THE FUTURE OF ENERGY GASES 

David G. Howell, Editor 

Associate editors: 

Katryn Wiese 

Michael Fanelli 

Laura Zink 

Frances Cole 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

An examination of the origin and distribution of natural 

gases and the economics and environmental effects 

of developing gas resources for energy 

UNITED STATES GOVERNMENT PRINTING OFFICE, WASHINGTON : 1993 
U.S. DEPARTMENT OF THE INTERIOR 

BRUCE BABBITT, Secretary 

U.S. GEOLOGICAL SURVEY 

Robert M. Hirsch, Acting Director 

For sale by U.S. Geological Survey 

Books and Open-Fil~ Reports 

Federal Center, Box 25286 

Denver, CO 80225 

Any usc of trade, product, or firm names in this publication is for descriptive purposes only and does 

not imply endorsement by the U.S. Government 

Project coordinated by Carolyn Donlin 

Text and illustrations edited by Carolyn Donlin, Helen Gibbons, and James W. Hendley II 

Book designed by Lisa Baserga, Linnea Larsen, and Carolyn Donlin 

Cover designed by Joe F. Vigil 

Library of Congress Cataloging in Publication Data 

The Future of energy gases I David G. Howell, editor ; associate editors, Katryn Wiese ... [et al.]. 

p. em. -(U.S. Geological Survey professional paper ; 1570) 

Based on papers presented at a conference held in Palo Alto, Calif., Oct. 1992. 

Includes bibliographical references. 

Supt. of Docs. no.: I 19:1570 

I. Gas as fuel-Congresses. 2. Hydrogen as fuel-Congresses. I. Howell, D.G. II. Series. 

TP345.AIF88 1993 

333.8'233-dc20 93-30188 

CIP 
PREFACE 

The ever-present concern of meeting U.S. energy needs led the Geological Survey in 1992 to initiate a series of 

publications that addresses the potential for an expanding role of energy gases to help sustain our domestic energy 

needs. This series is drawn from the Survey's own wealth of research as well as from academic, business, other 

government facilities, and private sources. We use the term "energy gases" to distinguish those natural gases, 

primarily methane, that have utility for energy purposes from the many other forms of natural gas. 

Recent discussions among economists, environmentalists, lobbyists, and scientific research groups within the energy 

industry have focused on the contributions of energy gases to the world's energy requirement. These discussions 

center around questions of gas supplies, assessing economic risk, future prices, and uncertainties of deliverability. 

What is often missing from these discussions, however, is a firm understanding of the fundamentals of energy gases: 

What are they? How do they form? Where are they found? How can they be exploited and at what costs? What are 

the environmental consequences associated with an expanded role of energy gases? 

Energy gases, particularly methane, are commonly associated with oil, and, indeed, huge supplies of methane have 

been found while exploring for oil. But only a small share of all methane is associated with oil and, importantly, 

methane forms in some settings totally independent of oil. Methane is found in association with coal; it is a 

byproduct of metabolic processes in microorganisms; it originates from great depths in the Earth's crust (it may even 

occur in the mantle); it occurs in the molecular lattice of ice in the Arctic and offshore areas below the sea floor; and 

it is often dissolved in water in large aquifers. Thus exploration efforts for gas are in many ways fundamentally 

different from exploration strategies for oil. Additionally, a variety of these settings contain truly enormous amounts 

of gas, but it is either dispersed throughout low-permeability horizons or concentrated in an ice lattice (hydrates); 

therefore, exploitation of these resources involves unique engineering problems rather than exploration uncertainties. 

To start the process of addressing these energy-gas issues, we organized a workshop in October of 1992 to which a 

spectrum of researchers was invited from government, universities, and the gas industry. Approximately 75 

specialists participated in discussions ranging from the origin of energy gases to how methane may provide a bridge 

to a hydrogen-based energy system in the future. This volume reflects the themes discussed at the workshop; it 

makes no attempt to offer new resource assessments because a variety of such studies already exists. Rather, its goal 

is to provide the fundamental information about energy gases, describe the attributes that make gas a beneficial fuel, 

provide ideas on how gas could be more fully integrated into an energy strategy, and explore the problems that may 

lie ahead if society shifts toward heavier use of energy gases. Woven throughout the volume are indications that a 

great deal is still unknown; these unknown factors may provide the focus for future research. 

Besides this volume, two additional companion products have been produced as follow-up products to the workshop. 

One is a 30-minute video entitled The Future of Energy Gases that is directed to nontechnical audiences and 

provides a general introduction to energy gases. The second is a pamphlet, also entitled The Future of Energy Gases 

(U.S. Geological Survey Circular II I 5 ), which provides a nontechnical summary of energy-gas issues with 

numerous illustrations. Together, the three products constitute a package offering a look at the topic of energy gases 

ranging from very general to highly technical. We would appreciate comments from readers, both in terms of the 

effectiveness of each piece as well as any suggestions for future products and research directions. 

And finally, we of the U.S. Geological Survey ad hoc Energy Gases committee must credit Gary Hill for challenging 

us to take on this project. Additionally, we would like to express our thanks and gratitude to the large cast of authors, 

editors, and production staffers whose collective effort allowed this volume to be conceived, written, and published 

in record time. Not included in the list of credits are Jim Pinkerton and Jeffrey Troll without whose confidence and 

guidance we could not have completed this volume. Special mention must go to Carolyn Donlin, the technical 

editing coordinator of the professional paper, whose patience, flexibility, and tenacity helped steer the 57 chapters 

through a rigorous and complicated review and production~schedule. 

Don Gautier, U.S. Geological Survey, MS 960, Federal Center, Box 25046, Denver, CO 80225 

(electronic mail address: gautier@bpgsvr.cr.usgs.gov) 

Robert Halley, U.S. Geological Survey, 600 4th Street South, Studebaker Bldg., St. Petersburg, FL 33701 

(electronic mail address: rhalley@wayback.er.usgs.gov) 

David Howell, U.S. Geological Survey, MS 902, 345 Middlefield Rd., Menlo Park, CA 94025 

(electronic mail address: dhowell@octopus.wr.usgs.gov) 

Jill McCarthy, U.S. Geological Survey, MS 999, 345 Middlefield Rd., Menlo Park, CA 94025 

(electronic mail address: mccarthy@octopus.wr.usgs.gov) 

David Scholl, U.S. Geological Survey, MS 999, 345 Middlefield Rd., Menlo Park, CA 94025 

(electronic mail address: dscholl@octopus.wr.usgs.gov) 

CONTENTS 

An Introduction to "The Future of Natural Gas" 

By David G. Howell, Frances Cole, Michael Fanelli, and Katryn Wiese -------------------------- 1 

ORIGINS OF ENERGY GASES 

Introduction to Microbial and Thermal Methane 

By Katryn Wiese and Keith A. K venvolden ------------------------------------------------------------ 13 

Stability and Flux of Methane in the Deep Crust-A Review 

By Robert C. Burruss--------------------------------------------------------------------------------------- 21 

Abiogenic Hydrocarbons and Mantle Helium in Oil and Gas Fields 

By Peter D. Jenden, David R. Hilton, Isaac R. Kaplan, and Harmon Craig----------------------- 31 

The Origin of Methane in the Crust of the Earth 

By Tho mas Go I d--------------------------------------------------------------------------------------------- 57 

Energy Gases of Abiogenic Origin in the Earth's Crust 

By John A. Apps and Peter C. van de Kamp ----------------------------------------------------------- 81 

Prospects for Commercial Abiogenic Gas Production: Implications from the 

Siljan Ring Area, Sweden 

By John R. Castano----------------------------------------------------------------------------------------- 133 

HABITATS OF GAS ACCUMULATION 

CONVENTIONAL GAS 

Conventional Gas Resources of the Gulf of Mexico Outer Continental ShelfPast Experience, Current Activities, Future Potential 

By Gary L. Lore--------------------------------------------------------------------------------------------- 157 

DEEP GAS 

Geologic Studies of Deep Natural-Gas Resources in the United States 

By T.S. Dyman, D.D. Rice, J.W. Schmoker, C.J. Wandrey, R.C. Burruss, R.A. Crovelli, 

G.L. Dolton, T.S. Hester, C.W. Keighin, J.G. Palacas, W.J. Perry, Jr., L.C. Price, 

C.W. Spencer, and D.K. Vaughan---------------------------------------------------------------------- 171 

Challenges of Ultradeep Drilling 

By Richard E. Wyman -------------------------------------------------------------------------------------- 205 

Empirical Observations Regarding Methane Deadlines in Deep Basins and 

Thrust Belts 

By David W. Houseknecht and Christoph Spot!-------------------------------------------------------- 217 

TIGHT GAS 

Gas in Tight Reservoirs-An Emerging Major Source of Energy 

By Ben E. Law and Charles W. Spencer ---------------------------------------------------------------- 233 

ORGANIC-RICH SHALES 

Autogenic Gas (Self Sourced) from Shales-An Example from the Appalachian Basin 

By Robert C. Milici ----------------------------------------------------------------------------------------- 25 3 

HYDRATES 

A Primer on Gas Hydrates 

By Keith A. K venvolden ------------------------------------------~------------------------~--------------- 279 

VII 
VIII 

HABITATS OF GAS ACCUMULATION-Continued 

HYDRATES-Continued 

Rock Physics for Characterization of Gas Hydrates 

By Jack Dvorkin and Amos Nur -------------------------------------------------------------------------- 293 

Natural Gas Production from Arctic Gas Hydrates 

By Timothy S. Co II ett ------------------- -----------------~-------:------------------------------------------ 2 99 

Gas Hydrates on the Atlantic Continental Margin of the United States-Controls 

on Concentration 

By William P. Dillon, Myung W. Lee, Kristen Fehlhaber, and Dwight F. Coleman-------------- 313 

Velocity and Amplitude Structures on Seismic-Reflection Profiles-Possible 

Massive Gas-Hydrate Deposits and Underlying Gas Accumulations in the 

Bering Sea Basin 

By David W. Scholl and Patrick E. Hart--------------------------------------~-------------------------- 331 

ACCREJ'IONARY PRISMS 

Generation, Migration, and Resource Potential for Hydrocarbons in Accretionary 

Subduction Systems-A Large, Unconventional Hydrocarbon Resource? 

By Andrew J. Stevenson------------------------------------------------------------------------------------ 3 53 

LANDFILLS 

An Energy Perspective on Landfill Gas 

By Peter J. Hutchinson ------------------------------------------------------------------------------------- 365 

DISSOLVED GASES 

A Survey of Natural Gas Dissolved in Brine 

By S u IIi van Marsden---------------------------------------------------------------------------------------- 3 8 3 

COALBEDS 

Coalbed Gas-An Undeveloped Resource 

By Dudley D. Rice, Ben E. Law, and Jerry L. Clayton----------------------------------------------- 389 

Coal as a Source Rock of Petroleum and Gas-A Comparison Between Natural 

and Artificial Maturation of the Almond Formation Coals, Greater Green River 

Basin in Wyoming 

By Mario Garcfa-Gonz{ilez, Donald B. MacGowan, and Ronald C. Surdam---------------------- 405 

GAS SEEPS 

Biochemistry of Natural Gases in Three Alkaline, Permanently Stratified 

(Meromictic) Lakes 

By Ronald S. Oremland and Laurence G. Miller------------------------------------------------------- 439 

A Comparison of Hydrocarbon Gases from Natural Sources in the Northwestern 

United States 

By Thomas D. Lorenson and Keith A. Kvenvoldcn --------------------------------------------------- 453 

Atmospheric Methane Flux from Coals-Preliminary Investigation of Coal 

Mines and Geologic Structures in the Black Warrior Basin, Alabama 

By Jerry L. Clayton, Joel S. Leventhal, Dudley D. Rice, Jack C. Pashin, Byard Mosher, 

and Peter Czepiel----------------------------------------------------------------------------------------- 4 71 
GAS-RESOURCE ESTIMATES 

U.S. Geological Survey Estimates of Natural-Gas Energy Resources 

By Gordon L. Dolton, Donald L. Gautier, Richard F. Mast, and David H. Root ----------------- 495 

National Petroleum Council Source and Supply Study-The Potential for 

Natural Gas in the United States 

By Donald L. Gautier and Robert L. Brown------------------------------------------------------------ 507 

Domestic Conventional Natural-Gas Reserves-Can They Be Increased by the 

Year 2010? 

By Thomas S. Ahlbrandt and David J. Taylor---------------------------------------------------------- 527 

A Primer in Field-Growth Estimation 

By David H. Root and Emil D. Attanasi----------------------------------------------------------------- 54 7 

Gas Hydrates as a Potential Energy Resource-A Review of Their Methane 

Content 

By Keith A. K venvolden ----------------------------------------------------------------------------------- 55 5 

Use of Seismic Data in Estimating the Amount of In-Situ Gas Hydrates in 

Deep Marine Sediment 

By Myung W. Lee, Deborah R. Hutchinson, William P. Dillon, John J. Miller, 

Warren F. Agena, and Barbara A. Swift-------------------------------------------------------------- 563 

Biogenic Gas: Controls, Habitats, and Resource Potential 

By Dudley D. Rice ------------------------------------------------------------------------------------------ 58 3 

World Resources of Natural Gas-A Discussion 

By Charles D. Masters -------------------------------------------------------------------------------------- 607 

THE ENVIRONMENT AND SOCIETY 

Environmental Consequences of Increased Natural-Gas Usage 

By Frances Cole --------------------------------------------------------------------------------------------- 619 

An Introduction to the Use of Natural Gas and Opportunities for Greater 

Consumption 

By Michael Fanelli ------------------------------------------------------------------------------------------ 6 3 5 

Methodology for Estimating Volumes of Flared and Vented Natural Gas 

By Timothy R. Klett and Donald L. Gautier------------------------------------------------------------ 651 

Energy Gases-The Methane Age and Beyond 

By Neboj sa N akicenovi c ----------------------------------------------------------------------------------- 661 

TECHNOLOGY 

Logistical Considerations for the Exploration and Production of Natural Gas 

By Russ D. Cunningham and Daniel R. Rowe--------------------------------------------------------- 677 

Overview of the U.S. Department of Energy/Morgantown Energy Technology 

Center Natural Gas Program 

By Abbie W. Layne ----------------------------------------------------------------------------------------- 685 

Alternative Development Strategies for Natural Gas 

By Emil D. Attanasi ----------------------------------------------------------------------------------------- 691 , 

Survey of Natural Helium Occurrences 

By Dennis W. Hinnah and John E. Hamak -------------------------------------------------------------- 703 

IX 
X 

TECHNOLOGY-Continued 

Methods of Gas Analysis 

By David E. Emerson--------------------------------------------------------------------------------------- 709 

Hydrogen: Its Comparison with Fossil Fuels and Its Potential as a Universal 

Fuel 

By T. Nejat Veziroglu and Frano Barbir ----------------------------------------------------------------- 715 

Hydrogen Storage Systems 

By James A. Schwarz and K.A.G. Amankwah --------------------------------------------------------- 725 

ECONOMICS 

HISTORY OF CONSUMPTION 

History of Natural-Gas Consumption in the United States 

By Michael F anel I i ------------------------------------------------------------------------------------------ 7 3 7 

MODELING 

An Economic Approach that Links Volumetric Estimates of Resources with Cost 

and Price Information 

By Dale M. Nesbitt------------------------------------------------------------------------------------------ 7 4 9 

Natural Gas-How Much, At What Cost? 

By Jairam S. Gopal and W. William Wood, Jr.--------------------------------------------------------- 787 

EXPLORERS' VISIONS 

Natural Gas and the Role of Competition in the United States 

By Keith E. Anderson--------------------------------------------------------------------------------------- 799 

Reflections After 62 Years of Exploration 

By Michel T. Halbouty ------------------------------------------------------------------------------------- 803 

New Thinking About Natural Gas 

By Robert A. Hefner III ------------------------------------------------------------------------------------ 807 

Natural-Gas Resources of North America 

By John A. Masters ----------------------------------------------------------------------------------------- 831 

The Future of Methane and How We Get There 

By Michael Roberts ----------------------------------------------------------------------------------------- 8 3 5 

THE FUTURE 

Sustainable Operation-Natural-Gas Contribution 

By Rex T. Ellington and Mark Meo ---------------------------------------------------------------------- 843 

The New Downstream: Increased End-Use Efficiency and Renewable Forms of 

Energy as Competitive Energy Resources 

By Evan Mills------------------------------------------------------------·----------------------------------- 84 9 

How Ultimate is Ultimate Gas Recovery? 

By Thomas J. Woods---------------------------------------------------------------------------------------- 8 69 

The Gas Gap: Uncertainty in the Supply of Natural Gas 

By David G. Howell, Katryn Wiese, and Jonathan Swinchatt --------------------------------------- 877 

Appendix -------------------------------------------------------------------------;:--------------- 885 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

An Introduction to "The Future of Natural Gas" 

By David G. Howell1

, Frances Cole2, Michael Fanelli3, and Katryn Wiese3 

CONTENTS 

Introduction .................................................................. . 

Origins of Energy Gases ............................................. . 

Energy Gas Resources . .. . .. . ... . .. .. . . . ... . . . ...... ... ... . .. .. . . .. . . . . . 3 · 

Natural Gas and the Environment ................................ 7 

Economic Benefits of Using Natural Gas .................... 8 

Natural Gas as a Bridge to Future Energy Systems ....... 9 

Economics of and Obstacles to Increased 

Natural-Gas Use ........................................................... 9 

Summary....................................................................... 10 

Acknowledgments ............................. :.......................... 10 

INTRODUCTION 

The earliest humans gained warmth and protection almost 500 millenia ago when they learned how to harness 

fire. Wood, dung, and animal fat were the sources of this 

energy. Over time these sources of energy have steadily 

evolved towards ever more efficient and cleaner forms: 

from biomass to coal to oil. That trend continues today with 

increased global use of natural gas, a fuel with environmental, economic, and political benefits. In the long term, during the 21st century, it seems likely that the trend will 

1

U.S. Geological Survey, MS 902, 345 Middlefield Rd., Menlo 

Park, CA 94025-3591. 2

U.S. Geological Survey, MS 955, 345 Middlefield Rd., Menlo 

Park, CA 94025-3591. 3

U.S. Geological Survey, MS 999, 345 Middlefield Rd., Menlo 

Park, CA 94025-3591. 

Manuscript approved for publication September 9, 1993. 

continue with the development of nonpolluting, renewable 

energy sources such as solar and various forms of nuclear 

energy. Before societies achieve this goal, however, it is 

likely that natural gas will increase its role in the energy 

mix. Nonetheless, a great deal of uncertainty and confusion 

surround the global supply of natural gas as well as the 

consumption of it. This professional paper addresses a 

breadth of issues regarding natural gas-how it forms, the 

environments in which it forms, how much remains, and 

the economics that affect these natural-gas issues. To continue the quest for a better understanding of the future of 

energy gases, all such issues must be explored. 

The information contained in this brief review is drawn 

exclusively from the chapters contained in this volume. Because a reference to each chapter was deemed cumbersome, 

readers are advised to peruse this volume for original 

source materials. 

ORIGINS OF ENERGY GASES 

Natural gas usually refers to methane, although small 

amounts of other hydrocarbon gases such as ethane, propane, and butane are also present in natural-gas mixtures. 

Methane is the simplest of the hydrocarbon moleculesone carbon surrounded by four hydrogen atoms-and it 

exists in variable concentrations throughout the Earth's atmosphere, water, and rock layers. 

Natural processes that form methane are divided into 

three types: biogenic (expelled gas from micro-organisms 

during the digestion of organic compounds), thermogenic 

(decomposition of organic matter by heat and pressure), 

and abiogenic (reactions of deep crustal gases with minerals or seepage of hydrogen- and carbon-rich primordial 

gases from the Earth's interior). Most of the methane that 

is extracted from the large natural-gas accumulations found 

in the Earth's crust is probably either biogenic or thermogenic in origin (fig. 1). The role of abiogenic methane in 

the formation of gas accumulations is a controversial issue. 
2 THE FUTURE OF ENERGY GASES 

DEPTH 

KM 

TEMP. 

oc 

_7::::::;;;;;:5:-=~=~~=f~t::F===~=r10 

100 

200 

300 

400 

500 

600 

700 

Figure 1. Schematic cross section of the Earth's crust, showing origin, migration, and accumulation of methane 

(CH4) . Origins of methane include conversion of organic material by micro-organisms (biogenesis), thermal 

decomposition of buried organic matter (thermogenesis), and deep crustal processes (abiogenesis). Buoyant 

methane migrates upward through rock pores and fractures and either accumulates under impermeable layers or 

eventually reaches the surface and dissipates into the atmosphere. 

Biogenic methane results from the decomposition of 

organic matter by methanogens, which are methane-producing micro-organisms and which pervade the near surface of the Earth's crust in regions devoid of oxygen, 

where temperatures do not exceed 9rc (20rF). Methanogens also Jive inside the intestines of most animals 

(people included) and in the cud of ruminants such as 

cows and sheep, where they aid in the digestion of vegetable matter. Because the methane generated in the subsurface is less dense than the rocks in which it is produced, it 

diffuses slowly upward through tiny, interconnected pore 

spaces and fractures, and it can eventually reach the 

Earth's surface and dissipate into the atmosphere. In places, however, the diffusion of methane is impeded by impermeable rock layers, and gas can become trapped in 

structures. If enough gas accumulates under these impermeable layers, the structures can be drilled and gas can be 

extracted for use as an energy source. 

Thermogenic methane is formed in a manner similar to 

oil. As organic particles deposited in mud and other sediment become deeply buried and compressed, higher temperatures cause carbon bonds in organic compounds to 

break down and form oil with minor amounts of gas. At 

increased temperatures (caused by increased burial depth), 

methane becomes the dominant product until it eventually 

replaces oil altogether. The simultaneous formation of both 

oil and gas in the early stage of the thermal decomposition 

process is the principal reason for the association of oil and 

gas in accumulations present in the upper 2 to 3 km of the 

Earth's crust. In deep parts of basins and possibly even in 

subduction zones methane may be the only hydrocarbon 

formed. 
AN INTRODUCTION TO "THE FUTURE OF NATURAL GAS" 3 

At greater burial depths, metamorphism may drive off 

all hydrogen atoms from organic compounds and leave a 

residue of carbon, often in the form of graphite. Under 

certain conditions in the deep crust, graphite may react 

with water; this reaction results in the recombining of carbon and hydrogen into methane. Recent studies on quartzvein systems indicate the presence of large fluxes of deep 

crustal gases and fluids; the volume of methane transported can be as large as 50 to 500 trillion cubic feet (Tcf) t 

for a single giant vein system. 

Abiogenic methane is formed by another process that 

involves nonorganic carbon- and hydrogen-rich gases, 

which exist deep within the Earth. They form as either 

primordial gases that seep from our planet's interior or as 

gases liberated from crustal rocks during metamorphism. 

As these gases migrate upward and interact with crustal 

minerals, they react to form the elements and compounds 

present in the atmosphere (nitrogen, oxygen, carbon dioxide, argon, and water). In volcanic regions today, there is a 

continual outgassing of carbon dioxide and water, which 

originated deep in the Earth. If these same gases were to 

migrate through rocks at high pressures, and in the absence of oxygen, methane would be the dominant stable 

compound. Perhaps methane is forming in this manner 

deep beneath the Earth's large continental regions where 

high pressure and low oxygen conditions prevail. 

Other planets and moons in our solar system have 

methane and other hydrocarbons as dominant elements in 

their atmospheres and surfaces. The ethane oceans and 

methane clouds of Titan and the methane ice on the surface of Pluto are examples. The theory that methane exists 

in the Earth's interior is generally accepted, but most geologists do not believe that methane migrating from deep 

within the Earth can or has formed economic accumulations. Questions of gas origin remain controversial and are 

important because they challenge the very foundations of 

our modern understanding. 

ENERGY GAS RESOURCES 

The role that natural gas will play in contributing to 

the world's primary energy requirements will depend ultimately on the availability and cost of sufficient supplies to 

meet a growing demand. Yet considerable uncertainty and 

disagreement prevails concerning the world's natural-gas 

resources. In fact, debates over fundamental issues such as 

the origin ·of natural gas and where to search for new, exploitable accumulations have caused many to wonder 

whether natural gas is a very well understood resource. 

t A Tcf of gas at the Earth's surface would occupy a space roughly 

2 miles long, 2 miles wide, and 2 miles high. This amount of gas would 

weigh 20 million tons. 

Commercial quantities of methane are present in many 

geologic environments and the modern era of exploration 

for natural gas has stimulated the development of new 

technologies and strategies that enhance and expand our 

capabilities of finding gas accumulations. The most common accumulations are generally associated with oil. In 

these subterranean traps, gas commonly forms a pocket 

between the denser oil below and the impermeable cap 

rock above. For oil production that is far from any naturalgas distribution system, gas produced in association with 

oil is often considered a nuisance. If it cannot be used as a 

fuel source for field operations, gas is sometimes vented or 

flared. For example, countries belonging to OPEC flared 

2. 9 Tcf in 1991, an amount which accounted for two-thirds 

of all recorded gas flared that year in the world. Nigeria 

flared 76 percent (0.8 Tcf) of its gas production in 1991. 

More commonly, however, especially iii the United States, 

excess gas is injected back into the well to help maintain 

the reservoir pressure, which aids the flow mid extraction 

of oil. 

Other natural-gas accumulations are termed unconventional. Unconventional resources are either more expensive to extract or require new technologies for extraction. 

For instance, where reservoir rock permeability is low, gas 

accumulations are referred to as tight gas. There may be 

large pore spaces to hold the gas, but there is little if any 

connection between pore spaces in these reservoirs; therefore, the flow of gas to the well bore is greatly restricted. 

Because the gas is highly disseminated and difficult to extract, its ultimate resource potential remains uncertain. 

Currently, some wells are drilled with a horizontal trajectory through the zones of tight gas to intersect "sweet 

spots," spatially restricted zones where natural fracture 

systems enhance the flow of gas. 

Coalbed gas is another unconventional resource. Coal 

is simply carbon-rich, woody terrestrial plant material that 

has been compressed and transformed. A byproduct of this 

transformation is methane. Synthetic gas can also be produced from coal as was the practice in the 18th, 19th, and 

early 20th centuries when "town gas" was used for street 

lighting. Liquid hydrocarbons can also be produced from 

coal, and since World War II a number of plants worldwide have been producing gasoline from this source. The 

presence of methane in coalbeds is one of the greatest 

dangers of underground coal mining-at high concentrations in mines, methane causes explosions. Historically, 

because canaries are very sensitive to minor concentrations of methane, they have been used as early warning 

indicators of dangerous methane build-ups in mines. By 

extracting coalbed gas prior to mining, the potential danger is reduced and an energy resource is gained. 

By the late 1970's, estimates of domestic natural-gas 

resources had become quite pessimistic: gas reserves were 

estimated to be 200 Tcf. At an average consumption rate 

of 20 Tcf/yr in the 1970's, the United States was assured 
4 THE FUTURE OF ENERGY GASES 

----of gas supplies for only 10 years. In 1978 regulations were 

passed restricting use of natural gas by industry and electric utilities. Proponents of this policy at that time believed 

that the Nation should not waste natural gas by producing 

electricity, because coal could produce electricity for less 

money. Since the late 1970's, U.S. natural-gas consumption has remained fairly constant. Consumption has ranged 

between 16 and 20 Tcf per year, and our reserves have 

also remained fairly constant because new discoveries 

have kept pace with depletions. 

The current wellhead and pipeline capacity of natural 

gas is more than adequate to deliver sufficient supplies to 

meet current U.S. demand. Most of the gas demand is met 

by production from domestic wells, but lately, pipeline-imported Canadian gas has provided as much as I 0 percent of 

total U.S. requirements for natural gas. Despite a current 

domestic gas-supply surplus, large reserves of natural gas 

in Canada are being developed, produced, and delivered to 

U.S. markets at lower prices than some of the domestic 

supply. As a result, those domestic gas supplies that have 

higher production costs remain undeveloped or shut in until 

gas-market prices increase to the point that production be390 

Ol 340 

c:: 

·u 

:J 

"C 

~ ll. 290 

0 

i 

.J:J 0 

E "C 

c:: :J :X 240 c:: :J "C 0 c:: E al 

:;.,. 

::.:::= 

... Cl 190 

:::E ~ 

~ 

"i 

~ 140 

i 

ll. 

c:: 

0 

~ 90 :J 

"C 

0 

rr. 

40 

"' 0 "' 0 "' ~ "' "' <0 <0 0> 0> 0> 

~ 

comes economic. With increasing levels of gas consumption in the United States, the current excess gas production 

and delivery capacity of domestic wells and pipeline imports will rapidly be absorbed. To establish and maintain 

higher levels of gas production and consumption, there is a 

need to either replace declining reserves by drilling new 

wells, or to substantially increase gas imports or both. 

The productivity of the average U.S. gas well has declined substantially over the past two decades. Of the 

world's 26,556 gas fields, 20,273 are domestic U.S. fields. 

Of these, nearly 19,000 are small fields, each with an ultimate yield ranging from 1 to 250 billion cubic feet (Bcf). 

Small fields are generally characterized by wells with low 

rates of production. In 1990, the average gas well produced only one-third the amount of gas as the average 

well in 1970 (fig. 2). Discoveries of gas fields with higher 

production rates, such as those found during the 1950's 

and 1960's in the Gulf of Mexico, have declined. Most of 

the new gas-field discoveri~s today are much smaller with 

lower rates of production. Much of the recent natural-gas 

exploration and development activity in the United States 

has focused on unconventional accumulations of gas; un20 

u 

!::. 

c:: 15 ~ ... 

:J 

"C 

0 

Q. 

.!! 

10 Oi 

Cl 

E 

0 

c 

0 

~ "' ~ "' 0 

:;; "' g: 0> "' 0> 

Figure 2. Number (in thousands) of producing natural-gas wells in the United States, the 

average annual rate of gas production per well (MMcf/yr is million cubic feet per year), 

and U.S. annual natural-gas production (in trillion cubic feet or Tcf) from 1945 to 

present. As average productivity of gas wells has declined from a peak in the early 

1970's, domestic gas production capacity has been maintained only by a dramatic increase in number of producing gas wells. Future production capacity is likewise dependent on adequate levels of exploration and development drilling activity to augment and 

replace declining production from aging, depleted, and abandoned wells. 
AN INTRODUCTION TO "THE FUTURE OF NATURAL GAS" 5 

conventional gas includes that associated with coalbeds, 

that in "tight" reservoirs, and that in shale beds. Wells tapping unconventional resources, however, commonly produce much smaller amounts of gas and at lower rates. 

Consequently, many more producing wells are needed to 

maintain the same level of gas production. The total number of producing gas wells in the United States has increased since 1970, from little more than II 0,000 gas 

wells in 1970 to more than 270,000 wells in 1991. 

For the current level of natural-gas production to be 

maintained or increased, exploration and development 

drilling must continue. In fact, the rate of drilling must 

increase significantly above current levels to replace the 

decline in productivity of the high-volume fields in the 

U.S. Gulf Coast. To maintain the current level of total 

U.S. gas-production capacity, the industry must return to 

the historically high levels of exploration and development 

activity of the late 1970's and early 1980's, a time when 

the price of gas was higher (fig. 3). A significant percentage of the gas drilling in recent years has been in coalbeds, tight reservoirs, and shale beds. Because most of this 

drilling has been done with the economic benefit of tax 

credits for developing these unconventional gas resources, 

the expiration of these credits on January 1, 1993, suggests that significantly fewer of these wells will be drilled 

in the future. Consequently, even more drilling for conventional gas reserves will be required not only to achieve 

higher domestic production but also to simply maintain 

the current level of production. 

The current low price of natural gas does not provide 

enough economic incentive for significant increased gas 

exploration and development activity. The increasing cost, 

difficulty, and risk of drilling wells in the Unites States 

under more stringent environmental regulations will con-

. tinue to reduce these activities. Furthermore, the industry 

may find it difficult to quickly return to the historically 

high levels of activity for several reasons. One reason is 

that over the past decade nearly half a million people have 

lost employment in the U.S. energy industries owing to 

greatly diminished levels of exploration, production, and 

marketing activities. Another reason is the fleet of available drilling rigs is considerably smaller now than during 

the height of activity during the late 1970's and early 

1980's. Many rigs have been permanently removed from 

service because they are now obsolete, they have been 

cannibalized for parts, or they were reduced to scrap. Additionally, large sums of capital would be required to fund 

more drilling and production activities. These resources 

may be difficult to secure owing to recent losses in similar 

investments. 

20000 ,---------~---------------------,- 3.00 

18000 

2.50 

16000 ~~ nght scale ... !II ... c 

0 14000 :; 

0.. 

E 12000 0 

left scale 

··.;e..:..:..:..: 

:::E 

~ 

2.00 N 

co 

01 

::::.. ... .. 'ii 

~ 10000 ..... 'o. .!:! 

1.50 ii 

.;, 

0) "' 

iii 8000 

I! !II 

«< 

0) 

'tJ :I 

c 

c 6000 <C 

«< 1.00 .. 

~ 

'i 

~ 

4000 

0.50 

2000 

0 0.00 

0 "' 0 "' ~ "' 0 "' 0 

"' "' ::: "' :;; "' "' "' "' "' "' "' "' ~ 

"' " "' 

Figure 3. U.S. annual gas-well completions and wellhead gas prices (in 1982 dollars per 

thousand cubic feet or Mcf) from 1945 to present. Historically, activities of natural-gas 

exploration and development companies has correlated closely to the wellhead price of 

natural gas. Because exploitation of natural-gas resources involves substantial capital investment over several years with significant risk, the market value of natural gas determines a company's economic incentive to undertake activities to find, produce, and 

market it. An extended period of stable prices would facilitate this process. 
6 THE FUTURE OF ENERGY GASES 

The interplay between supply, demand, and regulations 

has resulted in low wellhead prices for gas, which in turn 

negatively affects gas exploration. Nonetheless, new discoveries have been made. Current forecasts of the future 

endowment of domestic natural-gas resources suggest a 

U.S. supply of at least 900 Tcf, assuming that the price of 

gas will rise to $3.50 per thousand cubic feet (Mcf), twice 

the current cost. These new supply estimates would provide 

a 65-year supply at current consumption rates. But even 

this resource estimate may be low, because other unconventional sources of gas accumulation are being evaluated for 

their resource potential. These new sources potentially contain vast supplies, if only the technology necessary for extraction can be developed at low enough costs. Deep gas, 

located at depths greater than 4,000 m, represents one of 

the promising new sources. The petroleum industry has 

drilled more than 3 million wells in the United States in 

search of oil and some gas, but only about 16 thousand 

have probed depths greater than 4,000 meters. Methane remains stable to great depths whereas oil tends to concentrate in more shallow parts of the crust either because it has 

been displaced upward by the gas or because it breaks 

down at the higher temperatures found at depths greater 

than about 5 km. Additionally, with increasing pressures, 

gas compresses; the compression of gas results in more 

British thermal units (Btu's) per volume and, therefore, potentially enhances the desirability of deep exploration. 

Gas is also trapped in media other than rock. In shallow crustal horizons, enormous volumes of gas can be dissolved in brines. Although believed to be largely 

uneconomic, similar to the vast quantities of gold dissolved in sea water, local circumstances and ingenuity may 

result in such gas having limited resource potential. Gas 

trapped in the atomic lattice of ice is another unexplored, 

unconventional resource. These so-called hydrates look a 

lot like dry ice (frozen carbon dioxide), but hydrates will 

burn. In hydrates, the guest molecule of gas (which is 

methane 99 percent of the time) is housed within the crystalline structure of the ice, where it is packed at densities 

160 times greater than those at normal atmospheric pressures. Although huge quantities of gas exist in hydrate 

form, the commercial value of this gas is yet to be demonstrated, except for one commercial venture in northern 

Russia. Recent work suggests that over I 00 million Tcf of 

methane exists in gas hydrates worldwide with a potential 

resource of as much as 700,000 Tcf. This is roughly 10,000 

times larger than the global natural-gas consumption in 

1990, a truly immense quantity. Indeed there is great incentive to learn more about methane in gas hydrates and 

the technology required to exploit it. 

Recent global estimates of inferred recoverable resources are shown in figure 4. At recent ( 1990) world consumption rates of about 74 Tcf/yr, there is nearly a 125-year 

supply of natural gas. Whereas natural-gas resources appear 

Figure 4. Global natural-gas resource estimates and consumption rates for 1990. Major gas-producing basins are shown. Natural-gas resources 

are widely and plentifully distributed throughout the world. At current consumption rates, many countries have several decades, if not centuries, 

of estimated natural-gas resources. 
AN INTRODUCTION TO "THE FUTURE OF NATURAL GAS" 7 

to be abundant, it is only necessary to have sufficient supplies to provide the bridge to different fuels and energy 

systems of the future . Human beings have never fully exploited a resource, because the quest for cleaner, more convenient, and more efficient fuels has led to energy 

substitutions prior to resource exhaustion. It seems most 

pertinent to consider the advantages of switching now to a 

greater dependency on natural gas. 

NATURAL GAS AND THE 

ENVIRONMENT 

At present, roughly 90 percent of all energy consumed 

in the United States comes from the combustion of fossil 

fuels (fig. 5). The remainder comes from nuclear, hydro, 

ELECTRICITY GENERATION 

HOUSEHOLD/COMMERCIAL 

Figure 5. U.S. total energy consumption for 1991 by economic sector (left scale) and energy source (right scale). 

The Nation's largest share of energy is consumed during 

electricity generation, predominately by coal-fired steam 

plants. Transportation, the second largest energy-consuming sector, is very heavily dependent on gasoline, diesel, 

and small amounts of geothermal, wind, and solar power. 

Natural gas is the lightest of the fossil fuels; it contains 

only one carbon atom for every four hydrogen atoms. 

Upon combustion, the carbon-hydrogen bonds are broken, 

and heat is released in the process. The carbon combines 

with atmospheric oxygen to form C02, which is released 

into the atmosphere, while the hydrogen atoms combine 

with oxygen to form water vapor. Because of its lower 

carbon content, methane combustion produces roughly 

one-half the C02 emissions of coal, and about two-thirds 

as much C02 as oil, while delivering the same amount of 

thermal energy. 

Carbon dioxide and water vapor are the two most 

abundant of the greenhouse gases. These gases, which also 

include methane, ozone, nitrogen oxides, carbon monoxide 

and chlorofluorocarbons (CFC's), linger in the atmosphere 

NATURAL 

GAS 

HYDRO 

COAL 

35 

30 

-;j 

-

CD 

,... 

0 

,... 

-(/) 

0 

<( 

:::> 

0 

and aviation fuels which are refined from crude oil (petroleum); most petroleum products are currently imported 

from foreign countries. Technological developments, 

which lead to greater efficiency of energy consumption 

during electricity generation and transportation, will substantially mitigate the Nation's total energy requirement. 
8 THE FUTURE OF ENERGY GASES 

_____ where they can affect the temperature of the Earth's surface. Short-wavelength energy from the sun passes 

through the atmosphere and reaches the Earth, but the 

greenhouse gases prevent some of the longer wavelength 

reradiated energy from escaping back into space. By absorbing some of this outgoing radiation, the greenhouse 

effect keeps the planet warm and comfortable, at an average temperature of 14.5°C (58°F). Without the greenhouse 

effect, the average surface temperature would be a chilly 

-l8°C (0°F). Recent concern is over manmade changes in 

the composition and concentration of greenhouse gases 

that may cause overheating of the planet. 

Since the Industrial Revolution, the concentration of 

C02 in the atmosphere has increased by about 25 percent, 

largely because of increased input of C02 through burning 

fossil fuels. The impact of global warming on human society will not be sudden or disastrous, but it may cause 

some serious and expensive problems in places. Although 

the consequences are uncertain, the cure is clearly understood. To reduce the manmade contribution of greenhouse 

gases to the atmosphere, we must replace high-carbon 

fuels with low- or zero-carbon forms of energy. In this respect, natural gas is a large improvement over coal and 

oil. The ideal fuel, however, would contain zero carbon, 

such as pure hydrogen gas. Unfortunately, hydrogen is not 

present in nature in amounts large enough to extract and, 

therefore, it must be created synthetically. However, the 

cessation of fossil-fuel burning would not immediately affect the atmosphere. Because the residence time of C02 in 

the atmosphere is estimated to be several hundred years, 

reducing the C02 overload will be a very slow process. 

As mentioned above, methane is a potent greenhouse 

gas, roughly 25 times more potent than C02. In contrast to 

C02, however, it has a short residence time in the atmosphere. Methane remains in the atmosphere roughly ten 

years before it is oxidized and converted to C02 and water 

vapor. Like C02, atmospheric methane is increasing at an 

exponential rate. Its sources are poorly quantified, but 

roughly one-third is emitted from natural sources, such as 

wetlands, volcanic regions, termites, and decomposition of 

methane hydrates. Approximately two-thirds comes from 

manmade sources. Of the manmade sources, more than 

one-half comes from agricultural activities (rice paddies 

and cattle), and the remainder comes from oil and gas 

drilling, deliberate venting, pipeline leakage, biomass 

burning, and methane leakage from landfills. An increased 

dependence on natural-gas use will require more gas production, processing, and transportation infrastructure. This 

means the addition of more wells, tanks and pipelines 

from which methane can escape to the atmosphere. If 

methane is to endure as a relatively clean fuel, it is essential that these leakages are minimized. On the other hand, 

burning methane emits only C02 to the atmosphere, and 

does so in considerably less volumes than the other hydrocarbons. For example, burning one gallon of gasoline in 

an automobile produces 21 pounds (approximately 9.5 kg) 

of C02 exhaust, whereas the energy equivalent in natural 

gas (125 cubic feet or 3.54 m3) would produce 11 pounds 

(approximately 5 kg) of C02. As long as methane can be 

prevented from leaking into the atmosphere, using natural 

gas as a fuel source will be considerably more beneficial 

to the planet than using the other carbon-rich fuels. 

Another environmental concern associated with energy 

use is air pollution. Air pollution has short-term, localized 

effects compared to the global problems of the greenhouse 

effect. Because of its relative purity, methane combustion 

has the lowest emissions of all the hydrocarbon fuels; its 

combustion generates no particulates or associated trace 

metals and no S02. Nitrogen oxides and S02 produce additional environmental problems when they attach to water 

droplets and fall to the ground as acid rain and snow. A 

modern, high-technology gas-fired electricity plant generates one-fifteenth as much N02 as coal-fired electric plants 

and one-fifth as much as oil-fired electric plants; additionally, gas plants release no S02 or particulates. 

ECONOMIC BENEFITS OF USING 

NATURAL GAS 

The United States has a long history of being an international importer and exporter of energy products such as 

coal, oil, and gas. For several decades now the United 

States has been an exporter of surplus coal supplies, most 

of it destined for Canadian, European, and Japanese markets. At the same time, the United States has become an 

importer of oil and gas supplies. Most of the oil has come 

to us over the seas from many parts of the globe, most 

notably Nigeria, Mexico, and the Middle East, whereas 

nearly all of the gas imports have come through pipelines 

from Canada. Very small quantities of gas in liquefied 

form have been imported in tanker ships. In total, the 

United States is a net purchaser of very large quantities of 

imported energy supplies from foreign producers. In 1991, 

for example, the United States had a net energy trade deficit with other countries amounting to approximately $50 

billion, nearly 95 percent of which was for crude oil and 

other refined petroleum products. Many economists would 

argue that because of the decline of the domestic oil industry, the U.S. energy trade deficit is actually larger. 

An alternative national energy policy might be to encourage and support domestic energy resources, particularly 

natural gas. Support could include greater investment in 

research for exploration and development technologies, 

which will increase the availability of domestic supplies. It 

could also include research and investment in consumption 

technologies, which will improve the cleanliness and efficiency of energy consumption. Natural gas is a domestically 

available energy supply that, if utilized to its fullest potential, 

could reduce U.S. dependence on international energy trade. 
AN INTRODUCTION TO "THE FUTURE OF NATURAL GAS" 9 

NATURAL GAS AS A BRIDGE TO 

FUTURE ENERGY SYSTEMS 

Increased use of natural gas helps create the infrastructure necessary for the use of gaseous fuels. This infrastructure includes storage capability, pipelines and distribution 

facilities, and the advanced technology necessary to use 

gaseous fuels in homes, industries, electric utilities, airplanes and cars. Gaseous fuels hold the promise of being 

the fuel of the future, whether as a natural fuel source such 

as natural gas or as an energy carrier such as hydrogen. An 

energy carrier is a combustible, synthetic gas used to carry 

energy derived from an unusable or undesirable source to 

the consumer. In this case, hydrogen or methane gas can be 

formed from coal when coal is too polluting to use in its 

original form. Hydrogen can be formed from water using 

solar-generated electrical heat, thereby allowing the energy 

to be transported great distances by pipeline, which is more 

efficient than transportation by electricity. By increasing 

the use of natural gas today, we can begin to develop the 

infrastructure necessary to carry, store, and use gaseous 

fuels. This use paves the way to the ultimate conversion of 

our present liquid- and solid-based fuel system to a gaseous-based fuel system of the future. 

ECONOMICS OF AND OBSTACLES TO 

INCREASED NATURAL-GAS USE 

Electricity generation and transportation are the two 

largest uses of energy in the U.S. economy, consuming 37 

pen:;ent and 27 percent, respectively, of the Nation's 1990 

total energy requirement. As our population grows and 

spreads, the increased consumption of fuels for electricity 

generation and transportation is unavoidable, and technologies for this consumption will have to keep pace. 

For electricity generation, steam-driven turbines continue to be the predominant method of power generation. 

While steam-boilers have been fueled by coal, oil, and gas 

for decades, the percentage of steam generation by coal 

combustion has steadily increased to the point that coal 

now generates nearly 75 percent of the total steam produced. But, the forecasted growth in demand for electricity will require the construction of new generation capacity. 

Environmental regulations may increasingly restrict piant 

emissions, and electricity generators will need increased 

flexibility to meet seasonal, weekly, daily, and even hourly 

fluctuations in electricity demand. These conditions favor 

increased use of natural gas in electricity generation. 

The design and construction of gas-fired plants can be 

completed in half the time at less than half the cost of 

coal-fired plants. Gas-fired technologies are more efficient 

than coal-fired technologies, and, therefore, consume much 

less fuel per unit of electricity generated. As discussed 

previously, gas combustion generates far less pollution 

than coal. New gas-fired technologies, such as gas turbines 

and combined-cycle plants, are also much more flexible in 

their day-to-day operation; this flexibility allows utilities 

to respond much more easily to daily and hourly fluctuations in electricity demand. 

Additional savings in avoided costs can be realized by 

increased energy efficiencies. For example, lighting consumes 20 percent of all electricity. By simply replacing 

one 1 00-watt incandescent bulb with a compact fluorescent lamp, 75 percent less energy is used while the same 

amount and quality of light are delivered. For the lifetime 

of one compact fluorescent lamp, 10,000 hours, the savings is tantamount to 630 pounds (approximately 286 kg) 

of coal or a barrel of oil, or nearly 7,000 cubic feet (approximately 198 m3) of gas. Furthermore, a half ton of 

greenhouse gases would be averted. 

The transportation industry continues to be nearly exclusively dependent on crude-oil derivatives, principally 

motor gasoline as well as diesel and aircraft fuels. Extensive research has shown, however, that natural gas can 

perform very well as a motor vehicle fuel, while at the 

same time emitting roughly one half as much pollution 

from the tailpipe as normal gasoline-powered vehicles. At 

current prices, the fuel-cost-per-mile is far lower for vehicles using natural gas than for those using gasoline. Natural-gas powered vehicles are increasingly popular in 

countries all over the world, such as Canada, Italy, Russia, 

and New Zealand. In the United States they can be found 

primarily as public and private fleet vehicles in major metropolitan regions such as Los Angeles and New York City 

and are rapidly spreading to other urban areas (Houston, 

Fort Worth, and Austin, Texas). 

Energy and (or) carbon taxes are gaining interest here 

and abroad as means for generating revenue to mitigate 

externalities, which are costs to society as a consequence 

of using energy fuels. Examples of externalities include 

costs associated with air pollution, ground water contamination, acid rain damage to rivers, lakes, and forests, perhaps even military operations to protect foreign held 

resources. A carbon tax levies a tariff on a fuel in proportion to the amount of C02 it emits. Because C02 is a pollutant, and because other pollutants generally track with 

C02, a tax proportional to C02 targets the principal polluters. One idea for reducing C02 emissions is to establish 

national or per capita limits on pollution. These carbon/ 

pollution credits could be traded among countries. Underdeveloped countries could acquire revenues by polluting 

less and selling their excess pollution credits to developed 

countries. In developed countries, it would be cost effective to reduce the flux of pollution. All countries would 

benefit with such a system. More importantly, all countries 

would be doing their part to reduce C02 emissions. 

Because large regional disparities exist in the United 

States in relation to the types of energy that are available, a 

domestic carbon tax is believed by some to be unfair. For 
10 THE FUTURE OF ENERGY GASES 

________ example, the northwest has a large percentage of nonpolluting hydroelectric energy, whereas the central region depends on coal, and the east coast relies on oil for home 

heat An alternative is to implement some form of a Btu tax 

where all forms energy are taxed, regardless of the type. 

This scheme too will surely generate much debate-simple 

solutions to this complex problem are not clearly at hand. 

SUMMARY 

Though many are optimistic about the future supplies 

of natural gas, the numbers are still uncertain. Furthermore, 

a distinction must be made between resources in the ground 

and supplies available for immediate use. Resources can be 

estimated rigorously, but supplies have the most practical 

application. Our production supply of natural gas is currently running low, therefore development drilling must be 

increased. To find and develop our domestic energy gas 

resources, there has to be an increase in the number of 

exploratory wildcat and development wells. Because of the 

low price of gas, and the consequently small economic benefit to gas companies, the drilling of development and wildcat wells is decreasing. In 1980, about 17,000 development 

wells, and 700 wildcat wells were drilled in the United 

States. This brought the total number of gas-producing 

wells in the United States to 180,000. By 1991 that number 

had risen to 270,000. To support increased natural-gas use 

(>20 Tcf/yr), we will need even more producing wells; this 

increased use requires as many as 20,000 new development 

wells and more than 1,000 wildcat wells, per year. 

Solutions to these potential problems arc not obvious, 

and they are certainly not easy. We are left with a twocomponent dilemma: (I) Increased drilling will increase 

reserves, which would satisfy demand, but drilling will not 

increase significantly until the price goes up, and higher 

prices could diminish demand. (2) Natural gas is intended 

to reduce the effects of environmental damage due to fuel 

use, but to get adequate supplies of natural gas, numerous 

wells, many in environmentally sensitive areas, will have 

to be drilled. We must continue to do more research to 

improve exploration success, we must develop new production and consumption technologies, and, finally, we 

must look toward the future. But research must go handin-hand with action, for as AI Gore states in his book, 

Earth in the Balance, "* * * research in lieu of action is unconscionable. Those who argue that we should do nothing until we have completed a lot more research are trying to shift the burden of proof even as 

the r environmental] crisis deepens." 

Natural gas appears to be a good short-term solution 

to our society's energy needs. It is plentiful, clean, and 

good for the economy; it also provides a needed bridge to 

future energy systems. However, it is also plagued with a 

perception of uncertain supplies, which results in a lack of 

confidence in natural gas as a long-term, reliable fuel 

source. More research and more drilling should help to alleviate these concerns, and the results could be highly beneficial to our society and our environment 

ACKNOWLEDGMENTS 

This paper, and the entire volume, would not have been 

possible without the enthusiastic response of all the authors. Additionally, the motivation and support from Gary 

Hill and the guidance provided by Jim Pinkerton, Ken Bird, 

and Keith Kvenvolden ensured the timely completion of 

this volume. 
Methane, the dominant component of natural gas, forms 

through at least three different processes. One involves the 

breakdown of organic material during a thermogenic cracking process by which long-chained hydrocarbons, typically 

in solid or liquid form, dissociate at high temperatures and 

pressures to form short-chained hydrocarbons-butane, 

propane, ethane, and the shortest, methane. Continued 

heating (or cracking) may result in a pure carbon residue 

of graphite. This graphite residue forms deep in the Earth's 

crust. Under favorable conditions, this graphite can react 

with water to form more methane. That this has happened 

is evidenced by methane fluid inclusions in quartz-vein 

systems, which suggest large fluxes of methane-rich fluids 

from the deep crust. 

Methane also forms as a result of the metabolic processes 

of methanogens, bacteria-like microorganisms. These organisms commonly flourish in swamps, landfills, and in numerous places in the Earth's crust where temperatures are less 

than 97'C, oxygen is lacking, and an organic food source is 

present. Methanogens are also found in the intestines, cuds, 

and tooth plaque of several types of animals. 

This section also addresses the question of mantle-derived 

gases, sometimes called abiogenic gases. Mantle-derived 

gases are formed from carbon and hydrogen that were 

originally part of the primordial Earth. One report argues 

that most hydrocarbons in the Earth's crust are fundamentally inorganic and originate in the mantle. Evidence cited 

includes similarities in isotopic composition and chemical 

character of methane occurrences in large geographic areas 

that span long ranges of geologic time; additional evidence 

is the occurrence of methane elsewhere in the Solar System; 

where no known life forms exist. One report discusses how 

in 1986 the hypothesis of mantle-derived gas was tested by 

drilling a deep well into granitic basement in Sweden. No 

free gas was discovered, but trace amounts of both thermogenic and abiogenic natural gas dissolved in water were 

recovered. The hypothesis of abiogenic gas is challenged 

in other reports in which the chemistry of economic gas 

accumulations is evaluated to determine the origin of gas. 

The data presented suggest that all known economic gas 

accumulations, while potentially containing very small 

amounts of abiogenic gas, are dominantly organic and 

form through either thermogenic or biogenic processes. 

ORIGINS OF ENERGY GASES 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Introduction to Microbial and Thermal Methane 

By Katryn Wiese 1 and Keith A. Kvenvoldenl 

CONTENTS 

Abstract ......................................................................... 13 

Introduction ................................................................... 13 

Microbial Methane ..................... .................................. 14 

Microbiology and Ecology of Methanogens ......... 14 

Metabolism of Methanogens ................................. 15 

Methanogenic Environments ................................. 15 

Thermal Methane .................. ....... ........... ............. ......... 17 

Thermogenesis and Thermal Maturity of 

Source Rocks .............................................. ...... ..... 17 

Isotopic Composition of Thermal Methane .......... 18 

Molecular and Isotopic Compositions of Microbial 

and Thermal Gas . . . .. . . . . ..... .. .. . . . . .. . . . . .. . . .. . .. . ... . . .. . . .. . . . . . . ... 19 

Atmospheric Methane ... . . .. . . . . . . . .. . .. ... .. . . . . . . ... .. . . .. . . . . .. . . ... 19 

Summary....................................................................... 20 

References Cited ........................................................... 20 

ABSTRACT 

Commercially important accumulations of natural gas 

contain methane formed by two distinctly different processes. Microbial methane, produced biologically by methanogens, makes up roughly 20 percent of all known 

commercial gas accumulations, whereas thermal methane, 

generated during the thermochemical alteration of organic 

matter, accounts for the remaining 80 percent. Microbial 

and thermal methane can often be distinguished by isotopic and molecular ratios such as 613C, 6D, and methane/( ethane+propane) [C 1 /(C2+C3)]. 

1

U.S. Geological Survey, 345 Middlefield Rd. MS 999, Menlo Park, 

CA 94025. 

Microbial methane is produced in strictly anaerobic environments such as numerous aquatic environments, both 

marine and freshwater. Methanogens exist at surprising 

depths in the Earth's crust, at temperatures as high as 97°C. 

The primary metabolic processes by which methanogens 

gain energy are fermentation of acetate (CH3COO-) and 

reduction of C02. Other processes can occur depending 

upon the species of methanogen and the type of available 

organic matter (such as conversion of formate, methanol, 

methylamines, and methylated reduced sulfur compounds 

to methane), but in most cases these processes are not significant ones in nature. C02 reduction dominates in marine 

sediments, whereas acetate fermentation is most common 

in freshwater sediments. 

Thermal or thermogenic methane is formed as organicrich sediments move through progressively higher thermal 

maturity regimes found during increasing depths of burial. 

Thermal methane results from the thermochemical decomposition of organic matter. During early thermal maturation, 

thermal methane is accompanied by other hydrocarbon and 

non-hydrocarbon gases and is often associated with crude 

oil. At the highest thermal maturities, methane alone is 

formed by cracking of carbon-carbon bonds in kerogen, 

bitumen, and oils. 

INTRODUCTION 

Two major natural processes are known to form methane in amounts large enough for economic accumulations. 

These two processes are referred to throughout this paper 

as biogenic processes, because they both involve the decomposition of organic matter by either biochemical or 

thermochemical reactions. The process which is dominant 

in near-surface environments is microbial; in contrast, 

thermal methane generation takes place at greater depths 

where temperatures are sufficient to break chemical bonds 

13 
14 THE FUTURE OF ENERGY GASES 

----in organic matter. 'Fhe microbial process has been referred· 

to in the past as the biogenic process, whereas the term 

'thermogenic' implied a nonbiogenic process. This definition has been misleading, however, as thermogenesis 

involves organic matter whereas other non-biological processes of methane formation, termed abiogenic, do not. 

Abiogenic methane refers to methane which originates 

from carbon and hydrogen which were not tied up in organic materials and processes which involve no biologic 

assistance; the carbon and hydrogen instead may originate 

from primordial material deep in the Earth's crust or mantle, and the process of methane formation is simply one of 

chemical synthesis. For a more thorough discussion of 

abiogenic processes, see Jenden and others, Apps and van 

de Kamp, and Gold (this volume). 

Thermal and microbial methane both require organic 

compounds and, in the case of microbial methane, the assistance of microorganisms for their generation. Microbial 

methane is formed when numerous organic substrates (compounds undergoing biochemical conversion) are converted 

to methane during the metabolic processes of the methanogens, methane-producing microorganisms. Thermal methane 

is generated during the chemical decomposition of organic 

matter including long-chained hydrocarbons. This process 

produces shorter-chained hydrocarbons, among which methane is the dominant gaseous product. Both of these biogenic 

processes are well-studied and occur in different thermal 

regimes (fig. I; Rice, 1992), microbial in low-temperature, 

near-surface sediment accumulations and thermal in hightemperature, deeply buried sediments. The intent of this 

paper is to provide a basic summary of each process, to 

discuss differences between the methane formed from the 

two processes, and to distinguish between the two kinds of 

methane in naturally occurring gas accumulations; the paper 

is intended for nonspecialists who would find introductory 

material on natural-gas fonnation helpful. For more comprehensive information on petroleum gas generation, see 

Hunt (1979), Tis sot and Welte (1984 ), and Vi ally (1992). 

MICROBIAL METHANE 

MICROBIOLOGY AND ECOLOGY OF 

METHANOGENS 

Methanogens are methane-producing microorganisms 

that occupy a newly defined prokaryote group called archaebacteria. Eubacteria (also from the prokaryote group), 

eukaryotes, and archaebacteria make up the three evolutionary domains of life (Oremland, 1988; Konig, 1992; Stanier and others, 1986). Sixty-one species of methanogens 

have been discovered, making up three orders, seven families, and eighteen genera (Konig, 1992). Other microbes 

within the new kingdom of archaebacteria consist of extreme thermophilic microbes and sulfur metabolizers. 

1 

STAGE 

IMMATURE 

(diagenesis) 

MATURE 

(catagenesis) 

POST-MA TIJRE 

(metamorphism) 

PRIMARY 

PRODUCT 

DRY GAS 

OIL 

WET GASCONDENSATE 

DRY GAS 

HYDROCARBONS 

GENERATED ----t.,.~ 

Figure 1. Major stages during hydrocarbon generation as thermal 

maturity (time and temperature) of source rock increases. Microbial 

gas is generated at low temperatures and shallow depths. Thermogenic gas is generated throughout a large temperature and depth 

range; at the highest stages of thermogenesis the ratio of methane to 

higher alkanes and oil increases until dry gas is produced. 

Methanogens exist in a wide variety of strictly anaerobic environments (Cicerone and Oremland, 1988). Even a 

few parts per million (ppm) of oxygen is enough to kill 

them. In order to grow they feed on decomposed organic 

matter. These two requirements (no oxygen and plentiful 

organic substrates for energy) are usually found in environments such as freshwater and marine sediments, sewage sludge, flooded soils, animal gastrointestinal tracts, 

geothermal regions (such as hot springs or seafloor hydrothermal vents), and the heartwood of trees. Methanogens 

have also been found to survive conditions of hypersalinity and extreme pH. 

Other nutrient and growth requirements for methanogens have been described by Oremland ( 1988) and include 

availability of ammonium ions (NH4+) to satisfy the bulk 

of nitrogen requirements. Trace elements such as Co, Fe, 

Mo, Ni, Mg, and K, and the compound NaCI stimulate 

methanogenesis for some species, whereas a smaller number of species are stimulated by W and Sc. This stimulation 

is actually a result of the inhibition of competing processes. 

A narrow pH range is normally preferred, between 6 and 8, 

but some strains of methanogens are known to exist at pH 

ranges which are much higher and much lower. The dominant temperature range of- methanogenesis is from 4 to 

55°C, with the optimum temperature for the majority of 

methanogens around 35°C. One species, however, is known 
INTRODUCTION TO MICROBIAL AND THERMAL METHANE 15 

to exist at temperatures as high as 9rC. (Other species of 

archaebacteria, such as thermoacidophilic microorganisms, 

can exist at temperatures as high as ll0°C, but these species are not methane producing.) Inhibitors of methanogenesis include parts per million levels of oxygen, the presence 

of sulfite, ferrous ion (Fe3+), elemental sulfur, oxides of 

nitrogen, compounds with unsaturated carbon bonds, and 

the presence of nitrates and sulfates that channel the electron flow to microorganisms which are thermodynamically 

more efficient than methanogens. 

METABOLISM OF METHANOGENS 

Methane production is controlled by physical, chemical, 

and biological factors (Cicerone and Oremland, 1988). For 

each species of methanogen there is an optimal temperature 

range. As temperature trends toward this optimal range, production of methane will increase. Methane production is 

also dependent on the type and avaitability of decomposed 

organic matter. Substrates upon which methanogens can feed 

include hydrogen and carbon dioxide, formate, acetate, 

methanol, carbon monoxide, mcthylamines, and some methylated reduced-sulfur compounds (table 1). These substrates are produced as intermediate or end products of an 

intricate food web, beginning with complex organic biopolymers such as cellulose. Intermediary, nonmethanogenic, 

anaerobic bacteria break down these complex organics into 

the compounds which methanogens can use. 

The reduction of carbon dioxide by hydrogen and the 

fermentation of acetate are the two dominant methanogenic 

processes in nature. Nearly all methanogens (different species) are able to form methane through reduction of C02, 

and about half of the known species are able to use formate 

to create methane: The formate is actually converted first to 

C02 and H2 and then the reduction process takes over to 

produce methane (Marty, 1992). The other substrates described above are used by only a small fraction of the available species. In natural environments, however, the species 

which can cause reduction of C02 by hydrogen and fermentation of acetate are the dominant ones. 

The species of methanogen present and the metabolic 

process employed are dependent upon the conditions of the 

environment. Where large amounts of sulfate are present, 

sulfate-metabolizing microbes will dominate, and little to 

no methane will be produced. Where sulfate amounts are 

low, however, the conditions for proliferation of methanogens are more optimal, and methane generation will proceed at greater rates. Similarly, other important parameters 

for methanogenesis are optimal temperature range for the 

metabolic processes and availability of substrates as discussed in the previous section (Oremland, 1988). 

The processes of fermentation of acetate and reduction 

of C02 can be distinguished by comparing C'PC values and 

oD values of the produced methane (fig. 2). Methane from 

acefate fermentation is generally more depleted in deuterium and less depleted in 13C than methane formed through 

C02 reduction (Burke, 1992; Whiticar and other, 1986). 

This information can be used to characterize the type of 

environments in which each process is dominant as long as 

secondary fractionation does not occur or can be quantified 

(see "Molecular and Isotopic Compositions" section). 

METHANOGENIC ENVIRONMENTS 

Aquatic environments in which methanogens are found 

include freshwater (where fermentation of acetate is the 

dominant metabolic process) and sulfate-depleted marine 

sediments (where reduction of C02 is the dominant metabolic process), eutrophic lake sediments, salt marsh slurries, 

sediment slurries from estuarine muds, and anoxic water 

columns in meromictic (stratified) lakes (Oremland, 1988; 

Whiticar and other, 1986). In freshwater sediments, hydrogen and acetate are the important precursors to methane, with 

some of the produced methane coming from hydrogen reacting with C02 and the majority originating from acetate 

(fig. 3). In marine sediments, competition for acetate and 

hydrogen by sulfate reducers (when the sulfate ion concentration is high) makes methanogenesis highly dependent 

upon sulfate concentration (Marty, 1992) (fig. 3). When sulfate concentration is more than 1.0 millimolar, or the 

Table 1. Energy yields by important methanogenic substrates (modified from Oremland, 1988; Marty, 1992). 

[llG, gibbs free energy; kJ/mole, kilojoules per mole of methane] 

Methanogenic substrates 

carbonate-carbon dioxide 

formate 

methanol 

monomethy !amine 

acetate 

dimethylsufide 

Reaction 

4H2+C02-> CH4+2H20 

4HC00-+2H+_, CH4+C02+2HCOr 

4CH30H-> 3CH4+C02+2H20 

4CH3NH2+2H20+4H+ _, 3CH4+C02+NH4 + 

CH3COO-+H20-> CH4+HC0r 

(CH3hS+H20-> I.SCH4+0.5C02+H2S 

llG(kJ/mol) 

-139 

-127 

.:.103 

-102 

-28 

-74 

( 
16 THE FUTURE OF ENERGY GASES 

::; 

c_ 

-

_: 

--r 

c 

-

0 

'-0 

0 

-100 

-200 

-300 

-400 

MICROBIAL 

(Reduction) 

0 Biogenic 

• Ahiogcnic 

MICROBIAL 

(Fcnncntalion) 

-500 L-------~---------L--------L-------~---------L------~ 

-120 -100 -RO -60 -40 -20 0 

o 13C (ror Cl L:)). 111 r,·rmil 

Figure 2. Carbon isotope ratio (o 13C) versus hydrogen isotope ratio (OD) for microbially produced and thermogenically produced methane. Designated fields represent 

observed values resulting from fermentation and C02 reduction process, and thermogenically produced oil-associated and dry (nonassociated) gas (as labeled). Modified from Whiticar and others (1986). 

Figure 3. Flow diagram comparing methanogenesis pathways 

by acetate fermentation and C02 reduction in freshwater and 

marine sediments (modified from Whiticar and others, 1986). 

Dashed lines distinguish between regions where sulfate is 

present for reduction and where sulfate is absent. 

presence of nitrate or oxygen is high, little methane is found. 

Only after microorganisms have used up all free oxygen, 

nitrate, Mn and Fe oxides, and sulfate, will reduction of 

carbon dioxide take place and methane be produced. All of 

these inhibitors to methane production can be exhausted 

quickly at depths less than 2 meters, allowing for methane 

production and possible accumulation to begin below this 

depth (Whiticar and others, 1986 ). Methane from freshwater 

and marine sediments can be distinguished by isotopic values: o13C ranges from -110 to -60 permil and oD ranges 

from -250 to -170 permil (mean value of -192 permil) in 

marine sediments, whereas in fresh-water sediments methane has o13C values between -65 and -50 permil and oD 

values between --400 and -250 permil (mean value of -318 

permil). These different isotope values are due to different 

fractionation factors for the two processes (reduction versus 

fermentation) (fig. 2) and the different isotopic ratios of the 

substrates. 

Methanogens can be found in geothermal regions 

where their requirements for energy sources (decomposed 

organic matter) is no longer necessarily biologic. Geothermal H2 enters_hot springs, geological rift zones (such as 

Lake Kivu, Africa), and sea-floor hydrothermal vents 

where methanogens use the H2 to reduce the available 

C02 to produce CH4 (Oremland, 1988). Another near-surface environment in which methanogens are found, and 

microbial methane is produced, are landfills, where a richness in organic matter and a lack of oxygen makes meth-
INTRODUCTION TO MICROBIAL AND THERMAL METHANE 17 

ane production a large and important product. For more 

information, see Hutchinson (this volume). 

Relative to surface processes, little work has been 

done on subsurface (depths in the range from tens to hundreds of meters) methanogenic activity (Oremland, 1988). 

The active presence of methanogens at depth has been indicated, however, by direct observation of methanogens 

from material recovered during several Deep Sea Drilling 

Program (DSDP) projects, as well as from the isotopic 

values of known gas accumulations that indicate microbial 

activity. Methanogens have been recovered in deep aquifers in regions of Montana, Florida, and the Caspian Sea 

(Oremland, 1988). A necessity for methane production at 

depth in sediments is sufficient pore space for the methanogens to exist and grow (Rice, 1992). 

THERMAL METHANE 

THERMOGENESIS AND THERMAL MATURITY 

OF SOURCE ROCKS 

Organic matter in buried sediments can be converted 

to hydrocarbons through thermal decomposition. During 

sedimentation and burial, strata move through deeper, hotter environments, referred to as different thermal maturity 

regimes. Together with· the component of time, organic 

matter composed mainly of kerogen will decompose to 

form crude oil and other liquid and gaseous hydrocarbons 

such as those found in natural gas. Kerogen is the term 

used to identify the insoluble organic matter in rock. Kerogens can be divided into three types by their hydrogen/carbon (H/C) and oxygen/carbon (0/C) ratios, labeled I, II, 

and Ill in figure 4, as discussed by Tissot and Welte 

(1984). Type I and II kerogens (together called sapropelic) 

form oil and gas during decomposition, whereas type III 

kerogen (humic) dominantly produces gas, being least important of the three types for oil generation. These differentiations are primarily due to the available carbon and 

hydrogen in the organic matter. Type I kerogens have a 

high proportion of lipids, resulting either from selective 

accumulation of algal material, or from a severe biodegradation of the organic matter during deposition. Type II 

kerogens are usually related to marine sediments with a 

mixture of phytoplankton, zooplankton, and microorganisms and are deposited in reducing environments. Type III 

kerogen is derived mainly from continental plants. 

From the decomposition of kerogen, soluble organic 

matter (bitumen) is produced, and then crude oil. Gas is 

generated from kerogen, bitumen, and oil, throughout maturation of the sediments, though it dominates in the more 

mature sediments. Gas forms from decomposition of kerogen in the earliest stages, and then from cracking (thermal 

breaking of carbon-carbon bonds) of kerogen, bitumen, 

and oil in the later stages (Lewan, 1991, oral commun., 

.s 

~ ... 

u ·a 1.5 

0 

~ 

1.0 

0.5 

III 

0~----~----~----~--~~--~~--~~ 0 0.15 0.20 0.25 0.30 

-----------..- Atomic ratio 0/C 

Figure 4. Principle types and evolution paths of kerogen. Types 

I, II, and III are the dominant kerogen types. Evolution of kerogen composition with increasing burial is marked by an arrow 

along each evolution path. The different curves start with different H:O ratios according to original organic material and conditions of composition. The curves come together for very deep 

samples as the kerogen approaches I 00 percent carbon. Modified 

from Tissot and Welte (1984) and van Krevelen (1981). 

1993; Hunt, 1979). Oil forms mainly from type I and II 

kerogens, where the ratio of hydrogen to carbon is high 

enough to produce the liquid, heavy hydrocarbons. 

The amount and variety of hydrocarbon components 

generated is a function of the type of organic matter 

present in the source rock, and the time, temperatures, and 

pressures to which the source rock has been subjected. 

Figure 1 shows the changes in relative proportion of methane to oil and hydrocarbon gases as organic matter and 

source rocks are moved through progressively higher thermal maturity regimes. The proportion of liquid to gaseous 

hydrocarbons decreases, and the proportion of methane to 

the higher alkanes (C2+) increases as temperature increases. Thus in the later stages, methane is the dominant product and liquid hydrocarbons cease to be generated (fig. 1 ). 

Methane can form from the decomposition of oil, when 

it remains trapped in the sediments as they become more 

deeply buried and more thermally mature. Methane can 

also form from bitumen. Distinguishing between methane 

formed from decomposition of original source rock kerogen and that formed from thermal cracking of oil and bitumen is difficult (McCabe and others, in press). Because 13c 
18 THE FUTURE OF ENERGY GASES 

___ __ _ _ bonds are s_tronger than 12C bonds, however, methane formation from thermal cracking of carbon-carbon bonds produces lower 13C values in the methane (Tissot and Welte, 

1984). Because little oil or heavy hydrocarbons are generated from type Ill kerogens, there is less material available 

for cracking and methane formation. Even though methane 

is the dominant product of type III kerogens, the actual 

amount of methane produced from type III is less than the 

total amount formed from type I and II kerogens. 

When methane is found in association with oil, it is 

called associated gas; when found alone, independent of 

oil, it is termed nonassociated, or dry gas. Dry gas, predominantly methane (contains less than 0.1 percent of condensable liquids per 1,000 cubic feet of gas, Hunt, 1979), forms 

from microbial processes at shallow depths, or from thermal processes at high temperatures at great depth. As 

_ temperature increases during thermal maturation, each of 

the hydrocarbon species is formed during an optimal 

thermal window. For methane, optimum generation occurs 

at 150°C. Ethane, propane, and the butanes (C2+) have a 

lower optimal generation temperature, 120°C. This means 

that higher maturation regimes will produce fewer of the 

higher hydrocarbons and more methane (dry gas). 

Between 40 to 60 percent of the original organic 

matter in a sedimentary layer will be converted to hydrocarbons before reaching the final stage of thermal maturity-that is, the beginning of metamorphism (McCabe and 

others, in press). At this final stage (high temperatures and 

pressures) the organic material in the rock is converted to 

graphite (Burruss, this volume). Water remaining in the 

rocks, or coming from surrounding regions, can react with 

the graphite to form carbon dioxide and methane. These 

gases may then be liberated from the region through faults 

and fractures in the surrounding rocks, often evidenced 

through fluid inclusions in quartz vein systems (Burruss, 

this volume). This method of forming methane derives its 

carbon from a source which was originally organic (graphite). It is not in the strictest sense of this paper thermogenic, because instead of involving decomposition of complex 

organic matter, it involves a synthesis of carbon and hydrogen from simple compounds (carbon dioxide, pure carbon, and water) to form a simple hydrocarbon, methane. 

The amount of this kind of methane which is found in 

economic accumulations with thermogenic gas is believed 

to be negligible. 

The various or evolving stages of thermal maturation 

are labeled (I) diagenesis, the least thermally mature stage 

where microbial gas dominates, (2) catagenesis, the intermediate stage where oil and methane are generated from 

kerogen decomposition, and (3) metagenesis, the final 

stage where formation of almost pure methane (dry gas) 

occurs from thermal cracking of mainly oil and bitumen. 

The methane formed from cracking of kerogen at the 

highest thermal maturity stages is minor in comparison to 

the methane that comes from the cracking of bitumen and 

oil. At high thermal maturity most of the kerogen has already undergone cracking during earlier thermal stages. 

Similarly, the bitumen will begin to form oil at early stages and in the higher thermal maturity regimes will form 

only methane (Lewan, 1991, oral commun., 1993) 

ISOTOPIC COMPOSITION OF 

THERMAL METHANE 

Isotopic composition of thermal gases is dependent 

on three factors: (I) isotopic composition of source-rock 

organic carbon, (2) degree of fractionation during thermogenesis, and (3) degree of fractionation after methane formation. The first factor, source-rock isotopic composition, 

is dependent upon the kerogen type of the source rock and 

its degree of maturation. Isotopic fractionation during 

thermogenesis is a function of the differences in bonding 

energies for carbon-carbon bonds. The 13C-12C bond is 

stronger than the 12c-12c bond, and so the first-formed 

methane is preferentially enriched in 12C. As thermal maturation increases, so too does the 13C concentration (Faber 

and others, 1992). 

Fractionation after formation of methane is affected by 

the following: 

I. Isotopic equilibration between CH4 and C02. This 

process has been deemed unimportant, with isotopic effects too small to be significant (Fuex, 1977). 

2. Bacterial degradation (by methane-oxidizing microorganisms) which preferentially oxidizes 12C and thus enriches the residual methane in Be. 

3. Fractionation effects during migration. This process 

can affect the 13c;12C ratio of the residual product by increasing, decreasing, or leaving the ratio unchanged, depending upon the conditions of the system, whether closed 

or open, with or without mass loss. In steady-state systems 

(continual recharge and discharge of material), this fractionation is most likely not a major factor (Fuex, 1977). 

4. Time and migration of material can create an appearance of fractionation, as the earliest formed material 

(from a source with a certain o13C value) is channeled 

away first, while the last-formed material, having a different isotopic signature (due to previous preferential breaking of 12c- 12C bonds), migrates last. 

Thermal methane has a range of carbon isotopic values 

from -25 permil to -60 permil (Fuex, 1977; Schoell, 1988), 

though some authors place the maximum end of this range 

at -50 permil (Whiticar and others, 1986; Oremland, 1988). 

The lightest end of this range (most negative values) represents maximum fractionation of the lightest source material. This fractionation can be demonstrated by a source rock 

with organic carbon having o13c of approximately -30 permil that experiences a fractionation which decreases o13C 

by -30 permil, producing methane which has a o13C isotope signature of -60 permil. The heaviest end of the range 
INTRODUCTION TO MICROBIAL AND THERMAL METHANE 19 

of carbon isotope values for thermal methane (most positive values) represents minimum fractionation of the heaviest source material. This relation can be demonstrated by a 

source rock with organic carbon having o13C of approximately -19 permil that experiences a fractionation which 

decreases o13c by -6 permil, producing methane which has 

a o13C isotope signature of -25 permil (Fuex, 1977). 

MOLECULAR AND ISOTOPIC 

COMPOSITIONS OF MICROBIAL 

AND THERMAL GAS 

Microbially produced gas can be distinguished from 

thermogenically produced gas by use of stable isotope and 

methane/(ethane+propane) [C1/(C2+C3)] ratios (Bernard 

and others, 1976). Microbial methane is enriched in 12c, 

depleted in D, and contains only trace amounts of the 

higher alkanes: C 1/(C2+C3) ratios are typically > 1,000 (Cicerone and Oremland, 1988; Faber and others, 1992). Thermogenic methane, formed during catagenesis, is depleted in 

12C and has an abundance of higher alkanes (table 2), with 

values of C1/(C2+C3)<100. The reasons .behind these distinguishing characteristics are due to the different isotope 

fractionation factors and the different end-products of 

methanogenesis and thermogenesis. Methanogens cause enrichment of the lighter isotope during methanogenesis, producing values of o13c <-60 permil, whereas thermogenic 

values are typically >-60 permil (Fuex, 1977; Schoell,. 

1988) (fig. 5) or >-50 permil (Whiticar and others, 1986; 

Oremland, 1988). Values between -50 and -60 permil are 

often attributed to mixing of thermal and microbial methane. Late-stage thermal gases (formed during metagenesis) 

have lower hydrocarbon ratios because methane forms exclusive of the other hydrocarbon gases during the late maturation stage and have heavier isotopic signatures because 

the available organic matter is enriched in Be due to earlier 

fractionation which preferentially removed 12C. 

Important exceptions to the above description of microbial versus thermal gas exist; however, they are rare and do 

not characterize the majority of gas accumulations. One 

exception occurs when methane generation has ceased and 

the gas accumulation enters a regime where aerobic methane-oxidizing bacteria enter the methane-rich environment. 

These methane-oxidizing bacteria will destroy or oxidize a 

certain amount of methane but will also cause a fractionation resulting in the residual methane being isotopically 

heavier, because the oxidizing bacteria prefer light methane. This effect can usually be identified by comparison of 

methane o13c values with o13c values for other alkanes, 

such as ethane, which are not affected by these microorganisms (Faber and others, 1992). Also, in certain environments, such as meromictic lakes, anaerobic bacteria have 

similar fractionation effects, thereby shifting the isotope 

Table 2. Distinguishing characteristics of microbial and thermal methane (modified from Cicerone and Oremland, 1988). 

[C1• methane; c2, ethane; C3, propane] 

Source 

Microbial 

Thermogenic 

105 

104 

»100 

<100 

I>DC 1 (permil) 

<-60 

>>-50 

MICROBIAL 

<-150 

>-275 

'M 103 () 

+ 

C\J 

() 

's: 1 o2 () 

101 

100 

-20 -30 

' I 

,;,'/~~,~~············· :~ 

0 #: _; ______ _ ----- :P - : 

$' : 

A,..:f- I l 

-40 -50 -60 -70 -80 -90 -100 

o13C (for CH4), in permil 

Figure 5. Carbon isotope ratio (6 13C) versus C1/(C2+C3) for naturally occurring methane. Designated fields represent thermogenic and microbial methane and the corresponding mixing zones 

(as labeled). Modified from Bernard and others (1976). [C1, 

methane; C2, ethane; C3, propane] 

values to the heavy end such that a different origin is inferred than would otherwise be predicted. Finally, in certain 

rare circumstances, methanogens can form C2 (Cicerone 

and Oremland, 1988), which would skew the C1/(C2+C3) 

ratio. Fortunately, these secondary effects or exceptions are 

uncommon and can usually be identified. 

ATMOSPHERIC METHANE 

A significant amount of microbial gas is currently produced in surface and near-surface environments and often 

emitted to the atmosphere. Roughly 5x108 tons of biologically generated methane is emitted into the atmosphere 

each year (Cicerone and Oremland, 1988). Use of radiogenic carbon isotopes (

14C) indicates that 80 percent of this gas 

comes from recently formed microbial methane, originating 

from animals, rice paddies, termites, and landfills. The remaining 20 percent comes from methane older than the 

20 Ka age range of 14C, originating from the use of fossil 

fuels, and from the destabilization of methane hydrates (see 
20 THE FUTURE OF ENERGY GASES 

Kvenvolden, this volume). In contrast to atmospheric methane, only 20 percent of all known commercial gas accumulations are composed of microbial gas, whereas 80 percent 

are of thermogenic origin (Rice, 1992, this volume). 

SUMMARY 

Methane is produced in nature through two dominant 

processes, methanogenesis and thermogenesis. During 

methanogenesis the two dominant metabolic processes 

forming microbial methane are reduction of C02 and fermentation of acetate. These two processes are each dominant in a different depositional environment: reduction of 

C02 in marine settings and fermentation of acetate in the 

freshwater settings. Methanogens, the microorganisms 

which perform methanogenesis, are archaebacteria which 

live only in anaerobic, reducing environments and can survive a temperature range of 4 to 97°C. 

Thermal methane is formed as organic matter in buried 

sediments, is subjected to high temperatures, and undergoes 

decomposition. Typically this process involves generation 

of oil and other higher weight hydrocarbons as well as 

methane. In the late stages of thermogenesis, however, as 

temperatures increase above 120°C, methane becomes the 

dominant product, generated by thermal cracking of kerogen, bitumen, and oil. 

Thermal and microbial gas can be distinguished from 

one another through ()D and o13C isotope values for methane, as well as C1/(C2+C3) ratios of the gas. Thermal gas 

has o13C values (for methane) >-50 permil, ()D values (for 

methane) >-250 permil, and C1/(C2+C3) values <100. Microbial gas has o13c values (for methane) <-55 permil, 

bD values (for methane) <-150 permil, and C1/(C2+C3) 

ratios > 100. Commercial gas accumulations contain about 

20 percent microbial gas and 80 percent thermal gas. 

REFERENCES CITED 

Bernard, B.B., Brooks, J.M., and Sackett, W.M., 1976, Natural 

gas seepage in the Gulf of Mexico: Earth and Planetary Science Letters, v. 31, p. 45-54. 

Burke, R.A., Jr., 1992, Factors responsible for variations in stable 

isotope ratios of microbial methane from shallow aquatic 

sediments, in Vially, R., ed., Bacterial gas: Paris, Editions 

Technip, p. 47-62. 

Cicerone, R.J., and Oremland, R.S., 1988, Biogeochemical aspects of atmospheric methane: Global Biogeochemical Cycles, v. 2, no. 4, p. 299-327. 

Faber, E., Stahl, W.J., and Whiticar, M.J., 1992, Distinction of 

bacterial and thermogenic hydrocarbon gases, in Vially, R., 

ed., Bacterial gas: Paris, Editions Technip, p. 63-74. 

Fuex, A.N., 1977, The use of stable carbon isotopes in hydrocarbon exploration: Journal of Geochemical Exploration, v. 7, 

p. 155-188. 

Hunt, J.M., 1979, Petroleum geochemistry and geology: San 

Francisco, W.H. Freeman and Company, 617 p. 

Konig, H., 1992, Microbiology of methanogens, in Vially, R., 

ed., Bacterial gas: Paris, Editions Technip, p. 3-12. 

Lewan, M., 1991, Primary oil migration and expulsion as determined by hydrous pyrolysis, in Proceedings of the Thirteenth World Petroleum Congress: New York, John Wiley 

and Sons, p. 215-223. 

Marty, D.G., 1992, Ecology and metabolism of methanogens, in 

Vially, R., ed., Bacterial gas: Paris, Editions Technip, p. 13-

24. 

McCabe, P.J., Gautier, D.L., Lewan, M.D., and Turner, C., in 

press, Energy gases: U.S. Geological Survey Circular 1115. 

Oremland, R.S., 1988, Biogeochemistry of methanogenic bacteria, in Zehnder, A.J.B., ed., Biology of anaerobic microorganisms: New York, John Wiley and Sons, Inc., p. 641-705. 

Rice, D.D., 1992, Controls, habitat, and resource potential of ancient bacterial gas, in Vially, R., ed., Bacterial gas: Paris, 

Editions Technip, p. 91-118. 

Schoell, M., 1988, Multiple origins of methane in the Earth: 

Chemical Geology, v. 71, p. 1-10. 

Stanier, R.Y., Ingraham, J.L., Wheelis, M.L., and Painter, P.R., 

1986, The microbial world [4th ed.]: Englewood Cliffs, New 

Jersey, Prentice-Hall, 689 p. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and occurrence [2d ed.]: New York, Springer-Verlag, 699 p. 

Whiticar, M.J., Faber, E., and Schoell, M., 1986, Biogenic 

methane formation in marine and freshwater environments: 

C02 reduction vs. acetate fermentation-Isotope evidence: 

Geochimica and Cosmochimica Acta, v. 50, p. 693-709. 

van Krevelen, D.W., 1981, Coal-Typology, chemistry, physics, 

constitution: Amsterdam, Elsevier, 514 p. 

Vially, R., ed., 1992, Bacterial gas: Paris, Editions Technip, 

242p. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Stability and Flux of Methane in the Deep Crust-A Review 

By Robert C. Burruss 1 

CONTENTS 

Abstract ......................................................................... 21 

Introduction .... ... .... ........ ..... ............. ... .. . ........ .... .. ... ... .... 21 

Objectives .............................................................. 21 

Temperature, Pressure, and Fluids in the Crust: 

Metamorphic Facies ............................................... 22 

The Nature of Fluid Inclusion Observations ......... 23 

Basic Concepts ................................................ 23 

Time of Trapping .. .... .. .... .. .. ............ .... .. ..... 23 

Analysis of Composition and Density ...... 23 

Reliability . .... . ... ...................... ......... ............. ... 23 

Pressure and Temperature of Trapping ..... 23 

Diffusion of Water and Hydrogen ............. 23 

Stability of Methane in the Deep Crust ....................... 24 

Fluid Inclusion Observations ................................. 24 

Thermodynamic Modeling .................................... 24 

Evidence for Flux of Methane from the Deep Crustal 

Levels............................................................................ 25 

Giant Vein Systems and Mineralization ................ 25 

Metamorphic Fluid Circulation ............................. 25 

Does Crustal Methane Contribute to Resources?... 26 

Conclusions ................................................................... 27 

Suggestions for Future Research ........................... 27 

Acknowledgments ........................................................ 27 

References Cited ........................................................... 27 

ABSTRACT 

Empirical observations and theoretical calculations 

demonstrate that methane is stable in the crust to tempera1

U.S. Geological Survey, Branch of Petroleum Geology, Box 25046, 

MS 973, Denver, CO 80225. 

tures of 800°C and pressures of I 0 kbar or greater. These 

conditions are equivalent to depths of at least 35 to 40 km. 

Methane is most stable in metasedimentary crustal rocks that 

contain graphite. The concept of a "deadline" for methane 

is clearly irrelevant in graphitic metasediments. Based on 

the volume of fluid necessary to form quartz veins, the 

estimates of the possible flux of methane from depth in the 

crust are large, on the order of IO's to IOO's of Tcf (3 to 

30xi011 m3

) from single giant vein systems or from areas 

of focused flow in metamorphic terranes. Crustally generated methane can accumulate through phase separation and 

buoyant rise of a separate gas phase but may be accompanied by significant amounts of carbon dioxide and nitrogen. 

The estimated fluxes of methane needed for accumulation 

of natural gas resources are difficult to assess. Methane can 

be lost from crustal gases by oxidation in nongraphitic rocks 

at high temperatures. Methods are needed to chemically 

identify and ultimately quantify crustally generated methane 

accumulations that are accessible to drilling and production. 

INTRODUCTION 

OBJECTIVES 

Methane is stable and present at great depths (on the 

order of 30 km) in the crust. Recent studies demonstrate 

that there are significant fluxes (lO's to IOO's of trillion 

cubic feet (Tcf) or 3 to 30x 1011 m3) of fluids including 

methane from deep to shallower levels in the crust. This 

review identifies the geologic and geochemical constraints 

for the accumulation of natural gas resources from these 

fluxes and addresses whether these supplies are accessible 

to drilling and production. The evidence for the existence 

of these fluxes comes from recent advances in metamorphic petrology and the geochemistry of mineral deposits, 

with particular emphasis on the use of fluid inclusion 

21 
22 THE FUTURE OF ENERGY GASES 

observations to determine the compositiOn, temperature, 

and pressure of fluids in the crust. 

With the exception of a very small number of deep 

scientific drill holes, essentially all the direct information 

on fluids in the deep crust comes from observations of fluid 

inclusions in metamorphic and igneous rocks. Reviews of 

fluid inclusion observations and methods of analysis can be 

found in Hollister and Crawford (1981); Crawford and Hollister (1986); Roedder ( 1984) Most of the evidence for the 

presence of methane at deep crustal levels (1 0 to 35 km) 

comes from graphite-bearing metasedimentary rocks where 

reactions with graphitic carbon are the source for CH4 

(Burruss, 1977; Duke and Rumble, 1986; Hollister and 

Burruss, 1976). The source of the graphite in these 

metasedimentary rocks is the biogenic, carbonaceous detritus buried with the original sediments. Therefore, the methane generated from graphite in metasediments can be 

classified as an energy gas of organic origin. 

TEMPERATURE, PRESSURE, AND FLUIDS IN THE 

CRUST: METAMORPHIC FACIES 

Most of our knowledge of pressures (P), temperatures 

(T), and fluid compositions (X) in the crust comes from 

14 

I 

petrologic interpretations of mineral assemblages and thermodynamic models of mineral reactions. Some minerals 

have limited ranges of stability in P and T and their presence or absence defines the ranges of P and T experienced 

by a rock during burial, metamorphism, uplift, and exhumation. This concept of limited ranges of mineral stability 

is the basis for the general concept of metamorphic facies 

that in regional metamorphic terranes are generally known 

as greenschist, amphibolite, and granulite facies (P-T ranges are shown in fig. 1 ). Research over the last 15 to 20 

years in mineral analysis, thermodynamic modeling, stable 

isotope geochemistry, and radiogenic isotope geochronology has led to significant advances in our ability to define 

pressure, temperature, and time paths of metamorphic 

rocks that were once buried deeply in the crust. 

Our concepts of the composition of the fluid phase in 

metamorphic rocks are based on the requirements of thermodynamic equilibrium among mineral species. The coexisting fluid was initially assumed to be pure water in pelitic 

rocks and COTH20 mixtures in siliceous carbonate rocks. 

However, it was pointed out by French (1966) that when 

graphite is part of the mineral assemblage, other fluid species, such as CH4, CO, and H2 can be important components 

of the fluid. The discovery by Dolgov and others ( 1967) 

that COTbearing fluid inclusions are common in high-presL H 

El 

12 :11 Eclogite 44.4 120 

f!./ 

(/) Of 

a: 

<( 10 ~I QJ/ CD 

0 If Glaucophane- _J 0 . 

~ 8 .-::::- 1 Lawsonite 

z ,I, 

(EI 

w 

6 ~I 

a: .31 

::J I (/) 

(/) 

w 4 

a: 

a.. 

2 

100 200 300 400 

I 

I 

I 

I 

I 

I 

Amphibolite 

I 

I 

\ 

500 600 

(/) 

37.0 100 a: 

w 

Iw 

29.6 80 ~ 

0 

_J 

y: 

22.2 60 z 

- I 

I14.8 40 a.. 

w 

0 

7.4 20 

3.7 

1000 

TEMPERATURE, IN DEGREES CELSIUS 

Figure 1. Pressure-temperature diagram of metamorphic facies. Modified from Verhoogen and others 

(1970). Vertical pressure axis is shown as approximate depth in the crust on the right. Numbers labeled 

"L" on the inside of the axis are calculated on the basis of a lithostatic pressure gradient (270 barslkm) 

for an average crustal density of 2.7 g/cm3. Outer numbers labeled "H" are calculated on the basis of a 

hydrostatic pressure gradient (100 bars/km) for an average fluid density of 1.0 g/cm3. Measured pressure gradients in deep sedimentary basins change from hydrostatic to lithostatic in the depth range of 3 

to 10 km. 
STABILITY AND FLUX OF METHANE IN THE DEEP CRUST-A REVIEW 23 

sure, pelitic metasediments led to studies in a number of 

laboratories around the world of fluid inclusions in metasediments. These studies form the basis of this discussion. 

THE NATURE OF FLUID INCLUSION 

OBSERVATIONS 

BASIC CONCEPTS 

The basic principles of fluid inclusion studies are discussed in detail in Roedder (1984 ). The key to interpreting 

inclusion observations is to determine the time of trapping of 

the inclusions and then use the assumption that once the 

inclusions formed, they do not change volume or composition. This is also known as the assumption that inclusions "do 

not leak." The assumptions of constant volume and composition are critical for accurate interpretation of the PTX 

conditions of the fluid at the time of trapping. There are 

geologic processes that occasionally violate these assumptions. Failure to recognize such processes causes incorrect 

·interpretations of inclusion observations, but their recognition can lead to greater insight into the P-T history of samples. 

TIME OF TRAPPING 

Evidence for the time of trapping of fluid inclusions 

is based on the petrographic setting of the inclusions. Primary fluid inclusions form during mineral growth, most 

commonly along growth zones. Secondary inclusions are 

any inclusions that formed later than crystal growth, most 

commonly along healed microcracks that cross mineral 

grain boundaries. A subset of secondary inclusions called 

pseudosecondary inclusions form on healed microcracks 

that occur during crystal growth. In this case the microcrack terminates at a growth zone within the crystal, indicating that the fluid was trapped at some time during 

crystal growth, but not at a precisely identifiable stage of 

mineral growth. Although primary inclusions yield the 

least ambiguous evidence for the time of trapping, secondary inclusions can also yield useful information based 

on crosscutting relationships of fractures and microcracks 

(Cathelineau and others, 1990). 

ANALYSIS OF COMPOSITION AND DENSITY 

Determination of the pressure and temperature of formation (trapping) of fluid inclusions is based on analysis of 

both the composition and the density. of the fluid within the 

inclusion. The basic method involves observation of phase 

equilibria within inclusions with a microscope equipped 

with a heating and cooling (heating/freezing) stage. This is 

generally known as microthermometry. Procedures for 

making observations are discussed in Hollister and Crawford (1981) and Roedder (1984). The assumptions and 

basic methods of interpreting phase equilibria are discussed 

in Burruss ( 1981 a, 1981 b) a~d Van den Kerkhof ( 1988). 

There are a number of instrumental methods available 

for analyzing fluid inclusions such as mass spectrometry, 

gas chromatography, laser Raman microprobe spectroscopy, Fourier-transform infrared microscopy, and ion chromatography. Each method has limitations. The best analytical 

data result from a combination of techniques that include 

micro thermometry. 

RELIABILITY 

PRESSURE AND TEMPERATURE OF TRAPPING 

The soundness of any interpretation of fluid inclusion 

observations is based on the fundamental assumption that 

fluid inclusions do not leak or reequilibrate (in other words, 

once formed, they do not change volume or lose or gain 

fluid species). In general, this assumption is valid (Roedder, 

1984). There are, however, a number of well-defined processes that can cause reequilibration such as stretching or 

collapse (plastic deformation of the host mineral around the 

inclusion), decrepitation (brittle fracturing of the inclusion 

wall), and chemical diffusion. There is a growing body of 

evidence that these processes affect natural samples; however, in most cases they can be recognized. 

DIFFUSION OF WATER AND HYDROGEN 

Of the reequilibration processes, the one that has the 

most serious consequences for the occurrence of methane 

in fluid inclusions is diffusion of water and hydrogen 

through the host mineral. Quartz (Si02) is the most common host mineral for fluid inclusions in metamorphic 

rocks. Because quartz is an iron-free mineral, we do not 

have to be concerned about oxidation-reduction reactions 

involving iron (Fe2

+/Fe3+) that complicate the diffusion of 

hydrogen- and oxygen-bearing species through ferromagnesian host minerals like hornblende or olivine. Hydrogen 

diffusion can affect the amount of methane in fluid inclusions through the following reaction (Burruss, 1977; Hollister and Burruss, 1976): 

CH4+2H20=C02+4H2 (1) 

Diffusive loss of hydrogen can decrease the amount of 

methane as reaction 1 proceeds to the right. Methane 

could be completely lost from inclusions that have more 

than a 2:1 molar ratio of water to methane. Diffusive addition of hydrogen to an initially COz-rich inclusion could 

drive reaction I to the left and cause methane to be added 

to inclusions. Experimental and empirical evidence for 

both processes is discussed by Morgan and others (1993) 

and Hall and Bodnar (1990). 
24 THE FUTURE OF ENERGY GASES 

STABILITY OF METHANE IN THE 

DEEP CRUST 

FLUID INCLUSION OBSERVATIONS 

The methane content of fluid inclusions is determined 

by instrumental chemical analysis and by phase equilibrium 

observations (microthermometry). The results of the earliest 

attempts at instrumental analysis of methane in crustal rocks 

were fraught with ambiguity, owing to sampling problems 

(see review by Roedder, 1972). Some of the earliest reliable 

observations of methane in fluid inclusions from crustal 

environments were made by micro-thermometry (Mullis and 

others, 1973; Touret, 1971 ). Microthermometry was used to 

document the occurrence of methane in fluid inclusions from 

a granulite facies terrane (Hollister and Burruss, 1976). The 

identification of methane in fluid inclusions from deep crustal environments was confirmed by laser Raman microprobe 

spectroscopy of individual fluid inclusions (Dhame1incourt 

and others, 1979; Rosasco and others, 1975). 

The P-T ranges of methane-bearing fluids in a variety 

of crustal environments are shown in figure 2. The ranges 

of P and T for the individual metamorphic terranes and ore 

deposits are baseq on pressures and temperatures determined from fluid inclusions and from mineral equilibria. In 

other words, the methane-bearing fluids that are now 

trapped as inclusions were present in the crust at these P-T 

conditions. One common feature of all the occurrences of 

methane in the deep crust is the presence of graphite in the 

highest metamorphic grades and carbonaceous material or 

graphitic carbon at lower grades. On the basis of observed 

occurrences of methane, there is no upper temperature limit 

to the stability of methane in the crust in graphitic rocks. 

Evidence for an upper pressure limit or greatest depth 

of occurrence of methane is limited. Typical maximum 

pressure estimates for inclusions in granulite facies rocks 

are on the order of 10 kbar, or a depth of about 37 km, for a 

crust with an average density of 2.7 g!cm3. Inclusions are 

found in rocks from greater depths, as deep as 70 to 90 km, 

in eclogite facies rocks (Andersen and others, 1989; Selverstone and others, 1992), but to date the evidence for methane is very limited. COz-H20 fluids coexisting with saline 

brines and H20-N2 mixtures are documented (Andersen 

and others, 1989; Selverstone and others, 1992). References 

for the occurrence of CH4 in eclogitic fluids have been 

cited (Andersen and others, 1989), but the references are 

relatively obscure and difficult to confirm. 

THERMODYNAMIC MODELING 

The first attempts at thermodynamic modeling of equilibrium in metamorphic rocks required that the fluid either 

be pure H20 or H20-C02 mixtures. However, the presence 

of graphite in metasediments can lead to fluid compositions 

(/) 

a: 

-< co 

0 

_J 

:;;:: 

~ 

u.i 

a: 

~ 

(/) 

(/) 

w 

a: 

a.. 

10 

r8 f-

'-

6 -

-

4 rr2 rf0 

0 

r I l 

~ -

-

-

' r&~ 0 -

0 -

0 -

~ -

-

-

I I I I 

200 400 600 800 1000 

TEMPERATURE. IN DEGREES CELSIUS 

Figure 2. Pressure-temperature diagram of crustal conditions in 

which methane occurs as a stable component of fluid as observed 

in fluid inclusions. Numbered boxes refer to the pressure-temperature conditions discussed in the following publications: 8, Althaus and lstrate (1989); 4, Bastoul (1989); 3, Boiron and others 

(1990); 6, Cathelineau and others (1990); 7, Duke and others 

(1990); 11, Istrate and Althaus (1989); 2, Kisch and Van den 

Kerkhof (1991 ); 1, Mullis (1988); 5, Nwe and Morteani (1993); 

9, Poutiainen (1990); I 0, Whitney (1992). 

that are CH4 rich (French, 1966). The equilibrium compositions of C-0-H gases in the crust were calculated more than 

20 years earlier (French, 1966) than the recent attempts 

(Barker and Takach, 1991; Takach and others, 1987) to 

apply equilibrium thermodynamic calculations to gas compositions in deep sedimentary basins. One of the most thorough discussions of modeling gas compositions in graphitic 

rocks is the work of Ohmoto and Kerrick (1977). The fundamental reaction for generation of methane in graphitic 

rocks in the crust is 

(2) 

If we apply a thermodynamic constraint that the hydrogenoxygen (H:O) ratio is fixed at 2:1 (oxygen fugacity of the 

fluid is internally buffered), then this reaction describes 

the solubility of graphite in water and shows that methane 

and carbon dioxide will always occur in equimolar concentrations. The concentration of methane in the fluid as a 

function of P and T, to reaction (2), with H:O fixed at 2: 1 

is shown in figure 3. 

In many crustal rocks the concentration of methane is 

controlled by the oxidation state of iron in the rocks. In 

this situation the oxygen fugacity of the fluid is externally 

buffered by reactions such as 

(3) 

When oxygen is externally controlled by mineral reactions, the gas composition can vary widely through coupled reactions involving reaction (3) and reactions such as 
• 

STABILITY AND FLUX OF METHANE IN THE DEEP CRUST-A REVIEW 25 

(4) 

If the rock has a high oxygen fugacity, then methane is 

consumed and carbon dioxide becomes the dominant carbon-bearing species in the fluid phase. On the other hand, 

if the rock has a low oxygen fugacity, then carbon dioxide 

is consumed and the methane is the dominant carbon-bearing species in the fluid phase. 

EVIDENCE FOR FLUX OF METHANE 

FROM THE DEEP CRUSTAL LEVELS 

GIANT VEIN SYSTEMS AND MINERALIZATION 

The flux of gases in the deep crust can be estimated 

by determining the amount of water necessary to form 

quartz veins and then estimating the amount of gas that 

would be transported with the water. The measured solubility of quartz in water as a function of temperature, pressure, and salinity (Holland and Malinin, 1979) can be used 

8 

(/) 

c::: 

<( 

co 

0 

....J 6 

::z XcH ~ 

u..i ~ c::: 0.05 

=> 

(f) 

(/) 

UJ 4 

c::: 

a.. 

0 L---~---L----~---L----L---~--~ 

400 600 800 1000 

TEMPERATURE, IN DEGREES CELSIUS 

Figure 3. Pressure-temperature diagram of isopleths of methane 

content (XcH) of a C-0-H fluid in equilibrium with graphite 

with hydrogen-oxygen (H:O) ratio fixed at 2: I. Modified from 

Ohmoto and Kerrick ( 1977). 

to calculate the quantity of quartz precipitated per volume 

of water in a vein system at a given depth in the crust. 

From the volume of quartz veins that can be measured in 

the field, we can estimate the total volume of water necessary to form the vein system. The ratio of hydrocarbon 

and non-hydrocarbon gases to water can be determined 

from fluid inclusion measurements (Burruss, 1981 a; Landis and Hofstra, 1991; Van den Kerkhof, 1988). Therefore, 

we can estimate the volume of gases that are transported 

with the water that forms quartz veins at depth in a given 

tectonic setting. 

An extensive series of studies (Kerrich and Feng, 

1992) documented the geochemical processes and tectonic 

setting of formation of giant quartz-vein systems, which in 

many cases have associated gold mineralization (see Goldfarb and others, 1991). In one example of a giant vein system, an estimated 6xl018 g of aqueous fluid (6xl03 km3) 

deposited about 6x1015 g of quartz and in the process 

transported 3x1015 g of C02 (Kerrich and Feng, 1992). 

This is 1,500 trillion cubic feet (Tcf) of C02. On the basis 

of the range of methane-carbon dioxide ratios (1 :3 to 1 :40) 

observed in fluid inclusions in quartz from one of these 

giant vein systems, "southern Alaska mesothermal veins" 

(Landis and Hofstra, 1991 ), a single giant vein system 

may transport on the order of 50 to' 500 Tcf of CH4 to 

shallow crustal levels. The 12 giant vein systems that are 

documented (Kerrich and Feng, 1992) range in age and 

location from Archean (2,700-2,600 Ma) in the Canadian 

and Australian shields to Tertiary (38-27 Ma) in the European Alps. The number of these systems is biased by the 

fact that those documented are now exposed at the surface 

where they can be readily studied. 

METAMORPHIC FLUID CIRCULATION 

Evidence of and theoretical constraints on fluid flow 

during dynamo-thermal metamorphism of the crust have 

generated a significant volume of research and discussion 

in the last 15 years. A variety of issues is discussed in a 

recent, special issue of "Earth Science Reviews" (Fyfe, 

1992). J. Ferry is a major proponent of the flow of large 

volumes of fluid during metamorphism (Ferry, 1983). Recent work in the metamorphosed Waits River Formation 

along the Connecticut River valley, in the State of Vermont, has used reaction progress variables (Ferry, 1992) 

and stable isotope analysis of carbonate and silicate minerals (Stern and others, 1992) to calculate time-integrated 

fluid fluxes yield focused flows of 10 to >23x I 04 cm3

/cm2 

at crustal depths of about 25 km. Focused flow occurs in 

the crests of antiforms and around the margins of plutonic 

rocks. Calculated on a square-kilometer basis, these fluxes 

are lO to >23x1015 cm3/km2. Ferry (1992) and Stern and 

others (1992) indicate that the highest fluxes occur over 

areas >100 km2, which yield total fluid fluxes of similar 
26 THE FUTURE OF ENERGY GASES 

magnitude to Kerrich and Feng's (1992) estimates (as discussed above) for a single giant vein system. 

The volume of methane that may be part of the fluid 

flux calculated by Ferry and coworkers could be highly 

variable. Order of magnitude estimates are in the Tcf 

range calculated for Kerrich and Feng's (1992) giant vein 

systems. If the metamorphic rocks are graphitic, however, 

it is possible that the volume of methane could be high, on 

the order of 1 OO's of Tcf generated during focused flow 

through an area on the order of 100 km2. 

DOES CRUSTAL METHANE CONTRIBUTE 

TO RESOURCES? 

Although the evidence for the stability of methane in 

the deep crust is strong, questions still remain about the 

significance of the estimated fluxes for natural gas resources. In this case, I use the word resource in the 

conventional sense, meaning gas that is economically recoverable by present or near-future technology. In other 

words, does this methane accumulate in porous and permeable rocks accessible to drilling? The simple answer is 

that we do not know because we do not have good criteria 

to differentiate between deep crustal methane and normal 

thermogenic methane. However, there are three questions 

that should be addressed before we consider the problem 

of identifying deep crustal methane: ( 1) Can .methane generated in graphitic metasediments survive migration out of 

the source rock through non-graphitic rocks to shallow 

crustal levels? (2) Are there mechanisms that could concentrate the methane into a gas accumulation? And (3) 

what is the tectonic setting for high fluxes of deep crustal 

methane and is the area being studied favorable for the 

occurrence of reservoirs? 

Methane that is generated m graphitic metasediments 

can be consumed by two different types of reactions. In 

the first reaction, the methane can be oxidized by reactions 

with minerals that contain ferric iron. Reactions (3) and 

(4) discussed above can be combined as follows: 

Methane is consumed (oxidized) by the reduction of ferric 

iron in hematite to ferrous iron in magnetite. However, the 

stoichiometry of reaction 5 indicates that this mechanism 

for oxidizing methane is not very efficient because it requires 12 moles of hematite to reduce one mole of methane. 

If significant volumes of methane are concentrated along a 

flow path, then the oxidizing capacity of the rocks along the 

path may be rapidly exhausted, allowing methane to migrate. The second reaction that consumes methane is the 

reverse of reaction (2), the graphite solubility reaction. A 

methane and carbon dioxide mixture migrating to lower PT levels of the crust will precipitate graphite if thermodynamic equilibrium is maintained. There is petrographic and 

stable isotopic evidence for this reaction. Overgrowths of 

graphite on original metasedimentary graphite that are isotopically distinct from the host graphite (Duke and Rumble, 

1986) and intergrowths of graphite with retrograde, hydrous minerals (Duke and Rumble, 1986; Hollister and 

Burruss, 1976) demonstrate that this reaction occurs in the 

crust. The volume of methane that may be consumed by 

these two reactions is unknown. 

Methane in the deep crust occurs as mixtures with 

other components such as N2, COz, and H20. The total 

fluid composition may contain 10 to 20 mol percent CH4 

and in many cases as little as 1 to 5 mol percent. The 

methane can be concentrated from the aqueous fluid by 

phase separation (immiscibility). The critical curve for the 

CH4-H20 system is shown in figure 4 along with isopleths 

2.0 Two- (fJ phase a: 

<( field m 

0 

...J 1.5 ~ 

z 

u.i 

a: 

:::::> 1.0 (fJ 

(fJ 

w 

a: 

ll. 

0.5 

0 L-----~----_L ______ L_ ____ ...J_ ____ _...J 

277 327 377 427 477 527 

TEMPERATURE, IN DEGREES CELSIUS 

Figure 4. Pressure-temperature diagram showing the critical 

curve of CH4-H20 system (labeled 0 weight percent NaCI) and 

the calculated critical point curves for the CH4-H20-NaCI system 

at three different concentrations of NaCI (solid curves with hachures). Unhachured line is the critical curve for the H20-NaCI 

system with no CH4. At pressure-temperature (P-T) conditions to 

left of curves in the region labeled "two-phase field," separate 

liquid (H20 rich) and gas (CH4 rich) phases can exist. At higher 

P-T conditions on hachured sides of curves, methane is soluble 

in all proportions in pure water or brines of indicated NaCI content. As more NaCI is added to the system, the two-phase field 

expands to higher temperature. If an initially homogeneous fluid 

generated at P-T conditions on the hachured sides of curves migrates to shallower levels (lower P-T conditions on the left sides 

of curves), then it will separate into an H20-rich liquid and a 

CH4-rich gas. Gas can then migrate and accumulate by buoyancy. Modified from Krader and Franck (1987). 
STABILITY AND FLUX OF METHANE IN THE DEEP CRUST-A REVIEW 27 

for increasing salinity (Krader and Franck, 1987). As an 

initially homogeneous, water-rich fluid rises to shallower 

levels in the crust, CH4 and other gases will form a separate 

vapor phase at temperatures less than 400°C. The gas-rich 

vapor phase will rise buoyantly and separate from the aqueous phase. If this rising gas encounters an impermeable 

seal, it will accumulate. One difficulty with this mechanism 

is that it concentrates all gases that are immiscible in water. 

The methane will be accompanied by nitrogen and carbon 

dioxide, which will decrease the Btu content of the gas. 

Another factor in the possible contribution of deep 

crustal methane to natural gas accumulations is the tectonic 

setting in which crustal methane is generated. The examples of metamorphic terranes given above are all Barrovian, 

dynamo-thermal metamorphic terranes typically associated 

with continental plate collision. The giant vein systems described by Kerrich and Feng (1992) and others are typically 

associated with collisional regimes. Both terranes tend to 

have significant components of rapid, vertical tectonic 

movement that lead to rapid uplift and denudation that in 

turn would lead to reservoir leakage. One need only consider the European Alps or the Himalayas to realize that theprobability of preservation of major gas reservoirs in such 

terranes is relatively low. The possibility exists, however, 

that intermontane basins of collisional zones such as the 

Vienna or Pannonian basins of Europe might serve as traps 

for deeply generated, crustal gases. 

Whether or not one can identify sedimentary basins 

that are possible repositories of crustally generated methane, a crucial question that remains is how can we identify a crustal component of the gas? Only two methods 

appear to be available. One method is analysis of the stable isotopic composition, 613C (the variation in the abundance of 13C in parts per thousand) and 6D (the variation 

in the abundance of the hydrogen isotope deuterium (D) 

in parts per thousand) of the methane itself. A second 

possibility is analysis of the isotopic composition of the 

other major components of the gas, primarily nitrogen and 

carbon dioxide, and of the trace amounts of noble gases 

reservoired with the methane (see, for example, Ballentine 

and O'Nions, 1991). Once we know the geochemical criteria that uniquely identify crustally generated methane, 

then we can begin to assess the contribution of this source 

of energy gas to natural gas resources that are accessible 

to drilling. 

CONCLUSIONS 

I. On the basis of empirical observations and theoretical calculations, methane is stable in the crust to temperatures of 800°C and pressures of I 0 kbar or greater. These 

conditions are equivalent to depths of at least 35 to 40 km. 

The concept of a "deadline" for methane is clearly irrelevant in graphitic metasediments. 

2. Estimates of the possible flux of methane from depth 

in the crust are large, on the order of 10 's to 1 00' s of Tcf (3 to 

30xi011 m3) from single giant quartz-vein systems or from 

areas of focused flow in a Barrovian metamorphic terrane. 

Crustally generated methane can be concentrated through 

phase separation and buoyant rise of a separate gas phase. 

3. The significance of these estimated fluxes for natural gas resources is difficult to assess at this time. Methods 

are needed to identify the chemical and isotopic characteristics of crustally generated methane, Once these characteristics are identified, they can be used to estimate the 

fraction of crustally generated methane that is present in 

commercial reservoirs as has been done by Jenden and 

others (this volume) for abiogenic methane. 

SUGGESTIONS FOR FUTURE RESEARCH 

Several aspects of this review suggest areas for future 

research. First, we clearly need to carefully evaluate possible methods to identify crustally generated methane in 

sedimentary basin reservoirs. Second, detailed analysis of 

methane-bearing fluid inclusions in deep crustal rocks 

should provide insight into additional methods of addressing the first research area. In particular, stable isotopic 

studies of methane in fluid inclusions will document the 

range of values we can expect from this environment. 

Also, studies of the isotopic composition of noble gases in 

fluid inclusions should help identify the signature of gases 

generated at depth in the crust. 

ACKNOWLEDGMENTS 

My interest in this topic began during my dissertation 

research many years ago. L.S. Hollister's encouragement 

at Princeton University to pursue this research is still 

greatly appreciated. At Gulf Research and Development 

Co., T.J. Weisman's interest in deep methane ultimately 

led to my employment at that late, great research lab. Several colleagues at the U.S. Geological Survey, especially 

Dave Leach, Rich Goldfarb, and Mike Lewan have encouraged me to maintain my interest in this topic. To all 

of them and the many metamorphic petrologists currently 

pursuing fluid inclusion studies, I offer my thanks. This 

review would be impossible without them. 

REFERENCES CITED 

Althaus, E., and Istrate, G., 1989, Nitrogen-methane fluids in 

_granulite facies rocks from Valle Strona/Ivrea zone, W. Alps: 

Their bearing on the evaluation of P-T conditions of formation [abs.]: Berichte der Deutschen Mineralogische Gesselschaft, v. I, p. 7. 
28 THE FUTURE OF ENERGY GASES 

Andersen, T., Burke, E.A.J., and Austrheim, H., 1989, Nitrogenbearing, aqueous fluid inclusions in some eclogites from the 

Western Gneiss Region of the Norwegian Caledonides: 

Contributions to Mineralogy and Petrology, v. 103, p. 153-

165. 

Ballentine, C.J., and O'Nions, R.K., 1991, The nature of mantle 

neon contributions to Vienna Basin hydrocarbon reservoirs: 

Earth and Planetary Science Letters, v. 113, p. 553-567. 

Barker, C., and Takach, N.E., 1991, Prediction of natural gas 

compositiOn in ultradeep sandstone reservoirs: American 

Association of Petroleum Geologists Bulletin, v. 76, 

p. 1859-1873. 

Bastoul, A.M., 1989, The Tichka gold deposit, Morocco: Mineralogical and fluid inclusion data [abs.]: Terra Abstracts, v. 1, 

p. 24-25. 

Boiron, M.C., Cathelineau, M., Dubessy, J., and Bastoul, A.M., 

1990, Fluids in Hercynian Au veins from the French 

Variscan bel,t: Mineralogical Magazine, v. 54, p. 231-243. 

Burruss, R.C., 1977, Analysis of fluid inclusions in graphitic 

metamorphic rocks from Bryant Pond, Maine, and Khtada 

Lake, British Columbia-Thermodynamic basis and geologic interpretation of observed fluid compositions and molar 

volumes: Princeton University, unpublished Ph.D. dissertation thesis, 156 p. 

---1981 a, Analysis of fluid inclusions: Phase equilibria at 

constant volume: American Journal of Science, v. 281, 

p. 1104-1126. 

---1981b, Analysis of phase equilibria in C-0-H-S fluid inclusions, in Hollister, L.S., and Crawford, M.L., eds., Fluid 

inclusions: Applications to petrology: Calgary, Mineralogical Association of Canada, v. 6, p. 39-74. 

Cathelineau, M., Lespinasse, M., Bastoul, A.M., Bernard, C., 

and Leroy, J ., 1990, Fluid migration during contact metamorphism: the use of oriented fluid inclusion trails for a 

time/space reconstruction: Mineralogical Magazine, v. 54, 

p. 169-182. 

Crawford, M.L., and Hollister, L.S., 1986, Metamorphic fluids: 

the evidence from fluid inclusions, in Walther, J.V., and 

Wood, B.J., ed., Advances in Physical Geochemistry: 

Springer-Verlag, v. 5, p. 1-35. 

Dolgov, Y.A., Makagon, V.M., and Sobolov, V.W., 1967, Fluid 

inclusions in kyanite from metamorphic rocks and pegmatites of the Mama region (northeastern Transbaikel): Doklady Akademii Nauk S. S. S. R., v. 175, p. 164-166. 

Duke, E.F., Galbreath, K.C., and Trusty, K.J ., 1990, Fluid inclusion and carbon isotope studies of quartz-graphite veins, 

Black Hills, South Dakota, and Ruby Range, Montana: 

Geochimica et Cosmochimica Acta, v. 54, p. 683-698. 

Duke, E.F., and Rumble, D., III, 1986, Textural and isotopic 

variations in graphite from plutonic rocks, South-Central 

New Hampshire: Contributions to Mineralogy and Petrology, v. 93, p. 409-419. 

Ferry, J.M., 1983, Regional metamorphism of the Vassalboro 

Formation, south-central Maine, USA: a case study of the 

role of fluid in metamorphic petrogenesis: Journal of the 

Geological Society, London, v. 140, p. 551-576. 

---1992, Regional metamorphism of the Waits River Formation, Eastern Vermont: Delineation of a new type of 

giant metamorphic hydrothermal system: Journal of Petrology, v. 33, p. 45-94. 

French, B.M., 1966, Some implications of equilibrium between 

graphite and a C-H-0 gas phase at high temperatures and 

pressures: Reviews of Geophysics, v. 4, p. 223-253. 

Fyfe, W.S., ed., 1992, Metamorphic Fluids: Earth-Science Reviews, v. 32, 146 p. 

Goldfarb, R.J., Snee, L.W., Miller, L.D., and Newberry, R.J., 

1991, Rapid dewatering of the crust deduced from ages of 

mesothermal gold deposits: Nature, v. 354, p. 296-298. 

Hall, D.L., and Bodnar, R.J., 1990, Methane in fluid inclusions 

from granulites: A product of hydrogen diffusion?: 

Geochimica et Cosmochimica Acta, v. 54, p. 641-651. 

Holland, H.D., and Malinin, S.D., 1979, The solubility and 

occurrence of non-ore minerals, in Barnes, H.L., ed., Geochemistry of hydrothermal ore deposits: New York, John 

Wiley and Sons, p. 461-508. 

Hollister, L.S., and Burruss, R.C., 1976, Phase equilibria in fluid 

inclusions from the Khtada Lake metamorphic complex: 

Geochimica et Cosmochimica Acta, v. 40, p. 163-175. 

Hollister, L.S., and Crawford, M.L., ed., 1981, Fluid inclusions: 

Applications to petrology: Calgary, Mineralogical Association of Canada. 

Istrate, G., and Althaus, E., 1989, Methane and nitrogen in granulite facies rocks from the Sila Massif, Calabria, southern 

Italy: Neues Jahrbuch fuer Mineralogic, Monatschefte, 

v. 1989, p. 97-108. 

Kerrich, R., and Feng, R., 1992, Achean geodynamics and the 

Abitibi-Pontiac collision: implications for advection of fluids at transpressive collisional boundaries and the origin of 

giant quartz vein systems: Earth-Science Reviews, v. 32, p. 

33-60. 

Kisch, H.J., and Van den Kerkhof, A.M., 1991, CH4-rich inclusions form quartz veins in the Valley-and-Ridge province 

and the anthracite fields of the Pennsylvania Appalachians: 

American Mineralogist, v. 76, p. 230-240. 

Krader, T., and Franck, E.U., 1987, The ternary systems H20-

CH4-NaCl and H20-CH4-CaC12 to 800 K and 250 MPa: 

Berichte der Bunsen-Gesellschaft fuer Physikalische Chemic, v. 91, p. 627-634. 

Landis, G.P., and Hofstra, A.H., 1991, Fluid inclusion gas chemistry as a potential minerals exploration tool: Case studies 

from Creede, CO, Jerritt Canyon, NV, Coeur d'Alene district, ID and MT, southern Alaska mesothermal veins, and 

mid-continent MVT's: Journal of Geochemical Exploration, 

v. 42, p. 25-59. 

Morgan, G.B., Chou, 1.-M., Pasteris, J.D., and Olsen, S.N., 

1993, Re-equilibration of C02 fluid inclusions at controlled 

hydrogen fugacities: Journal of Metamorphic Geology, 

v. 11, p. 155-164. 

Mullis, J., 1988, Rapid subsidence and upthrusting in the Northern Apennines, deduced by fluid inclusion studies in quartz 

crystals from Porretta Terme: Schweizerische Mineralogische und Petrographische Mitteilungen, v. 68, p. 157-170. 

Mullis, J., Poty, B., and Leroy, J., 1973, Nouvelles observations 

sur les inclusions a methane des quartz du Val d'Illiez: 

Compte Rendus, v. 277, p. 813-816. 

Nwe, Y.Y., and Morteani, G., 1993, Fluid evolution in the H20-

CH4-COrNaCI system during emerald mineralization at 

Gravelotte, Murchison Greenstone Belt, Norhtest Transvaal, 

South Africa: Geochimica et Cosmochimica Acta, v. 57, 

p. 89-103. 
STABILITY AND FLUX OF METHANE IN THE DEEP CRUST-A REVIEW 29 

Ohmoto, H., and Kerrick, D., 1977, Devolatilization equilibria in 

graphitic systems: American Journal of Science, v. 227, 

p. 1013-1044. 

Poutiainen, M., 1990, Evolution of a metamorphic fluid during 

progressive metamorphism in the Joroinen-Sulkava area, 

southeastern Finland, as indicated by fluid inclusions: Mineralogical Magazine, v. 54, p. 207-218. 

Roedder, E., 1984, Fluid Inclusions, in Ribbe, P.H., ed., Reviews 

in mineralogy: Mineralogical Society of America, v. 12, 

p. 644. 

Selverstone, J., Franz, G., Thomas, S., and Getty, S., 1992, Fluid 

variability in 2 GPa eclogites as an indicator of fluid behavior during subduction: Contributions to Mineralogy and Petrology, v. 112, p. 341-357. 

Stern, L.A., Chamberlain, C.P., Barnett, D.E., and Ferry, J.M., 

1992, Stable isotope evidence for regional-scale fluid migration in a Barrovian metamorphic terrane, Vermont, USA: Contributions to Mineralogy and Petrology, v. 112, p. 475-489. 

Takach, N.E., Barker, C., and Kemp, M.K., 1987, Stability of 

natural gas in the deep subsurface: Thermodynamic calculation of equilibrium compositions: American Association of 

Petroleum Geologists Bulletin, v. 71, p. 322-333. 

Touret, J., 1971, Le facies granulite en Norvege Meridionale II. 

Les inclusions fluides: Lithos, v. 4, no. 423-436. 

Van den Kerkhof, A.M., 1988, The system C02-CH4-N2 in fluid 

inclusions: Theoretical modelling and geological applications: Free University Amsterdam, unpublished Ph.D. thesis. 

Verhoogen, J., Turner, F.J., Weiss, L.E., Wahrhaftig, C., and Fyfe, 

W.S., 1970, The Earth: An introduction to physical geology: 

New York, Holt, Rinehart and Winston, Inc. 

Vrolijk, P., 1987, Tectonically driven fluid flow in the Kodiak 

accretionary complex, Alaska: Geology, v. 15, p. 466-469. 

Whitney, D.L., 1992, Origin of COTrich fluid inclusions in leucosomes from the Skagit migmatites, North Cascades, Washington, USA: Journal of Metamorphic Geology, v. 10, 

p. 715-725 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Abiogenic Hydrocarbons and 

Mantle Helium in Oil and Gas Fields 

By Peter D. Jenden1

•

2, David R. Hilton3.4, Isaac R. Kaplan1

, and Harmon Craig3 

CONTENTS 

Abstract ... . . .. .. .. . ... . . .. ... ... .. . . . ....... ..... ..... .. .. . . .. .. .. .. ... .. . ... . . . 31 

Introduction ................................................................... 32 

Methane in the Mantle? ......................................... 32 

Samples and Analytical Techniques ............................. 33 

Recognizing Mantle-Derived Hydrocarbons in the 

Crust.............................................................................. 36 

Carbon Isotope Distribution in Methane ............... 36 

Carbon isotope Variations Among the 

C1 to C4 Hydrocarbons .......................................... 38 

Helium Isotope Ratios in Commercial Gases ...... 40 

Methane Concentration and Helium-3 Abundance ...... 42 

Methane o 13c and Helium-3 Abundance ................... .. 46 

Nonhydrocarbon Gases ................................................ 49 

Concluding Remarks .................................................... 50 

Acknowledgments ........................................................ 51 

References Cited .. . .. .. . . . ... ... .. . . .. ... .. .. .. .. ... . . . ... . . .. .. . . . . . . . ... . 51 

ABSTRACT 

Most carbon degassed from Earth's interior is released 

as volcanic and hydrothermal carbon dioxide along oceanic spreading ridges and as volcanic and geothermal carbon 

1

Giobal Geochemistry Corporation, 6919 Eton Ave., Canoga Park, 

CA 90604. 

2

Current address: Chevron Petroleum Technology Company, P.O. 

Box 446, La Habra. CA 90633. 3Scripps Institution of Oceanography, University of California, San 

Diego, La Jolla, CA 92093. 4

Current address: Free University of Berlin, FB 24, WEI FR 

Geochemie, 1000 Berlin, Germany. 

dioxide in continental regions. The chemistry of the 

earth's interior is poorly understood, however, and methane, rather than carbon dioxide, may be the dominant form 

of carbon throughout much of the mantle. According to 

one hypothesis (see Gold, this volume), methane from the 

mantle is continuously injected into the deep crust at lithospheric plate boundaries, ancient suture zones, and other 

areas of crustal weakness such as large meteorite impact 

sites. Where introduced beneath sedimentary basins this 

methane could accumulate in the conventional structural 

and stratigraphic traps in which we find petroleum. Geochemical evidence strongly argues that crude oil is of sedimentary (biogenic) origin, but the origins of natural gas 

are more complex and the proportion that may be derived 

from mantle (that is, abiogenic) sources is unknown. 

Three specific analytical criteria have been used to help 

identify mantle-derived hydrocarbons in oil and gas fields: 

(1) methane o13c > -25 perrnil, heavier (more positive) than 

o13c of methane derived 'from sedimentary organic carbon 

and more characteristic of known abiogenic methane occurrences; (2) "isotopic reversals" of the form methane &13C > 

ethane &13C >propane &13C, which are consistent with methane polymerization rather than hydrocarbon cracking; and 

(3) 3He/~e>O.l RA (RA=atmospheric ratio), possibly indicative of the presence of mantle-derived helium. Only 2.4 

percent of the 1, 700 commercial gases for which data have 

been assembled meet the first criterion. The small number 

of isotopic reversals that are present (second criterion) can 

be explained in many instances by mixing and oxidation of 

"isotopically normal" biogenic gases (methane o13c < 

ethane o13c <propane o13C) or by generation from isotopically heterogeneous organic matter. More than half of the 

340 commercial gases for which 3HefHe ratios are available meet the third criterion, however, and the proportion of 

helium in these gases originating in the upper mantle ranges 

from undetectable to nearly 100 percent. 

31 
32 THE FUTURE OF ENERGY GASES 

Using a geometric mean of 3xl06 for the molar CH4/

3

He 

ratio in uncontaminated, mantle-derived fluids from spreading ridges, mantle plumes and summit fumaroles of arc 

volcanoes (Welhan and Craig, 1983), the median abiogenic 

methane content of commercial gases is estimated to be less 

than 200 ppm by volume (range=O to 12,000 ppm). While 

admittedly a rough estimate, this calculation suggests that 

little confidence should be placed in the resource potential 

of abiogenic natural gas. In rift or convergent margin basins, 

hot magmatic fluids can strip methane and other volatiles 

from metamorphic basement and overlying sedimentary 

rocks, however, and commercial accumulations of this type 

of gas may be present (see Burruss, this volume). The economic value of such reserves could be impaired by dilution 

with carbon dioxide and possibly nitrogen. 

INTRODUCTION 

Inorganic, or "abiogenic," hypotheses for the origin of 

crude oil and natural gas can be traced back at least to the 

early 19th century when associations were first noted between mud volcanoes, petroleum seeps and igneous activity (see review by Dott and Reynolds, 1969, p. 15-45). In 

the late 19th century, M. Berthelot suggested that petroleum might originate by the reaction of deep-seated alkali 

metal with recycled crustal carbon dioxide. Shortly afterwards, Dmitri Mendeleeff proposed his famous hypothesis 

that oil and gas are generated by the hydration of iron carbides (Dott and Reynolds, 1969). A highly detailed modern version of the carbide hypothesis has recently been 

proposed by Hunt and others (1992). Among the variety of 

other mechanisms which have been suggested, FischerTropsch-type synthesis from carbon dioxide and hydrogen 

has figured prominently in many modern proposals (for 

example, see Szatmari, 1989). 

The most far-reaching abiogenic proposal in recent 

years is the "deep-earth gas" hypothesis (Gold, 1979, 1985, 

1987, this volume; Gold and Soter, 1980, 1982). Gold postulates that mantle methane is continuously injected into the 

crust at areas of weakness: lithospheric plate boundaries, 

ancient suture zones, and meteorite-impact sites. Under 

conditions of slow upward migration and cooling, some of 

this methane is assumed to polymerize, forming higher molecular weight hydrocarbons and crude oil. 

Numerous arguments for the abiogenic origin of oil 

and natural gas have been offered in the above references 

and in other papers (Porfir'ev, 1974, 1975; Kropotkin and 

Valiaev, 1976; Giardini and Melton, 1983; MacDonald, 

1983; Kropotkin, 1985). Often-cited arguments are (l) the 

abundance of methane in the outer planets of the solar system, (2) the abundance and variety of organic compounds 

in certain meteorites that may have been incorporated into 

the primitive earth, (3) the occurrence of bitumen and hydrocarbon gases in igneous rocks, (4) the association between prolific hydrocarbon accumulations and major faults 

that could act as migration pathways for deep-seated fluids, and (5) the fact that mantle-derived helium is found 

together with methane and higher molecular weight hydrocarbons in some geothermal and commercial natural gases. 

Most geochemists view these arguments as weak and 

circumstantial, the solid consensus being that economic accumulations of oil and gas are "biogenic," a byproduct of 

the bacterial and thermochemical alteration of biological 

detritus in deeply buried sedimentary or metasedimentary 

rocks. Hydrocarbons filling vugs and fractures in many igneous rocks may have a biogenic origin (Parnell, 1988). 

Faults associated with prolific oil and gas production often 

cut great thicknesses of organic-rich sedimentary rocks 

(Price, 1980). Furthermore, although it merits attention, the 

occurrence of mantle-derived helium in some oil and gas 

fields does not prove a nonsedimentary origin for the associated hydrocarbons. Claims by Gold and others that 

biological marker studies, pyrolysis experiments, kinetic 

modelling, and stable-isotope data do not provide strong 

evidence for the biogenesis of crude oil have met with 

sharp criticism (Treibs and Hirner, 1982; Planetary Sciences Unit, University of Cambridge, 1982; Marland, 1984; 

Philp and Brassell, 1986). However, as Gold (1979) and 

MacDonald (1983) have noted, the evidence for biogenesis 

of natural gas is not as strong. Low-molecular-weight hydrocarbons do not retain structural information about their 

precursors (for example, see Mango, 1987). The carbonisotope geochemistry of the light hydrocarbons is not sufficiently constrained to rule out mixing between biogenic 

hydrocarbons and small amounts of abiogenic hydrocarbons (see, for example, Schoell, 1984a; Jenden and others, 

1988b ). In addition, the origin of many dry, nonassociated 

gases, particularly those with high concentrations of carbon 

dioxide and nitrogen, is not clearly understood (Smith and 

others, 1985; Jenden and others, 1988a). 

METHANE IN THE MANTLE? 

The thermodynamic stability of methane in the Earth's 

mantle is a critical, unresolved issue. Considerable differences exist between measured and calculated oxygen fugacities lfo2

) in ultramafic mineral assemblages from _the 

uppermost mantle (Ulmer and others, 1987; Wood and 

others, 1990). If the measured fo 2 values near the ironwustite oxygen buffer are reliable, then CH4/(CH4+C02) 

ratios may range from <0.1 to nearly 1. In any case, Wood 

and others (1990) suggest that methane may become increasingly abundant below the transition from spinel to 

garnet (approximately 70 km) if ferric iron enters the garnet phase. 

The presence of methane in the deeper mantle is qualitatively consistent with the occurrence of reduced gases in 

fluid inclusions in diamonds (formed at depths ~150 km) 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 33 

and the distribution of diamond 6 13c values (Deines, 

1980b; Haggerty, 1986; Galimov, 1991 ). Although fluidinclusion studies show that carbon dioxide is by far the 

most abundant volatile carbon compound in volcanic 

rocks, fluid inclusions rich in methane, hydrogen, and complex organic compounds occur in many alkalic intrusives 

and kimberlites (Roedder, 1984, p. 404, 507-5I4). Thermodynamic data show that, in the presence of graphite and 

an oxygen-buffering mineral assemblage, fluid inclusions 

initially charged with carbon dioxide could become methane-rich upon cooling (Gerlach, I980; Kreulen, I987; Burruss, this volume). 

Another important issue is how mantle volatiles get 

into crustal reservoirs. Where sedimentary basins are 

formed by crustal extension, mantle volatiles could be introduced by melting of the underlying asthenosphere (Oxburgh and others, I986). Lawrence and Taviani ( 1988) 

speculated that isotopic anomalies in the interstitial waters 

of sediments beneath the Norwegian Sea were generated 

by the oxidation of abiogenic methane and hydrogen derived from the upper mantle. A second possibility is that 

in basins near convergent plate margins (and possibly in 

intraplate basins overlying ancient suture zones), mantle 

volatiles might be entrained in hydrothermal fluids generated from subducted lithosphere (Gwilliam, 1982). Here, 

however, mantle-derived methane could be diluted to insignificant concentrations by crustal volatiles, making its 

presence a matter of academic rather than commercial interest. It is worth noting that Poreda and others (1988) 

found no evidence for mantle helium in gases from the 

Barbados accretionary prism. A third possibility, proposed 

by Gold (1979) and Gold and Soter (1985), is that fluids 

migrate continuously out of the mantle and into the crust 

guided by fracture propagation. This speculative mechanism could provide a means for the injection of abiogenic 

methane into almost any crustal reservoir, regardless of its 

tectonic environment. 

Although skepticism is prudent (North, 1982), the potential contribution of abiogenic methane to world gas reserves could be large. The net accumulation rate of organic 

carbon in sedimentary rocks is approximately 3.2xl09 kg/yr 

(Tissot and Welte, 1984, p. 9). Given this figure, and an 

overall thermal alteration reaction of the form 

CH1.o (kerogen)-+0.75C (graphite)+0.25CH4, 

the maximum annual production of biogenic methane cannot exceed 1.5x I 09 m3 (0.8x 109 kg C). In comparison, 

roughly 26xi09 kg of mantle carbon (48xi09 m3 C02) are 

annually degassed into the ocean at spreading ridges (Des 

Marais, I985; Marty and Jambon, I987), and an additional 

large amount is released by subaerial volcanism and geothermal activity. These data suggest that if methane composed only I percent of the total flux of carbon out of the 

mantle, the biogenic and abiogenic methane production 

rates would be of comparable magnitude. (For comparison, the worldwide total of produced gas and recoverable 

reserves as of 1990 is estimated to be 1.7xi014 m3 (Masters and others, 1992).) 

In order to quantify the resource potential of abiogenic 

methane, two questions must be addressed: ( 1) What are 

the chemical and stable-isotope characteristics of abiogenic gas? and (2) What proportion of commercial natural gas 

reasonably can be attributed to abiogenic sources? To help 

answer these two questions we have combined published 

data with carbon and helium isotope measurements from 

more than 600 commercial natural· gases collected from 

1981 to 1987 by Global Geochemistry Corporation under 

contract to the Gas Research Institute (GRI), Chicago (see 

Jenden and Kaplan, 1989a). Question (I) is very difficult 

to address with certainty and some will no doubt object 

strongly to our conclusions. In response, we suggest that 

because the biogenic theory can easily account for most (if 

not all) commercial oil and gas accumulations, the resource potential of abiogenic petroleum is likely to be dismissed until proponents offer an alternative scheme for 

distinguishing abiogenic and biogenic hydrocarbons. 

SAMPLES AND ANALYTICAL 

TECHNIQUES 

GRI samples were collected primarily from U.S. oil 

and gas fields, in Precambrian to Pleistocene reservoirs, at 

depths ranging from less than 150m to nearly 7,000 m. A 

description of the GRI samples together with sampling 

procedures, analytical methods, and results is available 

from the National Technical Information Service (Jenden 

and Kaplan, 1989a). Sampling and analytical procedures 

are also discussed by Poreda and others (1986), Jenden 

and others (1988a), and Jenden and Kaplan (1989b ). 

13c;12c ratios for methane, ethane, propane, n-butane, 

and carbon dioxide were measured at Global Geochemistry 

Corporation and are reported in 6-notation as parts-perthousand (permil) deviations from PDB (Peedee belemnite) 

standard: 

6 13C(permil)= I OOOx[( 13C/12C)sample/( 13C/12C)pos-l]. 

The I a precision of these measurements is approximately 

O.I permil. 

3He/4He ratios were measured at Scripps Institution of 

Oceanography and have been corrected for atmospheric 

contamination as follows: 

eHe/'1-Je )corrected= 

[ eHefHe )measurectxX -eHe/'1--Ie )air ]/[X -I] 

where X=(He/Ne)measurectf(He/Ne)air The ratios are reported in table 1 relative to the air ratio (RA=1.4xl0-6) in the 

form R/RA and have a relative precision of better than ::t3 

percent. 
34 THE FUTURE OF ENERGY GASES 

Table 1. Helium isotope data for commercial gases collected in Gas Research Institute (GRI) study (Jenden and Kaplan, 1989a). 

[Abbreviations as follows: Cret, Cretaceous; Dev, Devonian; Eoc, Eocene; Jur, Jurassic; Mio, Miocene; Olig, Oligocene; Ord, Ordovician; Penn, Pennsylvanian; Perm, 

Permian; Plei, Pleistocene; Plio, Pliocene; Sil, Silurian; m, meters; ppm, pans per million; R/RA, ratio in sample divided by ratio in air;%, volume percent;--, not available] 

Sample 

No. 

1197 

1196 

1123 

1132 

1119 

1126 

1125 

1122 

1110 

991 

1031 

1004 

1030 

1121 

1129 

1130 

1127 

1124 

t1025 

1079 

1146 

1151 

1150 

1107 

1043 

1148 

2 1199 

2 1180 

2 1185 

1153 

1309 

2 1179 

2 1171 

2 1186 

2 1188 

2 1202 

2 1177 

2 1219 

1218 

1271 

1213 

1214 

1270 

1228 

1232 

1275 

1307 

1264 

1269 

Field 

Tompkins Hill 

Tompkins Hill 

Sutter Buttes 

Bounde Creek 

Rio Vista 

Freeport 

Poppy Ridge 

Sutter Buttes 

Rio Vista 

Union Island 

Florin 

Butte, West 

Harte 

Wild Goose 

Robbins 

Robbins 

Nicolaus 

Moon Bend 

Corning 

Lodi, Southeast 

Chowchilla 

Gill Ranch 

Moffat Ranch 

Crossroads 

Durham 

Chowchilla 

Santa Maria Valley 

Belgian Anticline 

Huntington Beach 

Trico 

Molino 

Wheeler Ridge 

Wilmington Offshore 

Big Mountain 

Oxnard 

Orcutt 

Wheeler Ridge 

Panhandle 

Panhandle, East 

Guymon, South 

Panhandle, West 

Panhandle, West 

Guymon, South 

Panhandle, West 

Panhandle, West 

Santa Fe Trail 

Panhandle, West 

Kansas Hugoton 

Guymon-Hugoton 

See footnotes at end of table. 

Reservoir Depth C1 

age (m) (%) 

Plio 

Plio 

Cret 

Cret 

Cret 

Cret 

Cret 

Cret 

Cret 

Cret 

Cret 

Cret 

Cret 

Cret 

Cret 

Cret 

Cret 

Cret 

Plio 

Eoc 

Cret 

Cret 

Eoc 

Cret 

Eoc 

Mio 

Jur 

Eoc 

Mio 

Plei 

Eoc 

Mio 

Mio 

Olig 

Eoc 

Mio 

Mio 

1,628 91.4 

1,463 94.3 

1,122 98.8 

1,896 96.8 

2,717 94.8 

2,213 62.3 

2,198 80.3 

1,856 94.8 

1,384 94.2 

2,972 86.9 

1,158 87.9 

1,554 92.1 

1,387 94.7 

765 77.9 

2,038 12.2 

2,051 12.6 

1,737 35.3 

1,576 80.1 

430 75.0 

905 51.3 

2,415 40.6 

1,753 90.2 

I ,246 91.4 

1,234 92.0 

649 70.3 

794 88.2 

1,268 41.2 

1,996 79.7 

1,498 69.5 

740 98.9 

-- 91.5 

2,707 75.4 

2,929 66.2 

I ,323 86.4 

2,819 80.1 

2,926 57.2 

2,274 77.5 

C02 

(%) 

Nz 

(%) 

02 

(%) 

Northern California 

1.30 

1.61 

0.202 

0.247 

5.08 

0.070 

0.150 

0.292 

4.15 

0.379 

0.026 

0.358 

0.486 

0.024 

0.061 

0.037 

0.041 

0.590 

0.006 

0.006 

0.482 

0.929 

0.370 

0.094 

0.051 

0.029 

0.043 3.61 

0.025 1.36 

0.048 1.01 

0.040 2.33 

0.457 0.697 

0.001 38.4 

0.194 19.5 

0.114 3.86 

0.642 1.43 

0.615 11.1 

0.020 10.1 

0.052 7.00 

0.062 4.66 

0.003 21.8 

0.032 87.4 

0.030 87.2 

0.011 65.1 

0.002 17.6 

0.002 23.8 

0.094 48.4 

0.012 59.1 

0.007 8.35 

0.059 7.61 

0.036 7.64 

0.004 29.2 

0.192 10.8 

0.919 

0.354 

0.021 

0.014 

0.018 

0.013 

0.019 

0.510 

0.027 

0.027 

0.007 

0.005 

0.006 

0.020 

0.026 

0.009 

0.046 

0.018 

0.005 

0.008 

0.040 

0.014 

0.021 

0.017 

0.043 

0.013 

Southern California 

10.3 

15.3 

24.1 

0.038 

8.58 

19.2 

27.3 

8.62 

9.80 

23.2 

13.5 

4.76 

0.898 

1.20 

0.504 

0.119 

0.042 

2.58 

0.010 

0.038 

5.10 

0.111 

32.7 8.89 

1.38 0.130 

1.50 0.100 

0.216 0.020 

0.201 0.042 

2.54 0.281 

1.24 0.005 

1.73 0.224 

6.37 1.34 

9.20 1.16 

5.43 0.346 

Hugoton-Panhandle area 

Perm 

Perm 

Penn 

Perm 

Perm 

Penn 

Perm 

Perm 

Penn 

Perm 

Perm 

Perm 

765 28.2 

640 66.2 

2,021 84.9 

820 75.1 

826 77.0 

1,905 77.0 

488 79.7 

588 75.2 

1,567 84.1 

838 72.3 

-- 74.1 

802 73.4 

54.0 

30.0 

9.86 

18.0 

17.9 

16.1 

9.76 

16.2 

8.53 

16.1 

12.2 

12.7 

1.21 

0.060 

0.269 

O.Q15 

0.023 

0.296 

0.029 

0.026 

0.361 

0.229 

0.031 

0.045 

19.6 

3.46 

1.86 

4.49 

4.73 

4.73 

8.55 

5.94 

6.79 

8.31 

12.5 

I 1.4 

0.360 

0.377 

0.348 

0.186 

0.067 

0.040 

0.233 

0.034 

0.029 

0.068 

0.015 

0.052 

He 

(ppm) 

4.5 

5.0 

10.6 

15 .l 

16.6 

26.0 

27.0 

30.0 

31.9 

33.0 

38.3 

44.5 

52.1 

52.6 

54.0 

59.2 

59.4 

67.7 

91.3 

97.0 

102 

104 

104 

106 

117 

129 

3.5 

5.1 

5.7 

6.8 

10.6 

11.6 

14.4 

15.7 

17.5 

20.9 

28.0 

251 

729 

857 

1120 

1310 

1380 

1500 

1580 

3290 

3410 

3550 

3670 

/l 13C(CH4) 

(permil) 

-32.2 

-31.9 

-28.0 

-26.0 

-36.0 

-15.2 

-19.1 

-29.8 

-38.5 

-23.8 

-29.2 

-31.1 

-52.4 

-27.0 

-22.3 

-21.2 

-20.0 

-30.7 

-42.9 

-46.0 

-34.0 

-47.9 

-51.7 

-46.1 

-26.7 

-53.8 

-32.1 

-36.3 

-51.4 

-70.2 

-36.6 

-40.0 

-45.4 

-40.1 

-36.2 

-36.6 

-49.9 

-42.3 

-41.6 

-43.6 

-41.9 

-41.8 

-45.3 

-43.9 

-44.7 

-43.0 

-42.4 

-43.4 

-43.2 

0.150 

0.145 

0.823 

0.730 

0.144 

1.16 

0.829 

1.10 

0.111 

1.26 

0.421 

1.71 

0.256 

1.97 

0.990 

0.861 

0.990 

2.74 

0.602 

1.01 

0.900 

0.307 

0.320 

0.138 

0.624 

0.361 

0.162 

0.234 

0.932 

0.062 

0.059 

0.310 

0.078 

0.562 

0.671 

0.838 

0.585 

0.041 

0.053 

0.169 

0.051 

0.042 

0.056 

0.031 

0.135 

0.091 

0.144 

0.203 

0.205 

145 

134 

66.6 

45.8 

40.8 

17.1 

21.2 

22.6 

21.1 

18.8 

16.4 

14.8 

13.0 

10.6 

1.61 

1.52 

4.25 

8.45 

5.87 

3.78 

2.84 

6.19 

6.27 

6.20 

4.29 

4.88 

84.4 

113 

87.8 

104 

61.7 

46.4 

32.8 

39.3 

32.7 

19.5 

19.8 

0.801 

0.649 

0.707 

0.479 

0.420 

0.398 

0.380 

0.340 

0.183 

0.151 

0.149 

0.143 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 35 

Table 1. Helium isotope data for commercial gases collected in Gas Research Institute (GRI) study (Jenden and Kaplan, 1989a)-

Continued. 

Sample 

No. 

1262 

1252 

1274 

1256 

1281 

1278 

1245 

1276 

1259 

1277 

1231 

1265 

1273 

1258 

1221 

1280 

1242 

1237 

1243 

1283 

1240 

1260 

1257 

1248 

1236 

'1048 

2 1204 

1090 

1049 

1

1047 

1098 

1136 

1145 

1343 

1337 

1335 

1347 

1340 

1346 

1333 

2 !345 

1334 

1342 

1336 

1341 

1339 

2 1344 

1338 

Field 

Kansas Hugoton 

Kansas Hugoton 

Guymon-Hugoton 

Kansas Hugoton 

Kansas Hugoton 

Kansas Hugoton 

Guymon-Hugoton 

Kansas Hugoton 

Kansas Hugoton 

Dunkle 

Panhandle, West 

Guymon-Hugoton 

Guymon-Hugoton 

Kansas Hugoton 

Panhandle, West 

Kansas Hugoton 

Texas Hugoton 

Panhandle, West 

Texas Hugoton 

Kansas Hugoton 

Texas Hugoton 

Kansas Hugoton 

Kansas Hugoton 

Guymon-Hugoton 

Panhandle, West 

Wilde 

Silver City 

Thayer 

Wilde 

Wilde 

Sterling 

Reichel, West 

Zook 

Bradford 

Painted Post 

Elmira, East 

Reading Center 

Houghton 

Lebanon 

Dansville 

Ellery Center 

Beech Hiii-Indepen 

Lakeshore 

Fayette-Waterloo 

Lakeshore 

Auburn 

Fredonia 

Bergen 

See footnotes at end of table. 

ReseiVoir Depth C1 

age (m) (%) 

c2+ 

(%) 

co, 

(%) 

N, 

(%) 

o, 

(%) 

Hugoton-Panhandle area- Continued 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Penn 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Perm 

Penn 

Cret 

Penn 

Perm 

Penn 

Perm 

Perm 

Ord 

Dev 

Dev 

Dev 

Ord 

Dev 

Sil 

Dev 

Sil 

Dev 

Sil 

Ord 

Sil 

Sil 

Dev 

Sil 

780 73.8 

768 73.0 

-- 74.2 

738 70.7 

759 70.3 

814 70.9 

817 72.0 

689 68.7 

783 66.1 

899 65.6 

866 66.7 

817 48.2 

863 70.3 

814 61.6 

814 76.0 

820 70.4 

960 68.6 

994 71.6 

930 67.2 

780 51.5 

945 70.8 

811 55.8 

683 49.6 

820 58.2 

997 65.6 

12.3 

12.2 

12.0 

12.2 

11.7 

11.9 

11.7 

11.0 

9.58 

7.84 

20.2 

11.4 

9.58 

10.4 

10.7 

4.01 

13.8 

11.6 

11.9 

7.71 

11.6 

5.51 

6.71 

11.6 

6.74 

0.020 14.2 

0.021 14.4 

0.026 11.8 

0.025 16.3 

0.018 17.1 

0.030 16.5 

0.056 14.9 

0.033 19.2 

0.058 23.8 

0.046 25.2 

0.198 10.9 

0.054 36.6 

0.022 17.0 

0.024 27.2 

0.152 12.6 

0.017 24.5 

0.340 14.8 

1.13 13.7 

0.098 18.5 

0.021 39.1 

0.003 15.7 

0.016 37.1 

0.001 43.5 

0.085 28.2 

0.939 24.1 

0.000 

0.115 

0.017 

0.035 

0.241 

0.210 

0.119 

0.432 

0.097 

0.240 

0.022 

0.252 

0.275 

0.088 

0.085 

0.121 

0.084 

0.158 

0.104 

0.054 

0.097 

0.147 

0.008 

0.059 

0.157 

Central and eastern Kansas 

403 67.3 

274 94.6 

154 96.8 

148 78.0 

422 73.7 

59! 69.1 

629 63.6 

1,234 68.1 

1,315 83.6 

1,128 95.1 

893 96.8 

2,466 98.4 

689 78.0 

834 97.8 

448 84.0 

811 71.3 

366 81.3 

1,190 92.8 

607 96.2 

1,241 90.3 

360 96.2 

320 78.9 

ISO 86.6 

4.13 

0.328 

0.090 

6.46 

7.80 

4.44 

3.82 

6.79 

0.125 26.3 

0.207 3.30 

0.351 2.33 

0.001 14.2 

0.088 17.4 

0.035 24.2 

0.007 30.5 

0.208 22.0 

0.003 

0.040 

0.013 

0.009 

0.003 

0.101 

0.025 

0.022 

New York 

15.6 

2.86 

1.54 

0.790 

20.5 

1.44 

14.4 

26.2 

15.1 

3.20 

1.45 

4.22 

0.912 

18.4 

7.69 

0.024 

O.D78 

O.D28 

0.005 

0.001 

0.014 

0.005 

0.023 

0.007 

0.008 

0.008 

0.000 

0.010 

0.090 

0.012 

0.512 0.017 

0.415 0.022 

0.733 0.033 

1.02 0.041 

1.08 0.047 

0.461 0.014 

0.914 0.029 

1.91 0.206 

0.518 0.044 

3.54 0.017 

2.06 0.061 

4.56 0.029 

1.61 0.039 

1.83 0.132 

4.04 O.D25 

He 

(ppm) 

3890 

3960 

4010 

4160 

4210 

4520 

4610 

5250 

5410 

5830 

6080 

6220 

6270 

6330 

6500 

6590 

7000 

7300 

7710 

7830 

8000 

8030 

9150 

12600 

13700 

416 

1330 

6680 

6810 

9360 

21100 

22800 

227 

276 

292 

437 

444 

518 

661 

755 

907 

1040 

1120 

1300 

1540 

1550 

2150 

o13C(CH4) 

(permil) 

-43.4 

-43.5 

-43.2 

-43.8 

-43.8 

-43.7 

-43.0 

-43.6 

-44.3 

-43.5 

-42.6 

-42.6 

-43.9 

-43.9 

-43.3 

-45.4 

-42.8 

-42.6 

-42.3 

-43.6 

-44.5 

-44.8 

-42.1 

-42.7 

-43.0 

-42.2 

-63.2 

-65.0 

-41.2 

-41.1 

-41.0 

-40.0 

-39.6 

-44.4 

-37.4 

-35.8 

-30.7 

-47.2 

-34.8 

-47.3 

-47.8 

-46.2 

-35.4 

-30.9 

-36.8 

-31.5 

-47.9 

-42.6 

3

He/4He 

(RIR.J 

0.198 

0.197 

0.197 

0.163 

0.161 

0.186 

0.191 

0.192 

0.093 

0.159 

0.125 

0.244 

0.043 

0.103 

0.147 

0.073 

0.183 

0.144 

0.175 

0.084 

0.183 

0.057 

0.132 

0.228 

0.105 

0.100 

0.092 

0.070 

0.091 

0.091 

0.097 

0.097 

0.082 

0.013 

0.016 

O.DI5 

0.035 

0.020 

0.018 

0.026 

0.020 

0.021 

0.016 

0.019 

0.019 

0.023 

O.DIS 

0.022 

CH4/

3

He 

(xiO") 

0.135 

0.132 

0.132 

0.121 

0.119 

0.112 

0.111 

0.093 

0.087 

0.080 

0.078 

0.055 

0.080 

0.070 

0.083 

0.076 

0.070 

0.070 

0.062 

0.047 

0.063 

0.050 

0.039 

0.033 

0.034 

1.62 

0.520 

0.083 

0.077 

0.053 

0.022 

0.021 

2.63 

2.46 

2.37 

1.61 

1.25 

1.35 

0.908 

0.674 

0.640 

0.637 

0.613 

0.496 

0.446 

0.363 

0.288 
36 THE FUTURE OF ENERGY GASES 

Table 1. Helium isotope data for commercial gases collected in Gas Research Institute (GRI) study (Jenden and Kaplan, 1989a)-

Continued. 

Sample Reservoir Depth c. c,. co, N, o, He ll"C(CH4) 3

He/4He CHi' He 

No. Field age (m) (%) (%) (%) (%) (%) (ppm) (permil) (RIR.J (x10") 

Miscellaneous U.S. locations 

1066 Puckett-WestBend, TX Penn 6,774 93.2 0.178 4.99 0.359 0.009 125 -31.6 0.013 5.32 

1063 Greasewood, TX Sil 3,137 92.5 0.390 5.74 0.567 0.007 143 -36.6 0.099 4.62 

1037 Sheep Mountain, CO Jur 960 2.13 0.254 97.3 0.666 0.004 180 -40.8 0.980 0.085 

1034 Sheep Mountain, CO Cret 959 4.21 0.278 94.8 1.54 0.005 612 -41.1 1.02 0.049 

1203 Sidney, West, NE Cret 1,509 73.1 15.8 3.99 4.23 0.035 733 -54.6 0.233 0.712 

1192 Wildcat, WV Sil 2,490 13.0 0.138 83.5 2.23 0.107 1060 -35.7 0.331 0.087 

1074 Indian Creek, WV Sil 2,058 33.4 0.277 61.3 2.73 0.012 1140 -34.5 0.210 0.209 

Gulf of Thailand 

1291 Era wan Mio 2,652 62.2 17.5 21.6 0.351 0.025 15.2 -41.1 0.037 29.2 

1299 Pia tong Mio 2,097 24.3 4.00 71.9 0.800 0.025 24.8 -39.2 1.89 6.98 

1292 Erawan Mio 1,929 67.5 18.5 8.68 1.18 0.053 25.3 -41.7 0.032 19.0 

1298 Pia tong Mio 1,908 57.7 18.1 24.8 0.315 0.027 27.1 -44.6 0.345 15.2 

1296 Era wan Mio 2,174 66.4 16.3 13.6 1.81 0.020 30.7 -40.5 0.039 15.4 

1288 Era wan Mio 1,378 80.0 17.7 3.15 0.652 0.016 34.0 -45.9 0.025 16.8 

1

Ratio 'Hei'He measured by R.I. Hill and R.K. O'Nions, University of Cambridge. 

'Associated gas (produced from reservoirs containing an oil phase). 

Many of the GRI data have been published in papers 

that address the origin and characteristics of gases from 

the California Great VaHey (Poreda and others, 1986; lenden and others, 1988a; Jenden and Kaplan, 1989b), U.S. 

Midcontinent (Hilton and others, 1988; Jenden and others, 

1988b ), Gulf of Thailand (Poreda and others, 1988), Los 

Angeles basin (Jeffrey and others, 1991), and northern Appalachian basin (Hilton and others, 1988; Jenden and others, 1993). 

RECOGNIZING MANTLE-DERIVED 

HYDROCARBONS IN THE CRUST 

At present there is little consensus regarding the compositional and stable isotopic variability of abiogenic gas 

in the crust. As a conservative first approximation we suggest that natural gases derived in whole or in part from 

abiogenic sources wiii be characterized by one or more of 

the following properties: (1) methane 6 13C > -25 permil, 

(2) methane [>I3C > ethane 613C > propane [>l3C > n-butane 613C, and (3) helium isotope ratios significantly greater than crustal radiogenic values (for example >0.1 RA)· 

The absence of suitable sedimentary source rocks provides 

additional support for an abiogenic origin, but the application of this criterion would limit our discussion to noncommercial hydrocarbon occurrences. The rationale behind the 

three criteria listed above and a discussion of their implications and limitations are presented below. 

CARBON ISOTOPE DISTRIBUTION 

IN METHANE 

There are relatively few carbon isotope data for methane occurrences that are widely considered to be abiogenic 

(fig. 1). Perhaps the best known occurrence is in the hydrothermal vents issuing from the East Pacific Rise at 21 oN. 

latitude (Welhan and Craig, 1979, 1983). East Pacific Rise 

methane is characterized by 613C values between -18 and 

-15 permil. Sediments are absent atop this area of the 

Rise, and high vent-temperatures (350°C), the occurrence 

of mantle 3HefHe ratios (7.8 RA), and the 613C value of 

carbon dioxide ( -7 permil) ail point strongly to an abiogenic origin. A second example of abiogenic methane is in 

fluid inclusions of alkalic igneous rocks from the Kola Peninsula of Russia (Galimov, 1975; Petersil'ye and Pripachkin, 1979) and southern Greenland (Konnerup-Madsen and 

others, 1988). b13C measurements on fluid-inclusion methane vary from -18 to -1 permil, overlapping the range 

observed at 21 o N. East Pacific Rise and extending to 

much heavier (more positive) values. Los Fuegos Eternos, 

a methane-hydrogen seep issuing from the Zambales Ophiolite in the Philippines, may also be abiogenic (ZO in 

fig. I; Abrajano and others, 1988, 1990). The Zambales gas 

is characterized by methane 613C=-7 permil and a large 

component of mantle-derived helium eHefHe=4.1 RA). 

No sedimentary rocks outcrop at the Earth's surface within 

15 km of these seeps. 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 37 

150 

Q. 

~ 100 ~ 

~ 

""' 0 

cr:: 

(.LJ 

c:Q 

~ 

~ 

50 

0 

M 

BIOGENIC ] METHANE 

T •••••• 

ABIOGENIC [ METHANE 

1699 

COMMERCIAL 

NATIJRAL GASES 

-80 -60 -40 

EPRFl 

GRI 

-20 

o13C METHANE (permil) 

zo. 

0 

Although used interchangeably in this paper, the terms 

"abiogenic" and "mantle-derived" are not strictly synonymous. Sherwood and others (1988), for example, have proposed that methane and hydrogen venting from seeps and 

boreholes in the Canadian Shield are generated by abiotic 

reactions between hydrogen and graphitic carbon in the 

crust. This type of gas appears to have little economic significance and is not considered further in this paper. However, the ubiquitous occurrence of secondary alterations 

within the crust makes it necessary to qualify our use of 

the word "mantle-derived." Methane in the East Pacific 

Rise and Zambales Ophiolite fluids, for example, may be 

formed in the crust by the abiotic reduction of igneous carbon with hydrogen derived from serpentinization of olivine. Fluid-inclusion methane in alkalic igneous rocks may 

originate from the crustal reequilibration of high-temperature, carbon-dioxide-rich fluids (for example Gerlach, 

1980). A small proportion of sedimentary carbon may have 

been incorporated into all of these gases by melting of intruded country rocks or by hydrothermal circulation of 

water containing dissolved organic matter and bicarbonate. 

For practical purposes, East Pacific Rise, fluid-inclusion, 

and Zambales Ophiolite methane is characterized as "mantle-derived" because it appears to be abiogenic and is associated with igneous intrusives carrying mantle helium. 

In this connection, it is important to note that the concept of "methane" actually existing as the molecule CH4 at 

...... Figure 1. Histogram of methane I\ 13C in commercial natural 

gases from Australia, Thailand, Japan, Canada, United States, 

Europe, and Commonwealth of Independent States (former Soviet Union). Data are from Gas Research Institute (GRI) study 

(Jenden and Kaplan, 1989a) and from Colombo and others 

(1966), Ga1imov and others (1970, 1973), Stahl and Carey 

(1975), Stahl and others (1977), Claypool and others (1980), 

Rigby and Smith (I 981 ), Mattavelli and others (1983), Rice 

(1983), Sundberg and Bennett (1983), Barker and Pollock 

(1984), Schoell (I 984b), Whiticar and others (1986), Rice and 

others (1989), Clayton and others (1990), James (1990), Johnson 

and Rice ( 1990), Kotarba ( 1990), Rice and Threlkeld ( 1990), 

Tanner and Fuex (I 990), Wakita and others ( 1990), Sakata 

( 1991 ), and Hiyagon and Kennedy ( 1992). M, microbial methane 

from unconsolidated sediments (Whiticar and others, 1986; Jenden and Kaplan, 1986); T, thermogenic methane (inferred from 

sediment pyrolysis studies; Sackett, 1978; Chung and Sackett, 

1979, 1980; Rohrback and others, 1984; Des Marais and others, 

1988); EPR, geothermal methane from 21 o N. East Pacific Rise 

(Welhan and Craig, 1983); FI, methane in fluid inclusions from 

igneous rocks (Galimov, 1975; Petersil'ye and Pripachkin, 1979; 

Konnerup-Madsen and others, 1988); ZO, methane issuing from 

Zambales Ophiolite, Philippines (Abrajano and others, 1988). 

ambient temperatures and pressures in the mantle is not a 

necessary part of the abiogenic natural-gas hypothesis. It is 

only essential that when abiogenic C and H atoms actually 

emerge in the upper crust, they are combined as the molecule CH4 . Throughout this paper we will therefore ignore 

the question of the molecular species in which C and H 

occur in the mantle and along the transport routes to the 

surface, and when we use the term "methane," it is to be 

taken as descriptive of the actual molecule we see in natural 

and volcanic gases, and of whatever form C and H are in 

below the crust. 

Other occurrences of methane with a likely abiogenic 

origin include fumarolic and hot spring gases from Kirishima Volcano, Japan (o 13C=-23.7 permil; Wakita and others, 

1990), and Iceland (613C=-40 to -18 permil; Poreda and 

others, 1992). The lighter (more negative) Iceland o13C values may reflect additions of biogenic methane. This interpretation would be consistent with the view of Welhan 

(1988) that methane o13C variations in geothermal systems 

primarily reflect changes in the source of the carbon. Alternatively, the lighter methane o13c values may be produced 

by isotopic exchange with magmatic carbon dioxide (o13C= 

-6±2 penni!). If isotopic equilibration between methane 

and carbon dioxide is attainable at temperatures as low as 

300°C (for example, see Giggenbach, 1982), then fractionation factors (Craig, 1953; Richet and others, 1977) indicate that abiogenic methane o13C values could be as low as 
38 THE FUTURE OF ENERGY GASES 

-32 permil. Lighter values might be explained either by 

isotopic equilibration at lower temperatures or by kinetic 

fractionation during the reduction of CO or C02 to CH4. 

Gold and Soter (1982) and Gold (1987, p. 175-181) 

suggested that methane o13c values far lighter than -40 

penni! could be produced by isotopically selective oxidation of mantle methane diffusing upward through the 

crust. The best evidence for this is the progressive increase 

in methane o13c observed with increasing depth in many 

sedimentary basins. This phenomenon is, however, readily 

explained by burial alteration of sedimentary organic matter (for example, see Schoell, 1983), and the experimental 

data of Kiyosu and Krouse (1989) suggest that isotopically 

selective oxidation (acting alone) would increase "rather 

than decrease 0 13c of the residual methane. 

Biogenic methane generally has lighter o13c values than 

the occurrences described above. Studies of young, poorly 

consolidated sediments indicate that o13C values of microbial methane are almost always less than -45 permit and 

very frequently less than -60 permil (fig. I; Whiticar and 

others, 1986; Jenden and Kaplan, 1986). Thermogenic methane, produced by the thermal degradation of sedimentary 

organic matter, is somewhat heavier, but still lighter than the 

abiogenic gases noted above. A o13C range of -60 to -20 

perrnil (and possibly extending to values as light as -70 

permil) is suggested for thermogenic methane on the basis 

of isotopic distribution of Phanerozoic kerogen and coal 

(o13C=-35 to -20 permil; Deines, 1980a, Lewan, 1986) and 

the results of laboratory pyrolysis studies (Sackett, 1978; 

Chung and Sackett, 1979, 1980; Rohrback and others, 1984; 

Des Marais and others, 1988). 

Although there is clearly some overlap between abiogenic and biogenic methane carbon isotope values, the best 

constrained o13c values for abiogenic methane are > -20 

permil, and almost all of the examples mentioned have 

o13c > -25 permil. It is therefore of interest to ask what 

fraction of commercial natural gases fall within this range. 

The histogram in figure I presents carbon isotope data for 

methane from commercial oil and gas fields throughout the 

world. The o13C values range from -84.4 permit for shallow glacial drift gas in Illinois to -15.2 permit for nitrogen-rich gas from northern California. A pronounced mode 

occurs at -42.5 permil. Although the histogram is not necessarily representative of world production, it is noteworthy that out of the 1,699 measurements plotted, only 41 

(2.4 percent) are heavier than -25 permit and 5 (0.3 percent) are heavier than -20 permil. 

CARBON. ISOTOPE VARIATIONS AMONG 

THE C1 TO C4 HYDROCARBONS 

The cracking of complex hydrocarbons to light-hydrocarbon gases generally yields an isotopic distribution in 

which methane o13c < ethane o13c < propane o13c < nbutane o13C (Des Marais and others, 1981; Jeffrey, 1981; 

McCarty and Felbeck, 1986; Chung and others, 1988; 

fig. 2). The isotopic composition of the light-hydrocarbon 

products is kinetically controlled, primarily reflecting the 

slightly lower strength of 12C-12c bonds relative to 13c-12c 

bonds, and has been modelled mathematically by Smith and 

others (1971), James (1983), Sundberg and Bennett (1983), 

Galimov (1988), Clayton (1991) and others. Mechanisms of 

light-hydrocarbon formation which involve the polymerization of cl units to give higher molecular weight hydrocarbons, such as in spark discharge experiments with methane 

(Des Marais and others, 1981; Chang and others, 1983), 

give the reverse distribution, in which methane o13C > 

ethane o13C >propane o13C > n-butane o13c. The possibility that the latter distribution might be characteristic of abiogenically formed hydrocarbon gases is suggested by data 

from fluid inclusions in alkalic igneous rocks (Galimov, 

1975; Konnerup-Madsen and others, 1988) and meteorites 

(Yuen and others, 1984) (fig. 2). 

20 

- 10 

] 

.. 

Ill 

~ 

-.. u 0 

~ " 

u 

::l 

c.o 

-10 

-20 

:«: ......... ...... ...... 1 __ 

... --j[······-0 

••• ' "-'.r· 

'-~--l ' -. ······· ...... ~ ' ·····~······· ' '· • ' . 

.... ........ ··~, ----· ·.Lr--

1 2 3 4 

CARBON NUMBER (n) 

EXPlANATION 

• OCTADECANE PYROLYSIS (JEFFREY, 1981) 

Q OIL-SHALE PYROLYSIS (McCARlY AND FELBECK. 1986) 

• METHANE POLYMERIZATION (DES MARAIS AND OTHERS, 1981) 

[;ii MURCHISON METEORITE (YUEN AND OTHERS, 1984) 

0 IGNEOUS-ROCK FLUID INCWSIONS (GAUMOV, 1975) 

Figure 2. o13C distribution in C1 to C4 hydrocarbons from 

various sources. Vertical bars indicate range of values measured in different samples or experiments. 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 39 

Fuex (1977) recognized that isotopic reversals in which 

methane 613C >ethane 6 13C, ethane 613C >propane 613C, 

and propane 613c > n-butane 613C, do occur in some commercia! natural gases. Illustrated in figure 3 is the lighthydrocarbon isotope distribution in natural gases from this 

study and from a number of published sources. Of 803 gases 

A 

-20 

i 

! 

~ -40 

:e 

~ 

v 

"' ... 

<Q 

-60 

-80 

::::--20 

·~ 

! 

'-Ll 

~-40 

v 

"' ... 

<Q -60 

c 

-80 

::::--20 

·~ 

! 

'-Ll 

z g -40 

CQ 

i:: 

v 

"' ... 

<Q -60 

E 

-80 

' ' ' ' + .. + 

+X 

+ .., .... + + ," X + + 

' 

+ 

+ 

+ + + 

' ' ' 

' ' ' 

/ 

/ / 

' 

' 

+ + ' + ' ' +, 'x , ;, 803 GASES ' ' ' + GRI STUDY ' ' 

' ' X UTERAllJRE 

-60 -40 -20 

o13C METHANE (permil) 

+ + 

' ' ' ' ' ' ' 

-60 

' 

' ' ' 

X 

'+ + )( , ... " 

+ X ," 

~ .u + ....... 

__ :----

' ' 

' ' ' 

' 

' ' ' 

407 GASES 

+ GRI STUDY 

' 

X UTERA llJRE 

-40 -20 

o13C METHANE (permil) 

' ' ' + + i~t .tt&.. / ' +- + + + _f!(-t~ '-~¥ X ,. " 

.,. ~ ~+..,! ~ .,/ 

/ 

X 

' / / 

/ 

-60 

+~ x"x't x / ' X + ' 

/ 

/ 

' 

/ 

/ 

/ 

/ 

/ 

/ ' 

+ ' + -p ' / 

/ 

155 GASES 

+ GRI STUDY 

X UTERAllJRE 

-40 -20 

o• 3 c METHANE (permil) 

' ' ' 

' ' ' 

' ' ' 

~--~--~--~---r---r---r---r---,60 

B 

-10 

D 

-10 

F 

-10 

0 

3.2% 

0 

10 

96.8% 

GRI 

STUDY 

10 

803 GASES 

20 30 

406 GASES 

20 30 

o13C PROPANE- o13C ETHANE (permil) 

154 GASES 

85% 

GRI 

STUDY 

0 10 20 30 

o13C n-BUTANE- o13C PROPANE (permil) 

50 

~ 40 

30 0 ""' 

ffi 

20 ~ 

~ 10 

0 

50 

40 ~ 30 ~ 

ffi 

20 ~ 

~ 10 

50 

~ 40 

30 ~ 

=: 

'-Ll 

20 CQ 

~ 

~ 

Figure 3. Distribution of methane, ethane, propane, and n-butane I\ 13C values in commercial natural gases. Data are from Gas 

Research Institute (GRI) study (Jenden and Kaplan, 1989a) and from Erdman and Morris (1974), Fuex (1977), James (1983), 

James and Burns (1984), Smith and others (1985), Safer (1985), Chung and others (1988), Jianyu and Bingjun (1990) and 

references listed in figure I. In figures 38, 3D, and 3F, percentages indicate proportion of samples that plot on either side of 

dashed lines. 
40 THE FUTURE OF ENERGY GASES 

with methane and ethane data, 29 gases (3.6 percent) have 

methane 613C > ethane B13C (figs. 3A, 38). However, none 

of these gases for which propane or butane data are available show methane 613C >propane 613C or methane 613C 

> n-butane 613c (figs. 3C, 3£). Because the concentrations 

of ethane, propane, and butane in these gases far exceed 

those in a mixture in chemical equilibrium (Takach and 

others, 1987), their carbon isotope compositions cannot be 

explained by isotopic equilibration in crustal reservoirs. Instead, the data suggest that natural gases do not arise from 

methane polymerization reactions as suggested by Gold and 

others (1986). 

The methane-ethane, ethane-propane, and propane-nbutane isotope reversals shown in figures 38, 3D, and 3F 

might be caused by a number of mechanisms. Many of the 

methane-ethane 'reversals occur in natural gases from northwestern Germany and the northern Appalachian basin, 

where vertical and lateral migration are extensive and mixing of gases from different sources may have occurred 

(Schoell, 1984b; Jenden and others, 1993; M. Schoell, oral 

commun., 1993). Mixing between different natural gases 

with normal isotopic distributions can produce a gas with 

one or more reversals, as illustrated in figure 4. In the Sacramento basin, isotopic reversals between methane and 

ethane could reflect either mixing (Jenden and Kaplan, 

1989b) or isotopic heterogeneity in the source organic matter (see lignite pyrolysis results of Des Marais and others, 

1988). The relatively high percentage of reversals between 

propane and n-butane shown in figure 3F may be caused by 

shallow microbial oxidation, which can be selective for 

propane (James and Burns, 1984; Jeffrey and others, 1991). 

HELIUM ISOTOPE RATIOS IN 

COMMERCIAL GASES 

Since the discovery in the late 1960's of 3He anomalies 

related to East Pacific Rise hydrothermal activity (see review in Craig and Lupton, 1981), the value of helium isotopes as tracers of mantle volatiles has been firmly 

established. Crustal helium, produced by radioactive decay 

of U and Th (yielding 4He) and the (n, a) reaction of 6Li 

(yielding 3He), is characterized by average 3He/'\Ie ratios 

<0.04 RA, where RA=atmospheric 3HefHe=l.4xi0-6 

(Mamyrin and Tolstikhin, 1984, p. 97-104; Andrews, 1985). 

Mantle-derived helium, on the other hand, is a mixture of 

radiogenic and primordial helium, the latter having 3He/ 

4He=l00 to 300 RA (Craig and Lupton, 1981; Mamyrin and 

Tolstikhin, 1984, p. 90-94). As a consequence, mantle 3

He/ 

4He values are much higher than crustal values and vary 

from an average of 8 RAin midoceim-ridge fluids and basalts to at least 35 RA in hotspots such as Hawaii and Iceland (Craig and Lupton, 1981; Welhan and Craig, 1983). 

In the last few years, numerous studies have addressed 

the distribution of helium isotopes in commercial oil and 

gas fields (fig. 5). Fields overlying ancient cratonic crust 

and in foreland basins formed by thrust-plate loading are 

characterized by 3He/'\Ie ratios close to radiogenic values 

(Oxburgh and others, 1986; Hilton and others, 1988; Hiyagon and Kennedy, 1992). Fields located near active plate 

margins in forearc, backarc, and rift basins, on the other 

hand, may have 3

HefHe ratios approaching mantle values 

(Poreda and others, 1986; Sano and others, 1987; Poreda 

and others, 1988; Wakita and others, 1990). The helium 

isotope data compiled in figure 5 range from 0.004 RA for 

a Paleozoic gas from the tectonically stable Russian platform (Kamenskiy and others, 1971) to 7.5 RA for a Cenozoic gas from Japan (Sakata, 1991). 

] -30 

~ 

u 

<"l 

::0 -35 

-40~~--~------~------~------~ 1 0.1 0.01 0.001 0.0001 

A MOLE FRACTION OF COMPONENT 1 IN MIXTIJRE 

12 

] 10 

.. 

~ 8 

EXPlANATION 

- ETifANE- MElHANE 

- - PROPANE- ElHANE 

--- n·BUTANE- PROPANE 

Ll.l 

u 6 ~ ex: 

Ll.l 4 

~ 2 0 

2 

---- -- u 

<"l 

.... 0 c.o 

.... --- -·-.. -.. -··_ .. _ .. _. ___ .. -.. -·-" 

-2 

1 0.1 0.01 0.0001 

B MOLE FRACTION OF COMPONENT 1 IN MIXTURE 

Figure 4. o13C values (A) and o13C differences (B) for range of 

hypothetical gas compositions produced by mixing between 

two biogenic endmembers (components I and 2) with a normal 

isotopic distribution (that is, o13C1<o13C2<o 13C3<o13C4). The 

model shows how, in a gas mixture, isotopic reversals could 

arise between two or even three hydrocarbons (for example, 

o13C1>o 13C2 or o13C2>o13C3>o13C4). A complete reversal 

among all four hydrocarbons would be highly unlikely. Component 1: 76 percent CH4, -52 permil; 15 percent CzH6, -40 permil; 6 percent C3H8, -34 permil; 3 percent C4H10, -31 permil. 

Component 2: 97.89 percent CH4, -32 permil; 2.00 percent 

C2H6, -28 permil; 0.10 percent C3H8, -26 permil; 0.01 percent 

C4H10, -25 permil. 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 41 

Using simple mass-balance principles, 3He!"H:e ratios 

can be used to estimate the fraction of helium which has 

been derived from the upper mantle. Where R refers to the 

3

HefHe ratio, the relevant equation is 

Calculations made assuming that Rcrust=0.01 RA and Rmantle= 

8 RA yield a range of 0 to 94 percent mantle-derived helium 

with a median value of 2.3 percent (fig. 6). 

An upper mantle 3HefHe ratio of 8:!:1 RA is well constrained by studies of midocean-ridge basalts and hydrothermal vents (Craig and Lupton, 1981; Welhan and Craig, 

1983). However, crustal 3HefHe values may vary locally 

from less than 0.01 RA to values in excess of 0.04 RA 

depending upon a variety of factors including the Li con15 

10 

10 

5 

CIS, NORTH SEA, 

WESTERN CANADA, AND 

MISCELlANEOUS 

\ 

0 ~---ll~~~uw~ 

0.001 0.01 0.1 

- - - - --- --

GRI STUDY 

MOSTLY USA 

(n = 110) 

10 

OTHER 

PUBLISHED 

STUDIES 

(n = 234) 

100 

tent of the sediments and underlying crust, the spatial distribution of Li relative to U- and Th-bearing minerals, the 

relative abundance of 3He-enriched cosmic dust particles 

in the sediments, and the relative release rates of 3He versus 4

He (Andrews, 1985; Martel and others, 1990; Hiyagon and Kennedy, 1992). Using a higher average crustal 

3He/"H:e value will yield lower estimates of mantle-derived helium, so that for a crustal 3

He!"H:e ratio of 0.1 RA, 

the median contribution of mantle-derived helium drops to 

1.2 percent. 

Kamenskiy and others (1971) were probably the first to 

suggest that the low 3He/"H:e ratios observed for many 

commercial natural gases argued against an origin in the 

mantle. This assessment must be qualified because the 

combined effect of helium loss through reservoir caprocks 

and helium addition from radiogenic sources could cause 

1000 

Figure 5. Histogram of 3He/4He ratios (expressed 

as RIRA, or ratio in sample divided by ratio in air) 

in commercial natural gases from Thailand, New 

Zealand, Indonesia, Philippines, Taiwan, and Barbados (Sano and others, 1987; Poreda and others, 

1988); Japan (Wakita and others, 1990; Sakata, 

1991 ); western Canada (Hiyagon and Kennedy, 

1992); United States (Aldrich and Nier, 1948; Weihan and others, 1988; Gas Research Institute (GRI) 

study-Jenden and Kaplan, 1989a); North Sea 

(Hooker and others, 1985); central Europe (Ballentine and others, 1991; Ballentine and O'Nions, 

1991 ); and the Commonwealth of Independent 

States (CIS) (Kamenskiy and others, 1971 ). Isotopic 

fields for radiogenic, volcanic, and primordial helium are adapted from Craig and Lupton ( 1981) and 

Mamyrin and Tolstikhin ( 1984). MOR, midocean 

ridge. 
42 THE FUTURE OF ENERGY GASES 

160 

150 

60 

~ 50 

rl) 

~ 

~ 40 

ca::: 

'""' QQ 

~ 30 ;:J 

z 

20 

10 

0 

344 TOTAL SAMPLES 

MEDIAN • 2.3 percent 

CIRCUM-PACIFIC BASINS 

0 10 20 30 40 50 60 70 80 90 100 

MANTLE He/TOT AI.. He (percent) 

Figure 6. Proportion of mantle-derived helium in natural gases. 

Calculations are based on the data in figure 5 and assume 3He/ 

4

He=O.Ol RA for crustal (radiogenic) helium and 3HefHe=8 RA 

for upper-mantle helium. Arrow labeled "Circum-Pacific basins" 

shows range of data from New Zealand, Philippines, Taiwan, 

Japan, and California. 

initially high 3He/'1-le ratios to decrease with time. 3HefHe 

ratios near 0.01 RA might be expected for very old accumulations regardless of their origin. On the other hand, the 

absence of elevated 3He/'1-le ratios in many Cenozoic oil 

and gas fields does argue against a significant contribution 

of mantle-derived methane. 

With this problem in mind, Gold ( 1987, p. 109) suggested that pure methane moving up through the mantle 

would quickly strip primordial helium from established migration pathways and that low, radiogenic 3He/'1-le ratios 

therefore do not rule out a contribution of mantle-derived 

fluids. Gold 's suggestion is at odds with the finding that 

volcanic and geothermal activity, which commonly accompanies the introduction of mantle volatiles into the crust, is 

nearly always associated with elevated 3He/'1-l:e ratios (for 

example, Welhan and others, 1988; Poreda and Craig, 

1989; Griesshaber and others, 1992). In the absence of 

supporting evidence, the proposal that abiogenic methane 

can be completely decoupled from mantle 3He/'1-l:e ratios 

is speculative at best. 

Although many gases appear to have little or no mantle 

contribution, figure 6 indicates that 10 to perhaps 85 percent of the helium in many circum-Pacific reservoirs of 

Cretaceous and Tertiary age may be derived from the upper 

mantle. This result is important but does not, by itself, 

imply the presence of large quantities of abiogenic hydrocarbons. 3He/'1-le ratios as high as 7.5 RA have been measured in oil and gas fields of the Green Tuff region of Japan, 

for example, yet methane o13c values range from -62 to -33 

permil (well within the biogenic range) no significant isotopic reversals are observed among the cl to c4 hydrocarbon gases, and biomarker studies have correlated the oils to 

local, organic-rich Miocene shales (Sakata and others, 

1989; Sakata, 1991). Although a large abiogenic contribution has been suggested (Wakita and Sano, 1983; Wakita 

and others, 1990), an alternative explanation is that magmatic fluids introduced mantle helium into the Green Tuff 

basins and also heated local source rocks, causing oil and 

gas generation (H. Craig and Y. Horibe, written commun., 

1984). 

A second example of biogenic methane associated 

with mantle-derived helium is provided by geothermal 

vents along the East Pacific Rise in the Guaymas Basin, 

Gulf of California (Welhan and Craig, 1979, 1982; Welhan 

and Lupton, 1987). Although 3He/'1-le=8.0 RA, approximately equal to that measured for similar vents at the 

21 oN. East Pacific Rise site (discussed above), the Guaymas methane-to-helium ratio is nearly three orders of magnitude higher than that at the 21 oN. site. This difference is 

attributed to the circulation of hot fluids through overlying 

organic-rich sediments in the Guaymas Basin. Indeed, 

whereas methane o13C values at the 21° N. East Pacific 

Rise site range from -18 to -15 permil, methane o13C values at the Guaymas site range from -51 to -43 permil, far 

too light for an abiogenic origin. 

METHANE CONCENTRATION AND 

HELIUM-3 ABUNDANCE 

If abiogenic (magmatic) hydrocarbons are present in 

oil and gas fields, one might expect to see evidence for 

mixing relationships in cross plots involving the concentrations and isotopic compositions of helium and methane. 

After Wakita and Sano (1983) suggested that Japanese 

gases in the Green Tuff region had a large component of 

abiogenic methane, H. Craig and Y. Horibe (written commun., 1984) showed that the Green Tuff data could readily 

be explained by mixing small amounts of magmatic helium with a crustal gas composed of biogenic methane and 

traces of radiogenic helium. In figure 7, a modified version 

of the plot used by Craig and Horibe (written commun., 

1984), the original data of Wakita and Sano (1983) are 

shown together with the more recent results of Wakita and 

others (1990) and Sakata (1991 ). The illustrated mixing 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 43 

line also fits gases from hot springs, mudpots, and fumaroles in the eastern Kamchatka Peninsula (Kamenskiy and 

others, 1976). 

The crustal endmember in figure 7 has been assigned 

a hypothetical composition with Cf4PHe=3x1013 and 

3HefHe=0.01 RA- The magmatic endmember is taken to 

be the same as a fumarole gas from Usu Volcano in westem Hokkaido, for which CH4PHe=1.1x106 and 3

He/'1le= 

6.2 RA (H. Craig andY. Horibe, written commun., 1984). 

On the basis of these endmembers, 0.1 ppm to 1,000 ppm 

(0.1 percent) of the methane in the Japanese commercial 

gases could be abiogenic (magmatic). 

figure which is not well constrained. If we use the CH4PHe 

ratio of 12x 106 measured for !fakone Volcano, southwest 

of Tokyo, the proportion of abiogenic methane in the Japanese commercial gases could reach up to 1 percent. On the 

other hand, fumaroles on volcanoes in the Banda arc of 

Indonesia have CH4/

3He ratios of 0.1xl06 or less (Poorter 

and others, 1991 ), for which abiogenic methane contents 

<100 ppm would be calculated. Actually, so long as the 

volcanic 3

He/'1Ie ratio is constant at approximately 6 RA, 

an equally good fit to the data can be obtained for any 

CHi)Ie ratio less than 3x108 (this figure corresponds to 

the minimum ratio measured for Green Tuff gas). 

This type of calculation obviously depends strongly 

upon the CH4PHe ratio of the magmatic endmember, a 

Similar two-component mixing models can also be fitted 

to data from other oil- and gas-producing regions, including 

1014 r-~---------------.--------------~~--------------r-~ 

-~------- CRUSTAL END-MEMBER: 

CH4/3He = 3 x 1013 

0.01 RA . 

I 

' 0.1 PPM 

0 

EXPIANA TION 

<> 

+ GREEN TUFF REGION 

<> OTHER AREAS 

0 

, 

I 

1 PPM 

6. KAMCHATKA PENINSUlA 

10PPM ' · 

<> 100 PPM,~ 

<) 

1%----

10%----

MAGMA TIC END-MEMBER: 

CH4

; 3He = 1.1 x 106 ____ ..,._.,._ 

6.2 RA 

usu 

105 ~~--------------~------------~------------~~ 0.01 0.1 1 10 

Figure 7. Mixing model for origin of helium and methane in Japanese natural gases (modified from H. Craig and Y. Horibe, written commun., 1984). Dashed lines indicate proportion 

of methane (in parts per million and in percent) derived from the magmatic endmember, Usu 

Volcano (USU). Natural-gas data for Green Tuff region and other areas from Wakita and 

others (1990) and Sakata (1991); data for Kamchl!tka Peninsula volcanic and geothermal 

gases from Kamenskiy and others (1976); data for Usu and Hakone (HAK) Volcanoes from 

Craig and others (1978) and H. Craig andY. Horibe (written commun., 1984). R/RA, ratio in 

sample divided by ratio in air. 
44 THE FUTURE OF ENERGY GASES 

the Commonwealth oflndependent States, Canada, the United States, the North Sea, and Central Europe (fig. 8). Two 

mixing curves encompass the data in figure 8 and illustrate 

the compositional variation of potential crustal and magmatic endmembers. Crustal CH/l-Ie ratios, shown with 3

He/ 

4He=O.Ol RA, range from 3xl09 to 2xl013 and are grossly 

related to reservoir age. The arrows in figure 8 illustrate the 

effects of adding pure radiogenic helium eHe/'1-le=O.Ol RA) 

to young reservoirs lying along the uppermost mixing line. 

Using the arrows as a guide, one can visually remove the 

effects of radiogenic helium addition and see that many of 

the Paleozoic reservoirs were initially charged by gases with 

CH4PHe and 3HefHe ratios similar to those observed in 

Mesozoic and Cenozoic reservoirs. 

Although the range of magmatic 3He/'1-le values in figure 8 is not as well constrained as in Japan (see fig. 7), 

somewhat lower values are suggested and the mixing lines 

employ endmembers at 1 and 4 RA- Magmatic 3He/'1-le 

ratios significantly lower than the upper mantle value of 

8 RA suggest that radiogenic helium (and possibly other 

volatiles) may have been incorporated into the magmatic 

endmember during migration through the deep crust (see, 

for example, Poreda and others, 1986, 1988). Magmatic 

CH4/

3

He ratios appear constrained to lie at or below lxl08, 

but as in the case of the Japanese gases, values as low as 0 

could be fitted to the data. 

The abundance of abiogenic methane in the gases shown 

in figure 8 is very difficult to estimate because the 3

HefHe 

1014 r--r---------------,---------------.----------------~~ 

X 

.(}> 

? <} 

107 

EXPLANATION 

+ CENOZOIC GAS 

106 <l? MESOZOIC GAS 

'\ 

\ 

\ 

\ 

\ 

? 

~ EPR 

X PALEOZOIC GAS ? 

105 

0.01 0.1 1 10 

Figure 8. Methane-helium relations in 179 commercial gases classified by reservoir age. 

Data are from Thailand, New Zealand, Indonesia, Philippines, Taiwan, Barbados, western 

Canada, United States, and central Europe (references listed in fig. 5 caption). EPR, geothermal fluids from 21 o N. East Pacific Rise (Welhan and Craig, 1983); ZO, gas seeps from the 

Zambales Ophiolite in the Philippines (Abrajano and others, 1988). Solid lines illustrate mixing between hypothetical crustal gases (diamonds) and magmatic gases; queries and dashed 

lines indicate uncertainty in the compostion of the latter. Arrows show the effect of adding 

radiogenic helium with 3

HefHe=0.01 RA to gases lying near the upper mixing line. RJRA, 

ratio in sample divided by ratio in air. 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 45 

and C~PHe ratios of the magmatic endmember are both 

relatively unconstrained. A further problem is that two-component models may not fully describe mixing relations in 

some oil and gas provinces. In the California Great Valley, 

for example, a third component characterized by high nitrogen content and 3

HefHe near 1 RA may be derived from 

subducted metasedimentary rocks (Jenden and others, 

1988a). A simple approach which sidesteps the problems 

created by assimilation of crustal volatiles into the magmatic 

component is to calculate, for each gas, the amount of 3He 

ultimately derived from the mantle. The concentration of 

abiogenic methane can then be estimated from CH4PHe 

ratios measured in volcanic and geothermal systems where 

contamination with organic carbon is unlikely. 

The relevant calculation is 

CH4 abiogenic(percent)= 

FxHe(percent)x(3

HefHe)mantlex(CH4/3He)geothermal• 

where F is the fraction of helium derived from the mantle 

(discussed above in fig. 6) and He is the helium concentration. The greatest uncertainty in this equation is the CH4PHe 

ratio of geothermal fluids derived from the mantle. As noted 

above, CH4PHe ratios of summit gases from circum-Pacific 

volcanoes range from <0.lx106 to 12xl06 (Craig and others, 

1978; Welhan and others, 1988; Poorter and others, 1991). 

CH4/

3He ratios in midocean-ridge basalts and geothermal 

vent fluids from open-ocean spreading ridges are reported to 

range from <<0.1 x106 to at least 20x107 (Welhan and Craig, 

1983; Jean-Baptiste and others, 1991; Javoy and Pineau, 

I 991). Finally, CH4PHe ratios measured in geothermal samples from mantle hotspots (Easter Island, Loihi Seamount, 

Iceland, and Reunion Island) vary from <0.1 X 1 o6 to 

100x106 (Craig and others, 1984; Garno and others, 1987; 

Poreda and others, 1992; Marty and others, 1993). As there 

is no clear evidence for contamination with organic carbon 

in these gases, this broad range of CH4PHe ratios presumably reflects differences in the cooling history of the fluids 

(Giggenbach, 1982) and variations in the oxygen-buffering 

capacity of the surrounding rocks. 

For illustrative purposes, we start with a CH4PHe ratio 

of 3xi06, the geometric average of the extreme values of 

0.1 X 1 o6 and 1 OOx 1 o6 noted above, which is approximately 

equal to that measured for fluids from the 21 oN. East 

Pacific Rise site (3.5xl06 to 6.5xl06

; Welhan and Craig, 

1983). The mantle 3HefHe ratio is taken to be 8 RA- Given 

these values, the calculated abundance of abiogenic methane in commercial gases (for which He abundance and 3

He/ 

4He data are available) ranges from 0 to 1.2 percent and has 

a median of 0.016 percent (160 ppm) (fig. 9). The highest 

concentrations are calculated for gases from the supergiant 

Hugoton field of southwestern Kansas, Oklahoma, and 

Texas. Neither the Lower Permian dolomite reservoir rock 

of the Hugoton field nor the underlying sedimentary section 

are associated with igneous intrusives (Pippin, 1970), but 

Hugoton gases have modestly elevated 3

He/'1-le ratios (0.06 

to 0.24 RA) and contain large quantities of both helium (0.4 

to 1.3 percent) and nitrogen (11 to 44 percent) (table I). 

Somewhat lower concentrations of abiogenic methane (up 

to 0.6 percent) are calculated for the circum-Pacific gases 

because even though many have extremely high 3HefHe 

ratios, they contain less than 200 ppm helium. 

The values plotted in figure 9 suggest that in most oil 

and gas fields, the abundance of abiogenic methane is vanishingly small. Even if the c~PHe ratio of geothermal 

fluids derived from the mantle were assigned the maximum value of l OOx 106, the median concentration of abiogenic methane in commercial oil and gas fields would still 

amount to only 0.53 percent. If the minimum value of 

0.1 x 106 were used, the median concentration of abiogenic 

methane would drop to just 5 ppm. 

140 

130 

~ 40 

(/) 

~ 

~ 30 

0:: 

U.J 

~ 

~ 20 

10 

0 

0 

244 TOTAL SAMPLES 

MEDIAN = 0.016 percent 

HUGOTON HElD, USA 

CIRCUM·PACJAC BASINS 

0.2 0.4 0.6 0.8 1.0 1.2 

ABIOGENIC METHANE(fOT AL GAS (percent) 

Figure 9. Estimated abundance of abiogenic methane in 244 

commercial gases from Thailand, New Zealand, Indonesia, 

Philippines, Taiwan, Barbados, Japan, western Canada, United States, and central Europe (references listed in fig. 5 caption). Calculations assume a geometric average CHi3He 

value of 3xl06 for magmatic fluids in circum-Pacific volcanoes, spreading ridges, and mantle hotspots uncontaminated 

by organic carbon (Welhan and Craig, 1983; Garno and others, 1987; Poorter and others, 1991; Poreda and others, 1992). 

Results are only order-of-magnitude estimates since CJ-4PHe 

ratios actually vary from <0.1 x 106 to IOOx 106

• Brackets indicate range of values calculated for gases from circum-Pacific 

basins and the supergiant Hugoton field, United States. 
46 THE FUTURE OF ENERGY GASES 

It is worth noting that for the supergiant Hugoton 

field, calculations employing (CH4PHe)geothermal=l00xl06 

yield abiogenic methane abundances as high as 40 percent. 

Since the entire Hugoton-Panhandle production complex is 

estimated to have ultimate recoverable gas reserves of 

more than 2xl012 m3 (Pippin, 1970), this would imply a 

huge absolute contribution of abiogenic methane. Even if 

we took (CH4PHe)geothermal=O.lxl06 and averaged theresults for all of the Hugoton-Panhandle samples, the estimated contribution of abiogenic methane would still be 

2xl08 m3. (On the basis of systematic variations in helium, nitrogen, and methane across the field, Gold and Held 

(1987) have argued that the entire Hugoton-Panhandle accumulation has an abiogenic origin.) 

Although this result might be viewed as evidence for a 

significant abiogenic hydrocarbon resource, it should be 

mentioned that because Hugoton 3HefHe ratios are only 

slightly elevated, the calculated abundance of abiogenic 

methane is quite sensitive to the 3HefHe ratio assumed for 

the crustal mixing endmember. In their discussion of helium isotope ratios in western Canadian gas fields, Hiyagon 

and Kennedy (1992) suggested that localized Li-rich evaporitic clays could yield radiogenic helium with 3

HefHe 

ratios as high as 0.5 RA- Because the Hugoton reservoirs 

interfinger with red beds and are overlain by evaporites, it 

is conceivable that the relatively high 3

He/'i-le ratios observed in this field are radiogenic and that the abundance · 

of mantle helium and abiogenic methane has been grossly 

overestimated. Although our explanation is speculative, it 

should be noted that methane 613C values in the HugotonPanhandle complex (-45.4 to -41.1 permil) are clearly biogenic and that no isotopic reversals occur among the C1 

to c4 hydrocarbons (Jenden and others, 1988b; Jenden and 

Kaplan, 1989a). 

METHANE a13c AND HELIUM-3 

ABUNDANCE 

If isotopically heavy abiogenic methane were a significant component of commercial oil and gas accumulations, 

one might expect to see a correlation between helium and 

methane carbon isotope compositions. It can be seen in 

figure 10 that the shape of the mixing lines depends critically upon the ratio (CHi3

He)crustaJ:(CH4PHe)magmatic· If 

the crustal ratio were as much as 1 o6 times the magmatic 

ratio, a significant correlation would not be expected. On 

the other hand, if the crustal ratio were on the order of 103 

times the magmatic ratio, methane 613C values would tend 

to increase with increasing 3

HefHe. In actuality, the expected relationships are complicated by variability in both 

the biogenic and magmatic methane o13C values. In addition, conclusions about the abundance of abiogenic methane are difficult to draw from these curves since hot 

magmatic fluids may become contaminated with organic 

carbon from invaded sedimentary and metasedimentary 

rocks. 

The relationship between methane 613c values and 

3

He/'i-Ie ratios for Japanese natural gases from the Green 

Tuff region and surrounding districts is shown in figure 11. 

The mixing lines are purely hypothetical and have been 

drawn so as to bound the data as tightly as possil?le. The 

isotopic compositions of methane in the crustal component 

vary from -76 perrnil (microbial origin) to near -36 permil 

(thermogenic origin). This large variation in o13C values 

makes the endmember abundances present in any given 

sample impossible to determine. 

Some insight can be gathered by examining points lying 

near the margins of the data field. The gas marked "A," for 

example, has a 3

HefHe ratio of 5.5 RA, very near that of 

the magmatic endmembers, and a 613C value of -61.3 permil, at least 30 permil lighter than that of the magmatic 

endmembers. The origins of helium and methane in this 

sample are clearly decoupled: the helium is essentially all 

derived from the magmatic component and the methane is 

essentially all derived from the crustal endmember. The 

actual (C~/ He)crustaJ:(C~PHe)magmatic ratio is probably 

greater than the value of 6x 103 illustrated by the lower 

mixing line. A ratio of approximately 105 would be required 

if the crustal endmember that mixed to form gas A had a 

methane o13c value as heavy as -62 permil. 

-10r-r---------~--------~--------~_, 

MAGMATIC 

END-MEMBER 

-15 00 

= -20 1:1 0 

e 

.. 

Ql 

..,e, 

~ -25 0 

:c 

!ij 0 :E -30 

u 

('I) 

.... 

tQ 

-35 20 

-40 

106:1 

% 

CRUSTAL MAGMATIC 

END-MEMBER METHANE 

-45 

0.01 0.1 1 10 

3He/4He (R!RA) 

Figure 10. Mixing lines between hypothetical crustal and magmatic endmembers on plot of methane I\ 13C versus 3

He/'i-Ie 

(expressed as R/RA, or ratio in sample divided by ratio in air). 

Shape of mixing lines depends on ratio (CJ-4PHe)crustal:(Clf.t/ 

3

He )magmatic, for which values from 1: I to 106:1 are illustrated. 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 47 

The shape of the upper mixing line, for which 

(C!-4PHe)crustal:(CH4PHe)magmatic=l.5x 104

, is suggested 

by the distribution of several gases in the area marked 

"B." The crustal endmember at 3He/'lle=0.01 RA presumably represents the most mature thermogenic methane 

generated in the Green Tuff basin without the involvement of magmatic fluids. The magmatic endmember, fitted 

with 3He/'lle=5.5 RA and methane b13C=-25 permil, is 

similar to several methane-rich Kamchatka Peninsula 

gases and is interpreted to originate from contact between 

mantle-derived fluids and sedimentary organic matter. If 

the crustal CI-4PHe ratio is taken to be 3x1013 (fig. 7), a 

CHi3He ratio of roughly 2x 109 is inferred for the magmatic component. The latter is similar to the CH4PHe 

ratio observed for the isotopically heaviest Green Tuff 

gases. 

Relationships between methane b13C values and 

3HefHe ratios for commercial gases outside of Japan are 

illustrated in figure 12. As before, methane b13C values 

inferred for the crustal component vary widely (-70 to -30 

or-,-------------r------------.------------.--, 

EXPL\NA TION zo[lj ··::· 

-10 + GREEN TIJFF REGION 

0 OTHER AREAS EPR 

D. KAMCHATKA PENINSUlA ~. 4 

~· -20 KIR 

] -30 J .. 

~ 1 

~ 0 tr:.*# ~ -40 • • ~ • 

• • 

u 0 • .., • .... 

00 -50 • 

<> • 

• • • 

-60 • 

Figure 11. Plot of methane 613C versus 3HefHe (expressed as R/RA, or ratio in sample 

divided by ratio in air) for natural gases from Japan (data from same sources as those cited 

in fig. 7). EPR, geothermal fluids from 21° N. East Pacific Rise (Welhan and Craig, 1983); 

ZO, gas seeps from the Zambales Ophiolite in the Philippines (Abrajano and others, 1988); 

KIR, Kirishima Volcano (Wakita and others, 1990). Mixing lines are drawn between hypothetical crustal and magmatic endmembers. The magmatic endmembers eHefHe=5.5 to 

8.0 RA and 6 13C=-25 to -15 permil) were chosen to match data for volcanic and geothermal gases from the Kamchatka Peninsula (Kamenskiy and others, 1976) and are interpreted 

to originate from variable contact between hot magmatic fluids and sedimentary organic 

matter. The illustrated (CH4PHe)crus1:(CH4/

3

He)magmatic values are l.5x104 for line 1-2; 

and 6x 103 for line 3-4. "A" and "B" refer to data discussed in text. 
48 THE FUTURE OF ENERGY GASES 

permil), making it impossible to estimate the endmember 

abundances in any given sample. No relationship can be 

discerned between methane o13C values and reservoir age. 

The distribution of data do, however, support an association 

between high 3HefHe ratios and isotopically heavy methane (<'i 13C values up to -15 permil). If one assumes a magmatic endmember with methane o13C:2:-15 and 3HefHe=1 

to 4 RA, several gases from the Great Valley of California 

(GV) would appear to be dominated by this component. 

3He/'He ratios (s0.04 RA) reach up to 2x1013, one might 

infer CH4PHe values for the so-called magmatic component as high as 5xl010. Because this ratio is more than 

one order of magnitude larger than the average ~CPHe 

ratio (where ~C is total carbon summed from all C-bearing compounds) inferred for the upper mantle (2x109

; 

Marty and Jambon, 1987), contamination with biogenic 

methane is indicated. Such high CH4PHe ratios in the 

magmatic endmember are intriguing because they imply 

that contact between igneous fluids and sedimentary rocks 

could generate commercially significant quantities of natural gas (Poreda and others, 1986, 1988). 

The mixing lines which so neatly bound the data were 

both drawn with (CH4PHe)crustati(CJ14PHe)magmatic=400. 

Since CH4PHe values for Cenozoic gases with crustal 

0~~--------------~-------------r------------~~ 

-10 

-20 

-

i -30 

! 

~ -40 

~ ::;: 

u .., 

... 

<0 -50 

-60 

-70 

EXPlANATION 

+ CENOZOIC GAS 

'l)o MESOZOIC GAS 

X PALEOZOIC GAS 

~~ ~ X::~ + X ~ + X+ ~X ¢ 

++ 

.Q- ~:'X ~X + 

X elf·~~ ~~ + + 

Xx X X ,v X x,;~ + + ,~+ ;<;: >+- cJi!' ~X <{)> 

+ 

4+ 

X c{l> + 

{> ~ 

<{? + 

X 

3 

+ 

2 4 

EPR 

+ 

-80~~--------------~------------~--------------~ 

0.01 0.1 1 10 

Figure 12. A plot of methane o13C versus 3He/'i-le (expressed as R/RA, or ratio in sample 

divided by ratio in air) for 133 commercial gases from Thailand, western Canada, United 

States, and central Europe (references listed in fig. 5). Lines illustrate mixing paths between hypothetical ·endmernbers with (CHi3

He)crustai:(CH4PHe)magmatic=400. Endmember 

2 is similar to several nitrogen-rich gases from the California Great Valley (GV) which are 

interpreted to originate from subducted metasedimentary rocks (Jenden and others, 1988a). 

EPR, geothermal fluids from 21° N. East Pacific Rise (Welhan and Craig, 1983); ZO, gas 

seeps from the Zambales Ophiolite in the Philippines (Abrajano and others, 1988). 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 49 

NONHYDROCARBON GASES 

Nitrogen and carbon dioxide compose less than 5 percent of most natural gases but can occur at concentrations 

in excess of 50 percent. Such high concentrations severely 

diminish natural-gas heating values, creating economic 

problems for gas producers. The origin of nitrogen- and 

carbon-dioxide-rich gases is not understood, but 3HefHe 

measurements suggest, in some instances, the presence of 

a magmatic gas component. 

Due to the paucity of available data, it is difficult to 

evaluate whether the mantle itself is an important source of 

nitrogen in natural gases. However, mantle volatiles may 

strip nitrogen from the deep crust. Nitrogen-rich fluid inclusions are commonly reported in metasedimentary rocks 

(K.reulen and Schuiling, 1982; Glassley and others, 1984; 

Darimont and others, 1988), where they may form by the 

oxidation of ammonium in silicate minerals (Honma and 

ltihara, 1981; Bos and others, 1988). On the basis of their 

geological occurrence and their association with methane 

b13C values as heavy as -15 permil, 3He/'1-le ratios of 1 RA, 

and N2/Ar ratios up to 22,000, nitrogen-rich gases in the 

California Great Valley are thought to have originated from 

subducted metasedimentary rocks underplating the crust 

(Jenden and others, 1988a). b15N data for Great Valley nitrogen gas (0.9 to 3.5 permil) and b15N values of total 

nitrogen in Franciscan Complex-equivalent rocks (1.9 to 4.3 

permil; Bebout and Fogel, 1992) support this conclusion. 

In contrast to the uncertainty surrounding deep sources 

of nitrogen, mantle-derived carbon dioxide is widely recognized in hot springs, volcanic and geothermal gases, and 

carbonatite magmas. Bicarbonate-rich springs are commonly associated with zones of major seismicity, Tertiary to 

present-day volcanism, and elevated 3HefHe ratios, indicating the presence of mantle-derived volatiles (Irwin and 

Barnes, 1980; Matthews and others, 1987; Griesshaber and 

others, 1992). Carbon isotope studies suggest that faulting 

and igneous activity have introduced magmatic carbon dioxide into gas reservoirs and coal seams in several Australian basins (Smith and Gould, 1980; Rigby and Smith, 

1981; Smith and others, 1985). Natural gases with 98 percent or more carbon dioxide, carbon dioxide b13C=-4 permil, and 3HefHe ratios near 3 RA have been reported from 

Queensland, Australia (Chivas and others, 1987), and New 

Mexico, United States (Staudacher, 1987), and probably 

have a magmatic origin. Chivas and others (1987) have 

proposed that the accumulation of magmatic carbon dioxide in shallow crustal reservoirs may be responsible for the 

occurrence of violent, near-surface explosions in regions of 

basaltic volcanism. 

A plot of carbon dioxide concentration versus b 13c for , 

140 commercial natural gases collected in this study is 

shown in figure 13. Gases with less than 40 percent carbon 

dioxide have b13C values ranging from -33 to +24 permil, 

reflecting a variety of crustal origins including hydrocarbon 

oxidation and kerogen decarboxylation (Irwin and others, 

1977; Krouse and others, 1988), microbial methanogenesis 

(Jenden and Kaplan, 1986), and oil field biodegradation 

(Dimitrakopoulos and Muehlenbachs, 1987; Jeffrey and 

others, 1991 ), Of particular interest is the fact that gases 

with 40 to 100 percent carbon dioxide have b13C values of 

-4±2 permil, outside the range of most marine carbonates. 

Similar observations have been made for carbon-dioxiderich gases in the Bekes Basin of Hungary (b 13C=-8 to -3 

permil; Clayton and others, 1990). Although b13c values in 

this range can be explained by mixing between organic and 

inorganic carbon sources, in tectonically active basins such 

data could indicate the presence of mantle carbon dioxide 

(approximately -4 permil; Marty and others, 1989, 1993; 

Javoy and Pineau, 1991; Poreda and others, 1992). 

In this study, 3He/'1-le measurements were made on 

five carbon-dioxide-rich gases, four from the United States 

and one from the Gulf of Thailand (table 2). Carbon dioxide concentration in these gases ranges from 61 to 97 percent, carbon dioxide b 13C values range from -6.1 to -2.9 

permil, and 3He/'i-Ie ratios range from 0.210 to 1.89 RAThe 3HefHe ratios are related to the age of the producing 

30r-----r-----r-----r-----~--~ 

20 

10 

-20 

-30 

• 

• 

• 

METHANOGENESIS AND 

OILFIElD 

• BIODEGRADATION 

ALTERATION OF 

~~~NATES 

..... ~ ~- _ _[-·--_II!_---__._ L 

I • •• •• • t 

1"' o13C = -4.0 (permil) 

J KEROGEN 

DECARBOXYlATION 

J HYDROCARBON 

OXIDATION 

-40 L...------1.-------L.-------l....---L---.....l 

0 20 40 60 80 100 

C02 (percent) 

Figure 13. 6 13C versus concentration of carbon dioxide in 

140 commercial natural gases from the United States and 

Thailand (this study; Jenden and Kaplan, 1989a). Brackets 

show ranges of 6 13C values expected for C02 derived from 

various sources. 
50 THE FUTURE OF ENERGY GASES 

Table 2. Chemical and stable isotopic composition of some COrrich natural gases (Jenden and Kaplan, 1989a). 

[Oz content less than or equal to 0.1 volume percent for all samples. Abbreviations as follows: Cret, Cretaceous; Jur, Jurassic; Mio, Miocene; Sil, Silurian; m, meters; 

ppm, parts per million; R/RA, ratio in sample divided by ratio in air; %, volume percent] 

Sample Reservoir Depth c, c2+ 

No. Field age (m) (%) (%) 

1299 Platong, Thailand Mio 2,097 24.3 4.001 

1037 Sheep Mountain, CO Jur 960 2.13 0.254 

1034 Sheep Mountain, CO Cret 959 4.21 0.278 

1192 Wildcat, WV Sit 2,490 13.0 0.138 

1074 Indian Creek, WV Sil 2,058 33.4 0.277 

rocks and reflect dilution in the reservoir with radiogenic 

helium. Platong gas (1.89 RA) is produced from Miocene 

sandstone, Sheep Mountain gas (0.98 to 1.02 RA) is produced from Jurassic and Cretaceous sandstones, and the 

West Virginia wildcat and Indian Creek gases (0.210 and 

0.331 RA) are produced from Silurian sandstones. Past 

tectonic activity may be a common factor in the origin of 

these gases: the Sheep Mountain field is closely associated 

with Tertiary intrusive rocks, the West Virginia wildcat 

and Indian Creek field are located near the eastern United 

States overthrust belt, and the Platong field produces from 

a rift basin with high heat flow; Carbon isotope data do 

not permit distinction between a magmatic source and a 

mixture of crustal carbonate and organic carbon sources, 

but the C02/

3

He ratios of the Sheep Mountain, West Virginia wildcat, and Indian Creek samples are very close to 

the estimated bulk -earth degassing ratio of 2x 109 (Marty 

and Jambon, 1987). The high co2PHe ratio of the Platong 

sample (lxl010) may indicate some contamination with 

crustal carbon. 

CONCLUDING REMARKS 

As we have noted earlier, the economic significance of 

magmatic volatiles in oil and gas fields cannot be estimated without quantitative assumptions regarding methane 

o13C values, 3He/4He ratios, and CH4t3He ratios in gases 

of mantle and crustal origins. Reasonable estimates for 

these parameters suggest that commercial accumulations 

of abiogenic hydrocarbons have not been discovered by 

the petroleum industry. Methane o13C values in oil and 

gas fields exhibit a sharp mode near -42 penni!, and 97.6 

percent of the available measurements are lighter (more 

negative) than -25 penni!, characteristics compatible with 

biogenic sources but inconsistent with gases known to be 

abiogenic. While superficially similar to the patterns observed for some abiogenic gases, isotopic distributions in 

which methane o13c > ethane o13c, ethane o13c > propane o13c, or propane o13c > n-butane o13C, can be exC02 N2 He ll13C(CH4) ll13C(CO,) 'He/4

He C~/'He 

(%) (%) (ppm) (permil) (permil) (RIR.J (xiO") 

71.9 0.800 24.8 -39.2 -6.1 1.89 11.0 

97.3 0.666 180 -40.8 -4.1 0.980 3.94 

94.8 1.54 612 -41.1 -4.0 1.02 1.09 

83.5 2.23 1060 -35.7 -3.5 0.331 1.70 

61.3 2.73 1140 -34.5 -2.9 0.210 1.83 

plained by isotopic heterogeneities in sedimentary organic 

matter, and by mixing and oxidation of biogenic gas. Helium isotope ratios in oil and gas fields vary from 0.004 to 

7.5 RA, indicating mixing between crustal helium of radiogenic origin and helium derived from the mantle. Calculations assuming a magmatic component with a C~ PHe 

ratio similar to that in gas from hydrothermal vents at 

21 oN. on the East Pacific Rise suggest that far less than 1 

percent of the methane in most oil and gas fields is of 

abiogenic origin. 

These findings are subjecf to several qualifications: 

I. By themselves, methane o13c values are not a very 

reliable means of distinguishing abiogenic and biogenic 

sources. Abiogenic methane with o13C < -25 penni! can be 

produced by Fischer-Tropsch synthesis (Lancet and 

Anders, 1970; Yuen and others, 1990) and may be widespread in crystalline cratonic rocks (Laier, 1988; Sherwood and others, 1988). Isotopically light abiogenic 

carbon is well known in diamonds and meteorites (Deines, 

1980b; Pillinger, 1984). On the other hand, Chung and 

Sackett (1979) have shown that isotopically heavy biogenic methane can be produced by laboratory pyrolysis of 

high-rank coals. Therefore, methane with ()13C > -20 permil could originate in low-grade metasedimentary rocks 

and is not necessarily abiogenic. 

2. The light hydrocarbon gas o13C distribution observed for fluid inclusions in igneous rocks and meteorites 

may not be characteristic of abiogenic hydrocarbons in 

general. Even if it were, few o13C data for C2+ hydrocarbons have been published for very dry commercial gases 

(C2+/total hydrocarbons < I percent), so many isotopic reversals might be undiscovered. 

3. Calculations have assumed a radiogenic crustal 

3

He/'l-Ie ratio of only 0.01 RA- Because much higher ratios may be produced by uncommon crystalline and sedimentary rock types rich in Li and by helium contributions 

from cosmic dust (Andrews, 1985; Hiyagon and Kennedy, 

1992), the abundance of abiogenic methane in some fields 

(for example, the supergiant Hugoton) may have been seriously overestimated. 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 51 

4. Calculations of abiogenic methane abundance depend on CH4PHe ratios of mantle fluids in apparently uncontaminated geothermal and volcanic systems; these 

ratios vary by more than three orders of magnitude. The 

highest ratios (approximately 100xl06) suggest that abiogenic methane could account for as much as 20 percent of 

the gas produced from a number of small, circum-Pacific 

basin accumulations. Most, if not all, of these hydrocarbons could have been generated by contact of hot magmatic fluids with organic-rich sedimentary rocks. On the 

other hand, the overall abundance of abiogenic methane 

could be seriously underestimated if reduction of magmatic carbon dioxide to methane in the crust is more extensive than predicted from volcanic and geothermal data. 

Theoretically, at least, "magmatic" CH4PHe ratios could 

approach the average upper mantle cPHe ratio of 2x 109 

(Marty and Jambon, 1987). 

The conclusion that abiogenic methane is not a commercial resource is consistent with findings from the 

Gravberg I well at the Siljan Ring in Sweden (Juhlin and 

others, 1991; Castano, this volume). Drilled, in part, to 

test the "deep-earth gas" hypothesis (Fish, 1986), the 

Gravberg 1 well penetrated a fractured granite structure 

which was thought to be capped by an impermeable seal 

of calcite cement. No commercial reserves were discovered, but several thin dolerite sills yielded minor shows of 

presumably abiogenic methane with less than 10 percent 

c2+ hydrocarbons and methane o13C values ranging from 

-26 to -11 permil (Laier, 1988; Jeffrey and Kaplan, 1988). 

Perhaps due to the great age of the country rock, gas samples uncontaminated by air yielded typical crustal 3He/4He 

ratios of approximately 0.02 RA (Hilton and Craig, 1989). 

ACKNOWLEDGMENTS 

We gratefully acknowledge the many oil companies 

that provided gas samples and well data for the GRI natural-gas study. Special thanks for assistance in collecting 

samples for helium isotope analysis are due Dudley Rice 

and Chuck Threlkeld at the U.S. Geological Survey in 

Denver, David Newell and Lynn Watney at the Kansas 

Geological Survey, and Don Drazan at the New York State 

Department of Environmental Conservation. We are indebted to Martin Drut and others at Global Geochemistry 

Corporation who measured gas compositions and carbon 

isotope ratios on what seemed to be innumerable samples. 

Robert Poreda made many of the helium isotope measurements and provided valuable comments and assistance. 

Helpful discussions and critical support were provided 

throughout the project by Ferol Fish, Paul Wescott, and 

Anthony Gorody of the Gas Research Institute. 

We wish to express our gratitude to Barbara Sherwood-Lollar and Joel Leventhal, who went out of their 

way to provide rapid and thoughtful reviews of this paper. 

Chevron Petroleum Technology Company kindly supported us with drafting and word processing. Research funding 

was provided by the Gas Research Institute, contract no. 

5081-360-0533. 

REFERENCES CITED 

Abrajano, T.A., Sturchio, N.C., Bohlke, J.K;, Lyon, G.L., Poreda, 

R.J., and Stevens, C.M., 1988, Methane-hydrogen gas seeps, 

Zambales Ophiolite, Philippines-Deep or shallow origin?, 

in Schoell, M., ed., Origins of methane in the Earth, Chemical Geology, v. 71, p. 211-222. 

Abrajano, T.A., Sturchio, N.C., Kennedy, B.M., Lyon, G.L., 

Muehlenbachs, K., and Bohlke, J.K., 1990, Geochemistry of 

reduced gas related to serpentinization of the Zambales 

Ophiolite, Philippines: Applied Geochemistry, v. 5, p. 625-

630. 

Aldrich, L.T., and Nier, A.O., 1948, The occurrence of 3He in 

natural sources of helium: Physical Review, v. 74, p. 1590-

1594. 

Andrews, J.N., 1985, The isotopic composition of radiogenic helium and its use to study groundwater movement in confined 

aquifers: Chemical Geology, v. 49, p. 339-351. 

Ballentine, C.J., and O'Nions, R.K., 1991, The nature of mantle 

neon contributions to Vienna Basin hydrocarbon reservoirs: 

Earth and Planetary Science Letters, v. 113, p. 553-567. 

Ballentine, C.J., O'Nions, R.K., Oxburgh, E.R., Horvath, F., and 

Deak, J ., 1991, Rare gas constraints on hydrocarbon accumulation, crustal degassing and groundwater flow in the 

Pannonian Basin: Earth and Planetary Science Letters, 

v. 105, p. 229-246. 

Barker, J.F., and Pollock, S.J., 1984, The geochemistry and origin of natural gases in southern Ontario: Bulletin of Canadian Petroleum Geology, v. 32, p. 313-326. 

Bebout, G.E., and Fogel, M.L., 1992, Nitrogen-isotope compositions of metasedimentary rocks in the Catalina Schist, California-Implications for metamorphic devolatilization history: 

Geochimica et Cosmochimica Acta, v. 56, p. 2839-2849. 

Bos, A., Duit, W., van der Eerden, A.M.J., and Jensen, J.B.H., 

1988, Nitrogen storage in biotite-An experimental study of 

the ammonium and potassium partitioning between IMphlogopite and vapor at 2 Kb: Geochimica et Cosmochimica 

Acta, v. 52, p. 1275-1283. 

Chang, S., Des Marais, D., Mack, R., Miller, S.L., and Strathearn, G.E., 1983, Prebiotic organic synthesis and the origin 

of life, in Schopf, J.W., ed., Earth's earliest biosphere, its 

origin and evolution: Princeton, N.J., Princeton University 

Press, p. 54-92. 

Chivas, A.R., Barnes, I., Evans, W.C., Lupton, J.E., and Stone, 

J.O., 1987, Liquid carbon dioxide of magmatic origin and its 

role in volcanic eruptions: Nature, v. 326, p. 587-589. 

Chung, H.M., Gormly, J.R., and Squires, R.M., 1988, Origin of 

gaseous hydrocarbons in subsurface environments; theoretical considerations of carbon isotope distribution, in Schoell, 

M., ed., Origins of methane in the Earth: Chemical Geology, 

v. 71, p. 97-103. 

Chung, H.M., and Sackett, W.M., 1979, Use of stable carbon 

isotope compositions of pyrolytically derived methane as 
52 THE FUTURE OF ENERGY GASES 

maturity indices for carbonaceous materials: Geochimica et 

Cosmochimica Acta, v. 43, p. 1979-1988. 

---1980, Carbon isotope effects during the pyrolytic formation of early methane from carbonaceous materials, in Douglas, A.G., and Maxwell, J.R., eds., Advances in organic 

geochemistry 1979: New York, Pergamon Press, p. 705-710. 

Claypool, G.E., Threlkeld, C.N., and Magoon, L.B., 1980, Biogenic and thermogenic origins of natural gas in Cook Inlet 

basin, Alaska: American Association of Petroleum Geologists Bulletin, v. 64, p. 1131-1139. 

Clayton, C., 1991, Carbon isotope fractionation during natural 

gas generation from kerogen: Marine and Petroleum Geology, v. 8, p. 232-240. 

Clayton, J.L., Spencer, C.W., Koncz, I., and Szalay, A., 1990, 

Origin and migration of hydrocarbon gases and carbon dioxide, Bekes Basin, southeastern Hungary: Organic Geochemistry, v. 15, p. 233-247. 

Colombo, U., Gazzarrini, F., Gonfiantini, R., Sironi, G., and Tongiorgi, E., 1966, Measurements of 13C/12C isotope ratios on 

Italian natural gases and their geochemical interpretation, in 

Hobson, G.D., and Louis, M.C., eds., Advances in organic 

geochemistry 1964: New York, Pergamon Press, p. 279-292. 

Craig, H., 1953, The geochemistry of the stable carbon isotopes: 

Geochimica et Cosmochimica Acta, v. 3, p. 53-92. 

Craig, H., Kim, K-R., and Rison, W., 1984, Easter Island Hotspot-!. Bathymetry, helium isotopes, and hydrothermal 

methane and helium [abs.]: EOS, v. 65, p. 1140. 

Craig, H., and Lupton, J.E., 1981, Helium-3 and mantle volatiles 

in the ocean and the oceanic crust, in Emiliani, C., ed., The 

sea, v. 7: New York, John Wiley and Sons, p. 391-428. 

Craig, H., Lupton, J.E., and Horibe, Y., 1978, A mantle helium 

component in circum-Pacific volcanic gases-Hakone, the 

Marianas and Mt. Lassen, in Alexander, E.C., and Ozima, 

M., eds., Terrestrial rare gases: Tokyo, Japan Scientific Society Press, p. 3-16. 

Darimont, A., Burke, E., and Touret, J., 1988, Nitrogen-rich fluids in Devonian metasediments from Bastogne, Belgium: 

Bulletin de Mineralogie, v. Ill, p. 321-330. 

Deines, P., 1980a, The isotopic composition of reduced organic 

carbon, in Fritz, P., and Fontes, J., eds., Handbook of environmental isotope geochemistry, v. 1: New York, Elsevier, 

p. 329-406. 

---1980b, The carbon isotopic composition of diamonds; relationship to diamond shape, color, occurrence and vapor 

composition: Geochimica et Cosmochimica Acta, v. 44, 

p. 943-961. 

Des Marais, D.J., 1985, Carbon exchange between the mantle 

and the crust, and its effect upon the atmosphere-Today 

compared to Archean time, in Sundquist, E.T., and Broecker, 

W.S., eds., The carbon cycle and atmospheric C02 natural 

variations Archean to present: Geophysical Monograph 32, 

American Geophysical Union, Washington D.C., p. 602-

611. 

Des Marais, D.J., Donchin, J.H., Nehring, N.L., and Truesdell, 

A.H., 1981, Molecular carbon isotopic evidence for the origin of geothermal hydrocarbons: Nature, v. 292, p. 826-828. 

Des Marais, D.J., Stallard, M.L., Nehring, N.L., and Truesdell, 

A.H., 1988, Carbon isotope geochemistry of hydrocarbons 

in the Cerro Prieto geothermal field, Baja California Norte, 

Mexico: Chemical Geology, v. 71, p. 159-167. 

Dimitrakopoulos, R., and Muehlenbachs, K., 1987, Biodegradation of petroleum as a source of 13C-enriched carbon dioxide in the formation of carbonate cement: Chemical Geology 

(Isotope Geoscience Section), v. 65, p. 283-291. 

Dott, R.H., Sr., and Reynolds, M.J., 1969, Sourcebook for petroleum geology: American Association of Petroleum Geologists Memoir 5, 471 p. 

Erdman, J.G., and Morris, D.A., 1974, Geochemical correlation 

of petroleum: American Association of Petroleum Geologists 

Bulletin, v. 58, p. 2326-2337. 

Fish, F., 1986, GRI's basic research on gas origin, migration: Oil 

and Gas Journal, lO February, p. 118-126. 

Fuex, A.N., 1977, The use of stable carbon isotopes in hydrocarbon exploration: Journal of Geochemical Exploration, v. 7, 

p. 155-188. 

Galimov, E.M., 1975, Carbon isotopes in oil-gas geology: U.S. 

Department of Commerce, National Technical Information 

Service, N75-27563, 395 p. 

---1988, Sources and mechanisms of formation of gaseous hydrocarbons in sedimentary rocks, in Schoell, M., ed., Origins 

of methane in the Earth: Chemical Geology, v. 71, p. 77-95. 

---1991, Isotope fractionation related to kimberlite magmatism and diamond formation: Geochimica et Cosmochimica 

Acta, v. 55, p. 1697-1708. 

Galimov, E.M., Ivlev, A.A., and Kuznetsova, N.G., 1970, Carbon 

isotope composition of gaseous hydrocarbons in petroleum 

and the problem of their origin: Geochemistry International, 

v. 7, p. 594-603. 

Galimov, E.M., Teplinskiy, G.I., Tabassaranskiy, Z.A., and 

Gavrilov, E.Ye., 1973, On the conditions of formation of gas 

deposits in the eastern part of the Turan plate as revealed by 

the carbon isotopic composition of the gases: Geochemistry 

International, v. 10, p. 1259-1271. 

Garno, T., Ishibashi, J-I., and Sakai, H., 1987, Methane anomalies 

in seawater above the Loihi submarine summit area, Hawaii: 

Geochimica et Cosmochimica Acta, v. 51, p. 2857-2864. 

Gerlach, T.M., 1980, Chemical characteristics of the volcanic 

gases from Nyiragongo Lava Lake and the generation of 

CH4-rich fluid inclusions in alkaline rocks: Journal of Volcanology and Geothermal Research, v. 8, p. 177-189. 

Giardini, A.A., and Melton, C.E., 1983, A scientific explanation 

for the origin and location of petroleum accumulations: 

Journal of Petroleum Geology, v. 5, p. 117-138. 

Giggenbach, W.F., 1982, Carbon-13 exchange between C02 and 

CH4 under geothermal conditions: Geochimica et Cosmochimica Acta, v. 46, p. 159-165. 

Glassley, W.E., Bridgwater, D., and Konnerup-Madsen, J., 1984, 

Nitrogen in fluids effecting retrogression of granulite facies 

gneisses-A debatable mantle connection: Earth and Planetary Science Letters, v. 70, p. 417-425. 

Gold, T., 1979, Terrestrial sources of carbon and earthquake outgassing: Journal of Petroleum Geology, v. I, p. 3-19. 

---1985, The origin of natural gas and petroleum, and the 

prognosis for future supplies: Annual Review of Energy, 

v. 10, p. 53-77. 

---1987, Power from the Earth: London, Dent and Sons, 208 p. 

Gold, T., Gordon, B.E., Street,W., Bilson, E., and Patnaik, P., 

1986, Experimental study of the reaction of methane with 

petroleum hydrocarbons in geological conditions: Geochimica et Cosmochimica Acta, v. 50, p. 2411-2418. 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 53 

Gold, T., and Held, M., 1987, Helium-nitrogen-methane systematics in natural gases of Texas and Kansas: Journal of Petroleum Geology, v. 10, p. 415--424. 

Gold, T., and Soter, S., 1980, The deep-earth gas hypothesis: Scientific American, v. 242, no. 6, p. 154-161. 

---1982, Abiogenic methane and the origin of petroleum: 

Energy Exploration and Exploitation, v. 1, p. 89-104. 

---1985, Fluid ascent through the solid lithosphere and its 

relation to earthquakes: Pure and Applied Geophysics, 

v. 122, p. 492-530. 

Griesshaber, E., O'Nions, R.K., and Oxburgh, E.R., 1992, Helium and carbon isotope systematics in crustal fluids from the 

Eifel, the Rhine Graben and Black Forest, F.R.G.: Chemicaf 

Geology, v. 99, p. 213-235. 

Gwilliam, W.J., 1982, Subducted origin hypothesis for deepsource methane, in Gwilliam, W.J., ed., Deep Source Gas 

Workshop: Technical Proceedings: Morgantown Energy 

Technology Center, U.S. Department of Energy, DOE/ 

METC-82-50, p. 140-161. 

Haggerty, S.E., 1986, Diamond genesis in a multiply-constrained 

model: Nature, v. 320, p. 34-38. 

Hilton, D.R., and Craig, H., 1989, The Siljan deep well-Helium 

isotope results: Geochimica et Cosmochimica Acta, v. 53, 

p. 3311-3316. 

Hilton, D.R., Jenden, P.D., Jeffrey, A.W.A., Kaplan, 1., and Craig, 

H., 1988, Helium isotopes in continental natural gases; results from Siljan, the Hugoton Panhandle and Appalachian 

Basin [abs.]: Chemical Geology, v. 70, 202 p. 

Hiyagon, H., and Kennedy, B.M., 1992, Noble gases in CH4-rich 

gas fields, Alberta, Canada: Geochimica et Cosmochimica 

Acta, v. 56, p. 1569-1589. 

Honma, H., and ltihara, Y., 1981, Distribution of ammonium in 

minerals of metamorphic and granitic rocks: Geochimica et 

Cosmochimica Acta, v. 45, p. 983-988. 

Hooker, P.J., Onions, R.K., and Oxburgh, E.R., 1985, Helium 

isotopes in North Sea gas fields and the Rhine rift: Nature, 

v. 318.p. 273-275. 

Hunt, C.W., Collins, L.G., and Skobelin, E.A., 1992, Expanding 

geospheres-Energy and mass transfers from Earth's interior: Calgary, Polar Publishing, 421 p. 

Irwin, H., Curtis, C., and Coleman, M., 1977, Isotopic evidence 

for source of diagenetic carbonates formed during burial of 

organic-rich sediments: Nature, v. 269, p. 209-213. 

Irwin, W.P., and Barnes, I., 1980, Tectonic relations of carbon 

dioxide discharges and earthquakes: Journal of Geophysical 

Research, v. 85 (B6), p. 3115-3121. 

James, A.T .• 1983, Correlation of natural gas by use of carbon 

isotopic distribution between hydrocarbon components: · 

American Association of Petroleum Geologists Bulletin, 

v. 67, p. 1176-1191. 

---1990, Correlation of reservoired gases using the carbon isotopic compositions of wet gas components: American Association of Petroleum Geologists Bulletin, v. 74, p. 1441-1458. 

James, A.T., and Bums, B.J., 1984, Microbial alteration of subsurface natural gas accumulations: American Association of 

Petroleum Geologists Bulletin, v. 68, p. 957-960. 

Javoy, M., and Pineau, F., 1991, The volatiles record of a "popping" rock from the Mid-Atlantic Ridge at 14° N-Chemical and isotopic composition of gas trapped in the vesicles: 

Earth and Planetary Science Letters, v. 107, p. 598-611. 

Jean-Baptiste, P., Charlou, J.L., Stievenard, M., Donval, J.P., 

Bougault, H., and Mevel C., 1991, Helium and methane 

measurements in hydrothermal fluids from the mid-Atlantic 

ridge-The Snake Pit site at 23° N.: Earth and Planetary 

Science Letters, v. 106, p. 17-28. 

Jeffrey, A.W.A., 1981, Thermal and clay catalyzed cracking in 

the formation of natural gas: College Station, Texas A&M 

University, Ph.D. dissertation, 123 p. 

Jeffrey, A.W.A., Alimi, M.H .• and Jenden, P.D., 1991, Geochemistry of Los Angeles Basin oil and gas systems, in Biddle, 

K.T .• ed., Active margin basins: American Association of Petroleum Geologists Memoir 52: p. 197-219. 

Jeffrey, A.W.A .• and Kaplan, I.R., 1988, Hydrocarbons and inorganic gases in the Gravberg-1 well, Siljan Ring, Sweden, in 

Schoell, M., ed., Origins of methane in the Earth: Chemical 

Geology, v. 71, p. 237-255. 

Jenden, P.D., Drazan, D.J., and Kaplan, I.R., 1993, Mixing of 

thermogenic natural gases in northern Appalachian basin: 

American Association of Petroleum Geologists Bulletin, 

v. 77, p. 980-998. 

Jenden P.D., and Kaplan, I.R., 1986, Comparison of microbial 

gases from the Middle America trench and Scripps Submarine canyon; implications for the origin of natural gas: Applied Geochemistry, v. 1, p. 631-646. 

---1989a, Analysis of gases in the Earth's crust: Final report 

to the Gas Research Institute, Chicago, Contract No. 5081-

360-0533. National Technical Information Service, Accession Number PB91-104273/XAB. 

---1989b, Origin of natural gas in the Sacramento basin, 

California: American Association of Petroleum Geologists 

Bulletin, v. 73, p. 431--453. 

Jenden, P.D .• Kaplan, I.R., Poreda, R.J., and Craig, H., 1988a, 

Origin of nitrogen-rich natural gases in the California Great 

Valley; evidence from helium, carbon and nitrogen isotope 

ratios: Geochimica et Cosmochimica Acta, v. 52, p. 851-861. 

Jenden, P.D., Newell, K.D., Kaplan, I.R., and Watney, W.L., 1988b, 

Composition and stable isotope geochemistry of natural gases 

from Kansas, Midcontinent, U.S.A. in Schoen, M., ed., Origins 

of methane in the Earth: Chemical Geology, v. 71, p. 117-147. 

Jianyu, C., and Bingjun, H., 1990, The character and genesis of 

condensate in the north of Liaodong Bay, China: Organic 

Geochemistry, v. 16, p. 561-567. 

Johnson, R.C .• and Rice, D.D., 1990, Occurrence and geochemistry of natural gases, Piceance Basin, northwest Colorado: 

American Association of Petroleum Geologists Bulletin, 

v. 74. p. 805-829. 

Juhlin, C., and others, 1991, Scientific summary report of the 

deep gas drilling project in the Siljan Ring impact structure: 

Stockholm, Vattenfall, 257 p. 

Kamenskiy, I.L., Lobkov, V.A., Prasolov, E.M., Beskrovnyy, 

N.S., Kudryavtseva, E.I., Anufriyev, G.S., and Pavlov, V.P., 

1976, Components of the upper mantle in the volcanic gases 

of Kamchatka (according to He, Ne, Ar, and C isotopy): Geochemistry International, v. 13, p. 35--48. 

Kamenskiy, I.L., Yakutseni, V.P., Mamyrin, B.A., Anufriyev, 

S.G., and To1stikhin, I.N, 1971, Helium isotopes in nature: 

Geochemistry International, v. 8, p. 575-589. 

Kiyosu, Y .• and Krouse, H.R .• 1989, Carbon isotope effect during 

abiogenic oxidation of methane: Earth and Planetary Science 

Letters, v. 95, p. 302-306. 
54 THE FUTURE OF ENERGY GASES 

Konnerup-Madsen, J., Kreulen, R., and Rose-Hansen, J., 1988, 

Stable isotope characteristics of hydrocarbon gases in the alkaline Ilimaussaq complex, South Greenland: Bulletin de 

Mineralogie, v. 111, p. 567-576. 

Kotarba, M., 1990, Isotopic geochemistry and habitat of the natural gases from the Upper Carboniferous Zacler coal-bearing 

formation in the Nowa Ruda coal district (Lower Silesia, 

Poland): Organic Geochemistry, v. 16, p. 549-560. 

Kreulen, R., 1987, Thermodynamic calculations of the C-0-H system applied to fluid inclusions-Are fluid inclusions unbiased 

samples of ancient fluids?: Chemical Geology, v. 61, p. 59-64. 

Kreulen, R., and Schuiling, R.D., 1982, N2-CH4-C02 fluids during formation of the Dome de I' Agout, France: Geochimica 

et'Cosmochimica Acta, v. 46, p. 193-203. 

Kropotkin, P.N., 1985, Degassing of the earth and the origin of 

hydrocarbons: International Geology Review, v. 27, p. 1261-

1275. 

Kropotkin, P.N., and Valiaev, B.M., 1976, Development of a theory 

of deep-seated (inorganic and mixed) origin of hydrocarbons, 

in Vassoevich, N.B., and others, eds., Combustible mineral 

resources, problems of geology and geochemistry of petroleum bitumen and bituminous rocks: Akademia Nauk SSSR, 

p. 133-144. [See Marland (1984) for English translation.] 

Krouse, H.R., Viau, C.A., Eliuk, L.S., Ueda, A., and Halas, S., 

1988, Chemical and isotopic evidence of thermochemical 

sulphate reduction by light hydrocarbon gases in deep carbonate reservoirs: Nature, v. 333, p. 415-419. 

Laier, T., 1988, Hydrocarbon gases in the crystalline rocks of the 

Gravberg-1 well, Swedish deep gas project: Marine and Petroleum Geology, v. 5, p. 370-377. 

Lancet, M.S., and Anders, E., 1970, Carbon isotope fractionation 

in the Fischer-Tropsch synthesis and in meteorites: Science, 

v. 170, p. 980-982. 

Lawrence, J.R., and Taviani, M., 1988, Extreme hydrogen, oxygen and carbon isotope anomalies in the pore waters and 

carbonates of the sediments and basalts from the Norwegian 

Sea; methane and hydrogen from the mantle?: Geochimica 

et Cosmochimica Acta, v. 52, p. 2077-2083. 

Lewan, M.D., 1986, Stable carbon isotopes of amorphous kerogens from Phanerozoic sedimentary rocks: Geochimica et 

Cosmochimica Acta, v. 50, p. 1583-1591. 

MacDonald, G.J., 1983, The many origins of natural gas: Journal 

of Petroleum Geology, v. 5, p. 341-362. 

Mamyrin, B.A., and Tolstikhin, L.N., 1984, Helium isotopes in 

nature: New York, Elsevier, 273 p. 

Mango, F.D., 1987, An in variance in the isoheptanes of petroleum: Science, v. 237, p. 514-517. 

Marland, G., 1984, A workshop on the origin of natural gas: 

Final report to the Gas Research Institute, contract no. 5082-

260-0624, Gas Research Institute, Chicago. 

Martel, D.J., O'Nions, R.K., Hilton, D.R., and Oxburgh, E.R., 

1990, The role of element distribution in production and release of radiogenic helium; the Cammenellis Granite, southwest England: Chemical Geology, v. 88, p. 207-221. 

Marty, B., and Jambon, A., 1987, CPHe in volatile fluxes from 

the solid earth-Implications for carbon geodynamics: Earth 

and Planetary Science Letters, v. 83, p. 16-26. 

Marty, B., Jambon, A., and Sano, Y., 1989, Helium isotopes and 

C02 in volcanic gases of Japan: Chemical Geology, v. 76, 

p. 25-40. 

Marty, B., Meynier, V., Nicolini, E., Griesshaber, E., and Toutain, 

J.P., 1993, Geochemistry of gas emanations-A case study of 

the Reunion Hot Spot, Indian Ocean: Applied Geochemistry, 

v. 8, p. 141-152. 

Masters, C.D., Root, D.H., and Attanasi, D., 1992, World resources of crude oil and natural gas, in Proceedings of the 

Thirteenth World Petroleum Congress, v. 4, Chichester, John 

Wiley and Sons, p. 51-64. 

Matthews, A., Fouillac, C., Hill, R., O'Nions, R.K., and Oxburgh, E.R., 1987, Mantle-derived volatiles in continental 

crust-The Massif Central of France: Earth and Planetary 

Science Letters, v. 85, p. 117-128. 

Mattavelli, L., Ricchiuto, T., Grignani, D., and Schoell, M., 

1983, Geochemistry and habitat of natural gases in Po 

Basin, Northern Italy: American Association of Petroleum 

Geologists Bulletin, v. 67, p. 2239-2254. 

McCarty, H.B., and Felbeck, G.T., Jr., 1986, High temperature 

simulation of petroleum formation-IV. Stable carbon isotope studies of gaseous hydrocarbons: Organic Geochemistry, v. 9, p. 183-192. 

North, F.K., 1982, Review of Thomas Gold's deep-earth gas hypothesis: Energy Exploration and Exploitation, v. I, p. 105-

110. 

Oxburgh, E.R., O'Nions, R.K., and Hill, R.I., 1986, Helium isotopes in sedimentary basins: Nature, v. 324, p. 632-635. 

Parnell, J., 1988, Migration of biogenic hydrocarbons into granites-A review of hydrocarbons in British plutons: Marine 

and Petroleum Geology, v. 5, p. 385-396. 

Petersil'ye, I.A., and Pripachkin, V.A., 1979, Hydrogen, carbon, 

nitrogen and helium in gases from igneous rocks: Geochemistry International, v. 16, no. 4, p. 50-55. 

Philp, R.P., and Brassell, S., 1986, Arguments against abiogenic 

origin for hydrocarbons: Chemical and Engineering News, 

15 December, p. 2ff. 

Pillinger, C.T., 1984, Light element stable isotopes in meteor- . 

ites-From grams to picograms: Geochimica et Cosmochimica Acta, v. 48, p. 2739-2766. 

Pippin, L., 1970, Panhandle-Hugoton Field, Texas-OklahomaKansas; the first fifty years, in Halbouty, M.T., ed., Geology 

of giant petroleum fields: American Association of Petroleum Geologists Memoir 14, p. 204-222. 

Planetary Sciences Unit, University of Cambridge, 1982, Mantle 

methane-Fool's gold?: Nature, v. 300, p. 312-313. 

Poorter, R.P.E., Varekamp, J.C., Poreda, R.J., van Bergen, M.J., and 

Kreulen, R., 1991, Chemical and isotopic compositions of 

volcanic gases from the east Sunda and Banda arcs, Indonesia: 

Geochimica et Cosmochimica Acta, v. 55, p. 3795-3807. 

Poreda, R.J., and Craig, H., 1989, Helium isotope ratios in circum-Pacific volcanic arcs: Nature, v. 338, p. 473-478. 

Poreda, R.J., Craig, H., Amorsson, S., and Welhan, J.A., 1992, 

Helium isotopes in Icelandic geothermal systems; 1. 3

He, 

gas chemistry and 13C relations: Geochimica et Cosmochimica Acta, v. 56, p. 4221-4228. 

Poreda, R.J., Jeffrey, A.W.A., Kaplan, I.R., and Craig, M., 1988, 

Magmatic helium in subduction-zone natural gases, in 

Schoen, M., ed., Origins of methane in the Earth: Chemical 

Geology, v. 71, p. 199-210. 

Poreda, R.J., Jenden, P.D., Kaplan, I.R., and Craig, H., 1986, 

Mantle helium in Sacramento basin naturai gas wells: 

Geochimica et Cosmochimica Acta, v. 50, p. 2847-2853. 
ABIOGENIC HYDROCARBONS AND MANTLE HELIUM IN OIL AND GAS FIELDS 55 

Porfir'ev, V.B., 1974, Inorganic origin of petroleum: American 

Association of Petroleum Geologists Bulletin, v. 58, p. 3-33. 

---1975, Inorganic origin of petroleum; reply: American Association of Petroleum Geologists Bulletin, v. 59, p. 886-

889. 

Price, L.C., 1980, Utilization and documentation of vertical oil 

migration in deep basins: Journal of Petroleum Geology, 

v. 2, p. 353-387. 

Rice, D.D., 1983, Relation of natural gas composition to thermal 

maturity and source rock type in San Juan Basin, northwestem New Mexico and southwestern Colorado: American 

Association of Petroleum Geologists Bulletin, v. 67, p. 1199-

1218. 

Rice, D.D., Clayton, J.L., and Pawlewicz, M.J., 1989, Characterization of coal-derived hydrocarbons and source-rock potential of 

coal beds, San Juan Basin, New Mexico and Colorado, U.S.A.: 

Intemationa!Joumal of Coal Geology, v. 13, p. 597-626. 

Rice, D.D., and Threlkeld, C.N., 1990, Natural gas analyses from 

offshore Gulf of Mexico, in Gulf Coast oils and gasesTheir characteristics, origin, distribution, and exploration 

and production significance-Proceedings of the Ninth Annual Research Conference-SEPM: Denver, Society of Economic Paleontologists and Mineralogists, p. 367-371. 

Richet, P., Bottinga, Y., and Javoy, M., 1977, A review of hydrogen, carbon, nitrogen, oxygen, sulphur and chlorine stable 

isotope fractionation among gaseous molecules: Annual Review of Earth and Planetary Sciences, v. 5, p. 65-110. 

Rigby, D., and Smith, J.W., 1981, An isotopic study of gases and 

hydrocarbons in the Cooper basin: Australian Petroleum Exploration Association Journal 21, p. 222-229. 

Roedder, E., 1984, Fluid inclusions-Reviews in mineralogy, 

v. 12: Washington, Mineralogical Society of America. 644 p. 

Rohrback, B.G., Peters, K.E., and Kaplan, I.R., 1984, Geochemistry of artificially heated humic and sapropelic sediments11: Oil and gas generation: American Association of Petroleum Geologists Bulletin, v. 68, p. 961-970. 

Sackett, W.M., 1978, Carbon and hydrogen isotope effects during 

the thermocatalytic production of hydrocarbons in laboratory 

simulation experiments: Geochimica et Cosmochimica Acta, 

v. 42, p. 571-580. 

Sakata, S., 1991, Carbon isotopic geochemistry of natural gases 

from the Green Tuff Basin, Japan: Geochimica et Cosmochimica Acta, v. 55, p. 1395-1405. 

Sakata, S., Takahashi, M., Igari, S., and Suzuki, N., 1989, Origin 

of light hydrocarbons from volcanic rocks in the "Green 

Tuff' region of northeast Japan-Biogenic versus magmatic: 

Chemical Geology, v. 74, p. 241-248. 

Sano, Y., Wakita, H., and Giggenbach, W.F., 1987, Island arc tectonics of New Zealand manifested in helium isotope ratios: 

Geochimica et Cosmochimica Acta 51, p. 1855-1860. 

Schoell, M., 1983, Genetic characterization of natural gases: 

American Association of Petroleum Geologists Bulletin, 

v.67,p. 2225-2238. 

---1984a, Recent advances in petroleum isotope geochemis-

. try: Organic Geochemistry, v. 6, p. 645-663. 

---1984b, Wasserstoff- und Kohlenstoffisotope in organischen Substanzen, Erdolen und Erdgasen: Geologisches Jahrbuch D67, 164 p. 

Sherwood, B., Fritz, P., Frape, S.K., Macko, S.A., Weise, S.M., 

and Welhan, J.A., 1988, Methane occurrences in the Canadian Shield, in Schoell, M., ed., Origins of methane in the 

Earth: Chemical Geology, v. 71, p. 223-236. 

Smith, J.E., Erdman, J.G., and Morris, D.A., 1971, Migration, 

accumulation and retention of petroleum in the earth, in 8th 

World Petroleum Congress Proceedings, v. 2: London, Applied Science Publishers, p. 13-26. 

Smith, J.W., and Gould, K.W., 1980, An isotopic study of the 

role of carbon dioxide in outbursts in coal mines: Geochemical Journal, v. 14, p. 27-32. 

Smith, J.W., Gould, K.W., Hart, G.H., and Rigby, D., 1985, Isotopic studies of Australian natural and coal seam gases: Bulletin of the Australasian Institute of Mining and Metallurgy, 

v. 290, p. 43-51. 

Sofer, Z., 1985, An unusual occurrence of light hydrocarbon 

gases in a well offshore northeast Palawan Island, The Philippines: Precambrian Research, v. 30, p. 179-188. 

Stahl, W.J., Boigk, H., and Wollanke, G., 1977, Carbon and nitrogen isotope data of Upper Carboniferous and Rotliegend 

natural gases from North Germany and their relationship to 

the maturity of the organic source material, in Campos, R., 

and Goni, J., eds., Advances in organic geochemistry 1975: 

Madrid, ENADIMSA, p. 539-559. 

Stahl, W.J., and Carey, B.D., 1975, Source-rock identification by 

isotope analyses of natural gases from fields in the Val Verde 

and Delaware basins, West Texas: Chemical Geology, v. 16, 

p. 257-267. 

Staudacher, T., 1987, Upper mantle origin for Harding County 

well gases: Nature, v. 325, p. 605-607. 

Sundberg, K.R., and Bennett, C.R., 1983, Carbon isotope paleothermometry of natural gas, in Bjoroy, M., ed., Advances in 

organic geochemistry 1981: New York, John Wiley and 

Sons, p. 769-774. 

Szatmari, P., 1989, Petroleum formation by Fischer-Tropsch synthesis in plate tectonics: American Association of Petroleum 

Geologists Bulletin, v. 73, p. 989-998. 

Takach, N.E., Barker, C., and Kemp, M.K., 1987, Stability of 

natural gas in the deep subsurface; thermodynamic calculation of equilibrium composition: American Association of 

Petroleum Geologists Bulletin, v. 71, p. 322-333. 

Tanner, J.A., and Fuex, A.N., 1990, Chemical and isotopic evidence of the origin of hydrocarbons and source potential of 

rocks from the Vicksburg and Jackson Formations of Slick 

Ranch area, Starr County, Texas, in Gulf Coast oils and 

gases-Their characteristics, origin, distribution, and exploration and production significance-Proceedings of the Ninth 

Annual Research Conference-SEPM: Denver, Society of 

Economic Paleontologists and Mineralogists, p. 79-97. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and occurrence: New York, Springer-Verlag, 699 p. 

Treibs, A., and Himer, A., 1982, Is there an abiogenic formation 

of petroleum-Critical remarks on the thesis of Gold and 

Soter: Erdoel und Kohle, Erdgas Petrochemie, v. 35, p. 170-

172. 

Ulmer, G.C., Grandstaff, D.E., Weiss, D., Moats, M.A., Buntin, 

T.J., Gold, D.P., Hatton, C.J., Kadik, A., Koseluk, R.A., and 

Rosenhauer, M., 1987, The mantle redox state; an unfinished 

story?: Geological Society of America Special Paper 215, 

p. 5-23. 

Wakita, H., and Sano, Y., 1983, 3He/'lle ratios in CH4-rich natural 

gases suggest magmatic origin: Nature, v. 305, p. 792-794. 
56 THE FUTURE OF ENERGY GASES 

Wakita, H., Sano, Y., Urabe, A., and Nakamura, Y., 1990, Origin 

of methane-rich natural gas in Japan-Formation of gas 

fields due to large-scale submarine volcanism: Applied Geochemistry, v. 5, p. 263-278. 

Welhan, J.A., 1988, Origins of methane in hydrothermal systems: 

Chemical Geology, v. 71, p. 183-198. 

We1han, J.A., and Craig, H., 1979, Methane and hydrogen in 

East Pacific Rise hydrothermal fluids: Geophysical Research 

Letters, v. 6, p. 829-831. 

---1982, Abiogenic methane in mid-ocean ridge hydrothermal 

fluids, in Gwilliam, W.J., ed., Deep Source Gas Workshop, 

Technical Proceedings: DOE/METC-82-50, Morgantown Energy Technology Center, p. 122-129. 

---1983, Methane, hydrogen and helium in hydrothermal 

fluids at 21° N. on the East Pacific Rise, in Rona, P.A., 

Bostrom, K., Laubier, L., and Smith, K.L., Jr., eds., Hydrothermal processes at seafloor spreading centers: New York, 

Plenum Press, p. 391-409. 

Welhan, J.A., and Lupton, J.E., 1987, Light hydrocarbon gases in 

Guaymas basin hydrothermal fluids; thermogenic versus 

abiogenic origin: American Association of Petroleum Geologists Bulletin, v. 71, p. 215-223. 

Welhan, J.A., Poreda, R.J., Rison, W., and Craig, H., 1988, Helium isotopes in geothermal and volcanic gases of the western 

United States, I. Regional variability and magmatic origin: 

Journal of Volcanology and Geothermal Research, v. 34, 

p. 185-199. 

Whiticar, M.J., Faber, E., and Schoell, M., 1986, Biogenic methane formation in marine and freshwater environments; C02 

reduction vs. acetate fermentation-Isotope evidence: 

Geochimica et Cosmochimica Acta, v. 50, p. 693-709. 

Wood, B.J., Bryndzia, L.T., and Johnson, K.E., 1990, Mantle oxidation state and its relationship to tectonic environment and 

fluid speciation: Science, v. 248, p. 337-345. 

Yuen, G., Blair, N., Des Marais, D.J., and Chang, S., 1984, Carbon isotope composition of low molecular weight hydrocarbons and monocarboxylic acids from Murchison meteorite: 

Nature, v. 307, p. 252-254. 

Yuen, G.U., Pecore, i.A., Kerridge, J.F., Pinnavaia, T.J., Rightor, 

E.G., Flores, J., Wedeking, K., Mariner, R., Des Marais, 

D.J., and Chang, S., 1990, Carbon isotopic fractionation in 

Fischer-Tropsch type reactions [abs.]: XXI Lunar and Planetary Science Conference, Lunar and Planetary Institute, 

Houston, p. 1367-1368. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

The Origin of Methane in the Crust of the Earth 

By Thomas Gold 1 

CONTENTS 

Abstract . ... . . ... .. . ....... .. .. .. .. .. . . ... . .. ... . . ... . . . ... . .. . .. .. . .... .. ... . ... 57 

Introduction ................................................................... 58 

Debate About the Origin of Petroleum ........................ 58 

Advocates of the Abiogenic Theory .......... ........ .... .. .. .. 59 

The Formation Process of the Earth ... .... .... .. .. .... ...... ... 60 

The Theory of the Biological Origin of 

Hydrocarbons on Earth ................................................. 61 

Origin of the Carbon on the Earth .... .. .... ...... ...... ...... ... 62 

The Surface Carbon Budget ......................................... 63 

Thermodynamics of Outgassing................................... 65 

Horizontal and Vertical Patterns of Hydrocarbon 

Fields ............................................................................. 66 

Interpretations Based on Carbon Stable Isotopes ........ 68 

The Helium Association with Petroleum ..................... 71 

Relation of Outgassing of Hydrocarbons to 

Atmospheric Oxygen . . .... . ....... .... .. .. ... .. ....... ............ ...... 73 

The Mechanics of the Ascent of Fluids Through 

the Crust ........................................................................ 74 

Results in Sweden ........................................................ 76 

Conclusions ................................................................... 78 

References Cited .. .... ... . ... . ....... .... .. ... . . .. .... . .... ... .... .. .. .. ... 79 

ABSTRACT 

The deposits of hydrocarbons in the crust of the 

Earth have long been regarded by many investigators as 

being derived from materials incorporated in the mantle 

at the time of the Earth's formation. Outgassing process1

7 Pleasant Grove Lane, Ithaca, NY, 14850. 

es, active in all geological epochs, then transported the 

liquids and gases liberated there into porous rocks of the 

crust. The alternative viewpoint, that biological debris 

was the source material for crustal hydrocarbons, gained 

widespread acceptance when molecules of clearly biological origin were found to be usually present in hydrocarbon fluids. 

Modern information redirects attention to the theories 

of a nonbiological, primeval origin. Among this information is the prominence of hydrocarbons-gases, liquids, 

and solids-on many other bodies of the solar system, as 

well as in interstellar space. Advances in high-pressure 

thermodynamics have shown that the pressure-temperature regime of the Earth would allow hydrocarbon molecules to be formed and to survive between the surface 

and a depth of 1 00 to 300 km. Outgassing from such 

depth would bring up other gases present in trace 

amounts in the rocks, thus accounting for the known association of hydrocarbons with helium. Recent discoveries of the widespread presence of bacterial life at depth 

point to this as the origin of the biological content of petroleum. The carbon budget of the crust requires an outgassing process to have been active throughout the 

geologic record, and information from planets and meteorites, as well as from mantle samples, would suggest 

that methane rather than C02 could be the major source 

of surface carbon. Isotopic fractionation of methane in its 

migration through rocks is indicated by numerous observations, providing an alternative to biological processes 

that have been held responsible for such fractionation. Information from deep boreholes in granitic and volcanic 

rock of Sweden has given support to the theory of the 

migration of gas and oil from depth, to the occurrence of 

isotopic fractionation in migration, to an association with 

helium, and to the presence of microorganisms below 4 

km depth. 

57 
58 THE FUTURE OF ENERGY GASES 

INTRODUCTION 

The gas methane, CH4, the principal component of 

natural gas, does not contain sufficient evidence in itself 

from which to deduce its origin on the Earth. There is 

some evidence from its isotopic composition, but interpretations of that are not unique. Information, however, exists 

in the mode of occurrence of natural-gas reservoirs, in 

the geographic and geological relationships, in associated 

chemicals, and, above all, in the frequent association with 

other hydrocarbons, specifically crude petroleum and bituminous coal. Although there are numerous occurrences of 

natural gas without the heavier hydrocarbons, the association is generally so clear that one cannot contemplate an 

origin for the natural-gas deposits independent of those for 

petroleum. I shall therefore first consider the origin of the 

whole set of hydrocarbons, including natural gas, and then 

discuss aspects that are specific to methane. 

DEBATE ABOUT THE ORIGIN 

OF PETROLEUM 

It is remarkable that in spite of its widespread occurrence, its great economic importance, and the immense amount of fine research devoted to 

it, there perhaps still remain more uncertainties concerning the origin of 

petroleum than that of any other commonly occurring natural substance. 

H.D. Hedberg, 1964 

Actually it cannot be too strongly emphasized that petroleum does not 

present the composition picture expected from modified biogenic products, and all the arguments from the constituents of ancient oils fit equally well, or better, with the conception of a primordial hydrocarbon 

mixture to which bio-products have been added. 

Sir Robert Robinson, 1963 

President, Royal Society, London 

The capital fact to note is that petroleum was born in the depths of the 

Earth, and that it is only there that we must seek its origin. 

D. Mendeleev, 1877 

The ongm of petroleum has been a subject of many 

intense and heated debates, ever since this black fluid was 

first discovered in large quantities in the pore spaces of 

many rocks. Is it something brought in from space when 

the Earth was formed? Or is it a fluid concentrated from 

huge amounts of vegetation and animal remains that may 

have been buried in the sediments over hundreds of millions of years? 

Arguments have been advanced for each viewpoint, 

and although they conflict with each other, each line of 

argument sounds strangely convincing. In favor of the biogenic origin of petroleum, the following four observations 

have been advanced: 

1. Petroleum contains groups of molecules that are 

clearly identified as the breakdown products of complex, 

but common, organic molecules that occur in plants, and 

that could not have been built up in a nonbiological 

process. 

2. Petroleum frequently shows the phenomenon of optical activity, that is, a rotation of the plane of polarization 

when polarized light is passed through it. This property 

implies that molecules which can have either a right-handed or a left-handed symmetry are not equally represented, 

but that one symmetry is preferred. This property is normally a characteristic of biological materials and absent in 

fluids of nonbiological origin. 

3. Some petroleums show a clear preference for molecules with an odd number of carbon atoms over those with 

an even number. Such an odd-even effect can be understood as arising from the breakdown of a class of molecules that are common in biological substances, and may 

be difficult to account for in other ways. 

4. Petroleum is mostly found in sedimentary deposits 

and only rarely in the primary rocks of the crust below; 

even among the sedimentary deposits, it favors those that 

are geologically young. In many cases such sedimentary 

deposits appear to be rich in carbonaceous materials that 

were interpreted as of biological origin, and as source material for the petroleum deposit. 

On the other side of the argument, in favor of an origin from deeply buried materials incorporated in the Earth 

when it formed, the following observations have been 

cited: 

1. Petroleum and methane are found frequently in geographic patterns of long lines or arcs, which are related 

more to deep-seated large-scale structural features of the 

crust than to the smaller scale patchwork of the sedimentary deposits. 

2. Hydrocarbon-rich areas tend to be hydrocarbon-rich 

at many different levels, corresponding to quite different 

geological epochs, and extending down to the crystalline 

basement that underlies the sedimentary deposits. An invasion of an area by hydrocarbon fluids from below could 

better account for this distribution than the chance of successive deposition. 

3. Some petroleums from deeper and hotter levels lack 

almost completely the biological evidence. Optical activity 

and the odd-even carbon-number effect are sometimes totally absent, and it would be difficult to suppose that such 

a thorough destruction of the biological molecules had occurred as would be required to account for this, yet leaving the bulk substance quite similar to other crude oils. 

4. Methane is found in many locations where a biogenic origin is improbable or where biological deposits 

seem inadequate: in great ocean rifts in the absence of any 

substantial sediments; in fissures in igneous and metamorphic rocks, even at great depth; and in active volcanic 

regions, even where there is a minimum of sediments. 
THE ORIGIN OF METHANE IN THE CRUST OF THE EARTH 59 

Futhermore, there are massive amounts of methane hydrates (combinations of methane and water ice) in permafrost and ocean deposits, where it is doubtful that an 

adequate quantity of biological source material is present. 

5. The hydrocarbon deposits of a large area often 

show common chemical or isotopic features, quite independent of the varied composition or the geological ages 

of the formations in which they are found. Such chemical 

"signatures" may be seen in the abundance ratios of some 

minor constituents such as traces of certain metals that are 

carried in petroleum; or a common tendency may be seen 

in the ratio of isotopes of some elements, or in the abundance ratio of some of the different molecules that make 

up petroleum. Thus a chemical analysis of a sample of 

petroleum could often allow the general area of its origin 

to be identified, even though quite different formations in 

that area may be 'producing petroleum. For example, a 

crude oil from anywhere in the Middle East can be distinguished from an oil originating in any part of South America, or from the oils of West Africa; almost any of the oils 

from California can be distinguished from those of other 

regions by the carbon isotope ratio. 

6. The regional association of hydrocarbons with the 

inert gas helium, and a higher level of natural helium 

seepage in petroleum-bearing regions, has no explanation 

in the theories of biological origin of petroleum. 

ADVOCATES OF THE 

ABIOGENIC THEORY 

Among the early advocates of a nonbiological origin 

of petroleum was the great Russian chemist Mendeleev, 

the originator of the periodic table of the elements. His 

arguments, presented in a paper on the origin of petroleum 

(Mendeleev, 1877), are still valid today. He already knew 

of the large-scale patterns of hydrocarbon occurrence, but 

his information on the processes that shaped the Earth was 

not ·our present understanding and made his explanations 

much more complex than would need to be the case now. 

Sokoloff (1889) discussed the "cosmic origin of bitumina" (carbonaceous substances from petroleum to pitch 

and tar), and he related these to the meteorites, knowing 

then already about meteorites' hydrocarbon content. He 

stressed that oil and tar occur in basement rocks, such as 

in the gneiss of Sweden. He could find no relationship to 

the fossil content of rocks, and he stressed that porosity 

was the sole circumstance that relates to the accumulation 

of bituminous substances. 

Vernadsky ( 1933) gave reasons why he considered that 

with increased pressure and decreased oxygen availability 

with depth, hydrocarbons would be stable and largely replace carbon dioxide as the chief carbon-bearing fluid. 

Kudryavtsev (1959), the most prominent and strongest 

advocate of the abiogenic theory in modem times, argued 

that no petroleum resembling the chemical composition of 

natural crudes has ever been made from genuine plant material in the laboratory, and in conditions resembling those 

in nature. He gave many examples of substantial and 

sometimes commercial quantities of petroleum being 

found in crystalline or metamorphic basement rocks, or in 

sedimentary rocks directly overlying those. He cited cases 

in Kansas, California, western Venezuela and Morocco. He 

pointed out that oil pools in sedimentary strata are often 

related to fractures in the basement directly below. The 

Lost Soldier Field in Wyoming has oil pools, he stated, at 

every horizon of the geological section, from the Cambrian sandstone overlying the basement rocks to the Upper 

Cretaceous strata. A flow of oil was also obtained from the 

basement itself. 

Hydrocarbon gases, he noted, are not rare in igneous 

and metamorphic rocks of the Canadian Shield. Petroleum 

in Precambrian gneiss is encountered in wells on the eastern shore of Lake Baikal, Russia. He stressed that petroleum is present, in large or small quantity, but in all 

horizons below any petroleum accumulation, apparently 

totally independent of the varied conditions of formation 

of these horizons. This statement has since become known 

as "Kudryavtsev's rule," and many examples of it have 

been noted in different parts of the world. Commercial accumulations are simply found where permeable iones are 

overlaid by impermeable ones, he concluded. 

Kudryavtsev introduced a number of other relevant 

considerations into the argument. Columns of flames have 

been seen during the eruptions of some volcanoes, sometimes reaching 500 meters in height, such as during the 

eruption of Merapi in Sumatra in 1932. The eruptions of 

mud volcanoes have liberated such quantities of methane 

that even the most prolific gasfield underneath should have 

been exhausted long ago. Also, the quantities of mud deposited in some cases would have required eruptions of 

much more gas than is known in any gasfield anywhere. 

The water coming up in some instances carries such substances as iodine, bromine, and boron that could not have 

been derived from local sediments and that exceed the 

concentrations in seawater one-hundredfold. Mud volcanoes are often associated with lava volcanoes, and the typical relationship is that the mud volcanoes nearer the lava 

volcanoes emit incombustible gases, while the ones further 

away emit methane. Kudryavtsev knew of the occurrence 

of oil in basement rocks of the Kola Peninsula of Russia, 

and of the surface seeps of oil in the Siljan Ring formation 

of central Sweden (which I shall discuss later). He noted 

that the enormous quantities of hydrocarbons in the Athabasca tar sands in Canada would have required vast 

amounts of source rocks for their generation in the conventional discussion, when in fact no source rocks have 

been found. 

Beskrovny and Tikhomirov (1968) noted, as did 

Anders, Hayatsu, and Studier (1973), that of the many 
60 THE FUTURE OF ENERGY GASES 

possible isomers of petroleum molecules, the particular 

subset found in natural petroleum is also the one preferentially produced in artificial oil production from hydrogen 

and carbon rather than from biological substances. 

Porfir' ev (197 4) argued that so-called source rocks 

have no identification that proves their hydrocarbons to be 

primarily biogenic. He also discounted the hypothesis, 

often advanced, that the transport and deposition of oil 

from supposed source rocks to the final reservoir was accomplished by solution in gas: the quantities of gas that 

would be required would exceed by orders of magnitude 

the quantities that could be derived from the supposed 

source materials. 

Levin (1958) concerned himself with the formation 

process of the Earth, claiming that the class of meteorites 

called carbonaceous chondrites, a low-temperature condensate that was probably responsible for bringing in solids 

that contained water, could have brought to the forming 

Earth several times larger quantities of carbonaceous materials than all the ocean water. 

Kravtsov (1975) presented much observational material. He showed that the natural seepage of methane in many 

areas was far more than could be supplied by any kind of 

gas field known. If the volcanic gases of the Kurile Islands, 

for example, are typical of the gases emitted over the timespan of the volcanic activity there, the amount of methane 

emitted would far exceed the conventional estimate of the 

present-day total world reserves. He also gave many examples of Kudryavtsev's rule. 

Kropotkin and Valyaev (1976, 1984) and Kropotkin 

(1985) developed many aspects of the theory of deep-seated, inorganic origin of hydrocarbons. They concluded that 

petroleum deposits were formed where pressure conditions 

permitted the condensation of heavier hydrocarbons, 

transferred from great depth by rapidly rising streams of 

compressed gases. In volcanic regions, they noted, decomposition of hydrocarbons would be favored, resulting 

in the formation of carbon dioxide and water, while in 

cooler, nonvolcanic regions, hydrocarbons would be preserved and could accumulate in alluvial traps and highly 

fractured beds, depending on the presence of adequate reservoirs and caprocks. According to these authors "vertical 

migration of hydrocarbons from levels far below formations rich in biogenic organic matter, which have been 

considered the source material for the oil, can be demonstrated in a majority of deposits." Kropotkin also presented numerous examples in which Kudryavtsev's rule is 

satisfied in a striking way. 

Most of the papers cited so far are by Russian authors, 

but there were several voices outside Russia (or the Soviet 

Union) who also argued for a nonbiogenic origin. Most 

notable among them was Sir Robert Robinson (1963, 

1966) who, like Mendeleev, can be considered among the 

most distinguished chemists of his day. He studied the 

chemical make-up of natural pe~roleums in great detail, 

and concluded that they were mostly far too hydrogen-rich 

to be a likely product of the decay of plant debris. Olefins, 

the unsaturated hydrocarbons, would have been expected 

to predominate by far in any material that was derived in 

that way. 

Sylvester-Bradley (1964, 1972) pointed out that the 

meteorites have hydrocarbons, and hypothesized that hydrocarbons on the Earth derived in major part from such 

material. He proposed that hydrocarbons streaming up 

through the crust from great depth would have provided 

energy sources for simple forms of life. He knew about 

the biological materials in petroleum, but, like Robert 

Robinson, he thought that they were due to contaminating 

additions from microbiota in such locations. 

Before discussing further the possible origins of hydrocarbons on the Earth, it is necessary to discuss the 

present state of knowledge of the process of formation of 

the Earth and the planetary system, and the materials that 

contributed to that formation. 

THE FORMATION PROCESS 

OF THE EARTH 

The Earth is a body with a most complex history. 

None of its sister planets display signs of the processes 

that appear to have been the major ones to shape this planet. On all the other solid bodies of the solar system the 

effects of impact cratering can be seen very clearly. Craters spanning a range of size from a few to several thousand kilometers can be clearly recognized. Impacts of 

solid objects upon all the planetary bodies in the process 

of their formation must have been a common occurrence. 

Strangely, on our Earth similar cratering events can 

only be seen, if at all, in a very subdued form. We see arcs 

of circles appearing in the midst of a topography shaped 

by other effects. It seems reasonable to interpret such circular features as the remains of impacts, now deeply buried but affecting the outer crust at a later stage in some 

way that makes the buried impacts recognizable again. 

One has to suppose that other events occurred here that 

obscured most of the evidence of this early bombardment. 

Nevertheless, it is now quite clear that the Earth, like 

the other solid planetary bodies, also formed by the accretion of solid objects, probably largely in the form of small 

grains, but interspersed with occasional major pieces. It 

appears that then a partial melting took place, causing materials of lower density to make their way to the surface, 

while presumably melts of high density sank down toward 

the center. The heat for this melting was the result of 

radioactivity contained in the material, as well as the heat 

resulting from compression. Once partial melting occurred, two other sources of heat came into play: firstly 

the gravitational energy that is released as materials can 

move and sort themselves out according to density. Sec-
THE ORIGIN OF METHANE IN THE CRUST OF THE EARTH 61 

ondly there is the chemical energy that results from all the 

chemical reactions that can then take place, either between 

different liquids or between liquids and solids. The original diverse materials that accreted as cold objects would 

certainly not have been chemically equilibrated with each 

other, but would be left in an uneven distribution by the 

chances of the impact events. After the original materials 

gained mobility by melting, many chemical reactions 

would take place that would, on average, release energy 

and thus provide more heat, as well as give rise to volatile 

substances. 

Both of these last two sources of energy-gravitational and chemical energy-have the interesting property that 

they make the heating unstable: where more heating has 

occurred and more melt has been produced, more of these 

actions can take place and therefore still more heat will be 

produced. One may well speculate that the very uneven 

distribution of internal heat sources that we recognize at 

the surface is derived from such an instability. The circum-Pacific "belt of fire" is the most striking example, but 

there are also many other lanes characterized by high heat 

flow and volcanic activity. They are also characterized by 

the outflow of fluids-gases and liquids-that are thought 

to have a deep origin. Deposits of hydrocarbons frequently 

show a clear association with such patterns (an example is 

shown in fig. 3). 

If the major volume of the Earth has never been molten, the. mantle of the Earth underneath the crust must still 

contain the diversity of chemistry, the chemical energy 

sources, and the sources of gases and liquids that would 

be the legacy of an accretion process from diverse and initially cold solids. Major impacts would have thrown up 

ring patterns of mountains, which, as on the Moon, would 

convert vertical patterns of chemical inhomogeneity into 

regional patterns. Many arcuate patterns on the Earth of 

surface topography and of chemical features or of heat 

flow may be a consequence of such impacts. 

THE THEORY OF THE BIOLOGICAL 

ORIGIN OF HYDROCARBONS ON EARTH 

Oil, hydrocarbon gases, and coal on the Earth were 

thought to have been derived entirely from biological 

debris for several reasons. One reason was the belief in 

earlier times that hydrocarbons were specifically organic 

substances: hence the name "organic carbon" for all forms 

of unoxidized carbon. The knowledge that hydrocarbons 

are abundant in the universe, and on many of the other 

planetary bodies of our solar system, was not available at 

that time. Now we know that carbon, the fourth most 

abundant element in the universe after hydrogen, helium, 

and oxygen, is almost certainly also the fourth most abundant in the planetary system; there it is predominantly in 

the form of hydrocarbons. The major planets Jupiter, Saturn, Uranus, and Neptune have large amounts of methane 

and other hydrocarbon gases in their atmospheres. Titan, a 

large satellite of Saturn, has methane and ethane in its atmosphere, and these gases form clouds and behave much 

like water does in the atmosphere of the Earth. Triton, a 

large satellite of Neptune, appears to have hydrocarbons 

mixed with water ices on its surface, as does the outermost planet known at this time, Pluto. A large fraction of 

all the asteroids show a surface reflectance closely resembling that of tar, and the comets have hydrocarbons among 

the gases they emit. The surface of the core of Comet Halley, recently observed by spacecraft, is most reasonably interpreted as one of tar. Complex, polycyclic hydrocarbon 

molecules similar to those in natural petroleum have been 

observed to be a prominent component of interplanetary 

dust grains that currently enter the Earth's upper atmosphere (Clemett and others, 1993). 

Hydrocarbons in our planetary system are certainly 

very abundant, and in all the extraterrestrial examples 

mentioned they are almost certainly not related to biology. 

Also, hydrocarbons are prominent among the gases identified in the molecular clouds of the galaxy, and it is from 

such clouds that the solar system formed initially. The 

presence and great abundance of hydrocarbons is universal, and no special mechanism for their generation on the 

Earth needs to be invoked, unless one knows with certainty that hydrocarbons could not have survived the formation process here, although they did so on many of the 

other planetary bodies. (No evidence of hydrocarbons has 

yet been seen on Mars, the Moon, Venus, and Mercury. 

The atmosphere of Venus is too hot to have maintained 

gaseous or liquid hydrocarbons; the other three bodies 

lack an adequately protective atmosphere to have maintained hydrocarbons on their surfaces.) 

In earlier times there was the belief that the Earth had 

formed as a hot, molten body. In that case no hydrocarbons or hydrogen would have survived against oxidation, 

nor would any of these substances have been maintained 

in the interior after solidification. With that belief, there 

seemed no possibility of accounting for the hydrocarbons 

embedded in the crust other than by the outgassing of carbon in the form of C02, produced by materials that could 

have survived in a hot Earth, and subsequent photosynthesis by plants that converted this C02 into unoxidized carbon compounds. This consideration is irrelevant now that 

we know that a cold formation process assembled the 

Earth and that hydrocarbons could have been maintained, 

and could be here for the same reasons that they are on 

the other planetary bodies. 

The common existence of molecules of clearly biological origin in most petroleum and bituminous coal is no 

longer an argument for a biological origin of hydrocarbons, 

now that we know of the wide reach of microbiology in the 

crust (Jannasch, 1983; Yanyanos, 1986; Gold, 1992). Before this reach had been identified, the possibility of 
62 THE FUTURE OF ENERGY GASES 

widespread biological contamination at depth had not been 

considered. Now, especially after the discovery of the volcanic vents on the ocean floors and the profuse chemosynthetic life that exists there, the outlook is different. It is now 

seen as not only possible, but very likely, that microbiota 

are common in the crust down to depths of between 5 and 

10 kilometers, a level below which the temperature will 

reach values too high for any microbial life we know, 

thought to be between ll0°C and 150°C. This deep microbial life uses as its energy source the various chemical imbalances that the outgassing process creates as gases and 

liquids stream up through rocks with which they have never 

been chemically equilibrated. Knowing now of the occurrences of such deep microbial life, it seems likely that no 

location that could support such life has been kept sterile 

from it for the long periods of geologic time. Hydrocarbons, 

together with oxygen donors such as sulfates or metal 

(principally iron) oxides, substances that are common in the 

rocks or water, would provide a usable energy source for 

microorganisms. Hydrocarbon deposits would therefore acquire biological debris in the course of time. The molecules 

that are commonly regarded as proof of the biological origin of petroleum and of bituminous coal have all been 

found to be also produced by subsurface bacteria; indeed 

some of them can only be produced by bacteria (Ourisson 

and others, 1984). Pristane, phytane, steranes, hopanes are 

unquestionably of biological origin, but do not certify the 

biological origin of either petroleum, coal, kerogen, or 

whatever other deposits in which they are seen. With the 

photosynthetic theory of their origin, they seemed to certify 

that these materials were all once at the surface. But this is 

no longer a valid inference. Many other conclusions in geology were based on this inference, and should also be 

reconsidered now. 

ORIGIN OF THE CARBON 

ON THE EARTH 

The surface and surface sediment on the Earth contain 

approximately one hundred times as much carbon as 

would have been derived from the grindi~g up of the basement rocks that contributed to the sediment. The surface is 

enormously enriched in carbon, and this enrichment needs 

an explanation. 

Of the carbon we have on the surface or in the sediment of the Earth, four-fifths is estimated to be in the form 

of carbonate rocks, and one-fifth in unoxidized form, frequently referred to as "organic." (The word "organic," 

given at one time to all unoxidized carbon, is of course now 

a misleading misnomer.) The quantities are large: if expressed as the mass of the element carbon per square centimeter of total Earth surface area, the estimate of carbon on 

the surface or in the sediment of the Earth is about 20 

kilograms. (I will be referring to this quantity again later.) 

During formation of the Earth by the accumulation of 

cold solids, very little gaseous material was incorporated, 

as indicated by the extremely low level of the nonradiogenic noble gases in the atmosphere of the Earth. Among 

those gases, only helium could have escaped into space, 

and only xenon could have been significantly removed by 

absorption into rocks. Neon, argon, and krypton would 

have been maintained as an atmospheric component. The 

proportions of noble gases in the Sun and in space are 

known. Any acquisition of such a mix of gases in the formation of the Earth would not have allowed selective exclusion of the noble gases, which have no significant 

chemical interactions. One is forced to conclude that the 

acquisition of gases, or substances that would be gaseous 

at the pressures and temperatures that prevailed in the region of formation of the Earth, was limited to the small 

value implied by the low noble-gas values. The carbon 

supply the Earth received initially could not have been in 

the form of hydrocarbon gases, high-volatility hydrocarbon liquids, or CO or C02. 

Could meteoritic infall of carbon at later times be held 

responsible for the current excess of surface carbon? Such 

a massive infall would have left much other evidence in 

the geologic record, and such evidence is absent. The only 

alternative is that carbon came up from the interior as a 

liquid or gas, just as is true for the water of the oceans 

(approximately 300 kg/cm2), the nitrogen of the atmosphere (approximately 1 kg/cm2) and the (largely radiogenic) argon of the atmosphere. 

Perhaps one might consider the possibility that the 

Earth once had a massive atmosphere of carbon dioxide 

that evolved early, from materials that could have survived 

the formation process, and that these materials then became converted into the carbon deposits we now have; but 

that also does not seem an acceptable explanation, for in 

that case we should see many more very early carbonate 

rocks than the amounts laid down later. This pattern is not 

what the geologic record shows. What it does show is a 

reasonably continuous accumulation of carbonate rocks; 

no epoch having enormously more carbonate deposition 

per unit of time, nor enormously less. If outgassing from 

depth is responsible for surface carbon, then one has to 

discuss what the source material in the Earth might have 

been, what liquids or gases might have come from the 

source material, and what their fate would have been as 

they made their way up through the crust. 

The meteorites represent some samples of material left 

over from the formation of the planets. While they may 

not be representative of the quantities of the different 

types of material that made up the Earth, they appear to 

represent at least samples of all the major components. 

Only one type of meteorite, the carbonaceous chondrites, 

contain significant amounts of carbon, and they contain it 

mainly in unoxidized form, a substantial fraction in the 

form of solid, heavy hydrocarbons. This material, when 
THE ORIGIN OF METHANE IN THE CRUST OF THE EARTH 63 

heated under pressure as it would be in the interior of the 

Earth, would indeed release hydrocarbon fluids, leaving 

behind deposits of solid carbon. 

The quantitative information on carbonaceous chondrites is difficult to evaluate. These chondrites are much 

more friable than most other meteorites, and therefore survive the fall through the atmosphere less often than the 

others. Carbonaceous chondrites also are destroyed by erosion on the ground much more rapidly. The result must be 

that far fewer than the original proportion are ever discovered. They may well represent even now the largest quantity of meteoritic material still available for collection by 

the Earth; the infall of interplanetary dust to which I have 

referred contains similar carbonaceous material. 

By contrast, carbonates, which would be a source material for C02, exist in meteoritic materials only in very 

small concentrations, so that an origin of the Earth's surface carbon from an initial C02 source seems unlikely. If 

the carbonaceous chondrite material is the principal source 

of the surface carbon we have, then the initial material 

that could be mobilized in the Earth at elevated temperatures and pressure would be a mix of carbon and hydrogen. What would be the fate of such a mix? Would it all 

be oxidized with oxygen from the rocks, as some chemical 

equilibrium calculations have suggested? Evidently not, 

for we have clear evidence that unoxidized carbon exists 

at depths between 150 km and 300 km in the form of diamonds. We know diamonds come from this depth range, 

because it is only there that the pressures would be adequate for their formation. Diamonds are known to have 

high-pressure inclusions that contain CH4 and heavier hydrocarbons, as well as C02 and nitrogen (Melton and 

Giardini, 1974). The presence of at least centimeter-sized 

pieces of very pure carbon implies that carbon-bearing fluids exist at the depth of diamond formation, and that they 

must be able to move through pore spaces at that depth, so 

that a dissociation process may selectively deposit the 

pure carbon-a process akin to mineralization processes as 

we know them at shallower levels. The fluid responsible 

cannot be C02, since this molecule has a higher dissoCiation temperature than the hydrocarbons that coexist in the 

diamonds; the diamonds must therefore have been laid 

down by hydrocarbons. 

Diamonds will survive a transport to the low pressure 

at the surface only if that transport is accompanied by 

rapid cooling; if diamonds are cooled slowly they will turn 

to graphite, the equilibrium form of carbon at low pressure. Diamond is a metastable form of carbon at the low 

surface pressure, but the surface temi>erature is too low for 

a relaxation to the stable form. Indeed, diamonds are 

found predominately in the vicinity of sites of explosive 

gas eruptions, diamond pipes, where rapid gas expansion 

caused quick cooling. There is also evidence for pure 

carbon transported up from depth at a slow rate: pseudomorphs of diamonds. Spaces showing the octahedral symmetry of diamond have been found filled with graphite, in 

mantle rocks that have come to the surface in Morocco 

(Pearson and others, 1989). These rocks came up presumably in a slow ascent; they contain a dense array of octahedral spaces filled with graphite, clearly fitting the 

interpretation as pseudomorphs of diamond. This discovery suggests that a very high density of diamonds exists in 

at least some locations in the mantle, and that the rarity of 

diamonds on the surface is to be attributed to the rarity of 

the explosive events that could bring them up sufficiently 

quickly. It is noteworthy that hydrocarbons are found in 

diamond pipes together with the diamonds, suggesting that 

the gases involved in the explosive events were not oxidizing (Kravtsov and others, 1976, 1981 ). 

THE SURFACE CARBON BUDGET 

The deposition of carbonate rocks has been an ongoing 

process throughout the times of the geologic record. Most 

but not all of this carbonate has been an oceanic deposit, 

deriving the necessary C02 from the atmospheric-oceanic 

C02 store. The amount of carbon that is at present in this 

store is, however, only a very small fraction of the amount 

required to lay down the carbonates in the geologic record. 

The atmospheric-oceanic reservoir holds at present only 

about 0.01 kg of carbon per cm2 of the Earth's surface area. 

If we take the figure quoted earlier (see section "Origin of 

the Carbon on the Earth"), of about 20 kg of carbon per 

cm2 laid down over the time of the identified geologic 

record, there must have been a supply renewing the atmospheric-oceanic C02 store gradually, but by an amount 

2,000 times the present content. This amount of carbon, if 

calculated as having a continuous and steady outgassing 

rate and initially all coming up as methane, would translate 

into a 1-m-deep layer of methane at standard temperature 

and pressure (STP) being created all over the Earth every 

2,700 years. If the rate is regionally variable, so that, for 

example, one-tenth of the area produces nine-tenths of the 

amount, then in the gas-prone areas, a 1-m-deep layer of 

methane at STP would come up every 300 years. If naturalgas fields are filled from outgassing methane, such a supply 

rate would be much more than adequate in the timespans 

available to create all the known fields. 

If the supply of carbon from below ceased, the present 

rate of carbonate deposition would deplete the atmospheric-oceanic reservoir of carbon in something on the order 

of 500,000 years, a very small fraction of geologic time. 

Outgassing of carbon in some form must have been a continuous process; it is not likely that humans evolved just in 

the last period, just before the death of all plant life. We 

must therefore inquire what quantities of carbon would 

have been available at deep levels, what form this carbon 

took, and in what manner the resupply of the atmosphericoceanic C02 reservoir could have taken place. It is also 
64 THE FUTURE OF ENERGY GASES 

clear that one cannot discuss human-caused additions to 

the atmospheric carbon gases without taking into account 

the large and surely variable natural carbon emission that 

has taken place throughout geologic time. 

The resupply of carbon must be from juvenile sources. 

Recycling of sedimentary rocks cannot account for it, both 

for reasons of the quantities involved and for reasons of 

the isotopic composition. If the repeated subduction of 

carbonate rocks occurred on the necessary. massive scale, 

it would seem that old carbonate rocks should have disappeared almost completely. This is not the case. The isotopic information, to which we shall return later, also would 

say that in a process of continuous recycling the proportion of 13c would continuously increase in the atmosphere, and hence the younger carbonates would be 

isotopically heavier than the older ones; this also is not the 

case. Marine carbonates of all ages back to the Archaean 

show the same narrow range of the carbon isotopic ratio 

(Schidlowski and others, 1975; see also fig. 4). 

How much carbonaceous chondrite material would 

have been required to provide the supply of the surface 

carbon? Let us make a simple calculation. Suppose that in 

the depth range between 100 and 300 kilometers we have 

a patchwork of which the carbonaceous chondrite material 

composes 20 percent on average. In this material, carbon 

amounts to 5 percent. Given these figures, each squarecentimeter column through the 200-kilometer layer would 

contain, on average, I percent of carbon (5 percent of 20 

percent), which would translate into 660 kilograms per 

square centimeter. If one-thirtieth of this carbon had been 

mobilized and reached the outer crust, it would suffice to 

account for all the carbon of the carbonate sediments and 

the deposits of unoxidized carbon. Of course the proportion of carbonaceous chondrite type of material may have 

been very much larger, and the producing layer much 

thicker. The fraction that needs to have been mobilized 

would then be much smaller. All one can really say at this 

stage is that there is no quantitative problem. Volatile-rich 

material of sufficient quantity to have supplied the water 

of the oceans, as discussed by Levin (1958), could quite 

easily have supplied the quantity of hydrocarbons for all 

the surface carbon. 

As we have seen, the primary source material in the 

Earth that would yield a carbon-bearing fluids is likely to 

be a hydrocarbon mix, not a substance that would first 

produce C02. As the carbon-bearing fluids moved up toward the Earth's surface, however, some unknown fraction 

would come up on pathways held open by magma, where 

these fluids would largely be oxidized to C02 and water. 

Along other pathways, created by pressure fracturing in 

solid rock, the direct oxidation would be minimal and 

these fluids might arrive at the surface as methane and 

other hydrocarbon gases or liquids. However, even in the 

solid rock a substantial proportion of carbon-bearing fluid 

is frequently oxidized at shallow levels, as indicated by 

the common presence of carbonate cements in oil- and 

gas-rich regions. These cements are derived from metal 

oxides initially present in the rocks and from C02 derived 

apparently from the oxidation of methane with some oxygen supplied from the rocks; the carbon isotope ratio of 

these pore-filling cements is not compatible with a derivation from atmospheric C02, and their distribution is such 

that they fill the pores in a vertical column, suggesting an 

origin from ascending fluids. This oxidation is probably 

due to the action of microorganisms that obtain oxygen 

from components of the rock, and it is then limited to the 

outer levels of the crust where the temperature is in the 

range in which microbial activity can take place. It can be 

presumed quite reasonably that only a fraction of the C02 

so produced will in fact remain in the ground as carbonate, and a substantial fraction, quite possibly the major 

amount, will escape into the atmosphere. 

A supply of hydrocarbons at depth may thus provide 

C02 to the atmospheric-oceanic reservoir in three different 

ways. One is through volcanic pathways and oxidation 

with oxygen supplied by the magma; another is by ascent 

of hydrocarbons through solid rocks and oxidation at shallow levels, most likely by bacterial action, with subsequent escape of C02 to the atmosphere; a third process is 

the escape of methane and other hydrocarbons into the atmosphere, where, in the presence of atmospheric oxygen, 

they would reside on average 10 years before oxidation to 

C02. What fraction of carbon resupply comes by each of 

these pathways is still not known directly, but some limits 

can be placed by considerations of the maintenance of the 

atmospheric oxygen level within the bounds suggested by 

the geologic record, and possibly by some other more direct measurements. 

Methane is present in the atmosphere at about 1.7 

parts per million (ppm) by volume. Much or most of this 

methane represents a cycling of atmospheric carbon 

through biological processes, but the quantitative estimates 

of the magnitudes and speeds of these processes are not 

sufficiently precise to determine whether the observed 

methane concentration is the one to be expected from biological recycling alone. One may therefore inquire whether a contribution to this methane directly from outgassing 

sources is a possibility. Fortunately there is a clear possibility of distinguishing biologically recycled methane from 

juvenile methane: the radiocarbon (

14C) proportion of the 

biological contribution should be the same as that of atmospheric C02, since such recycling would almost all take 

place in a short time compared with the half-life of 14C 

(5,700 years). Thus carbon from deep sources would be 

free from 14C. A measurement of the fraction of 14C in 

atmospheric methane can therefore supply the information. 

Several such measurements have been attempted, but there 

are difficulties and uncertainties connected with the sampling method and with the measurement itself. The latest 

measurements have given values of approximately 32 per-
THE ORIGIN OF METHANE IN THE CRUST OF THE EARTH 65 

cent of non- 14C-bearing atmospheric methane (Lowe and 

others, 1988). Would such values be compatible with a 

supply of carbon from juvenile sources? 

We may take, for a simple calculation, methane with 

a concentration in the atmosphere of 1.7 ppm and a lifetime of about 10 years before oxidation. Let us suppose 

that 30 percent of this methane is juvenile, and see how 

this amount compares with the requirements of the terrestrial carbon budget. The measurements quoted would give 

an amount of juvenile carbon at present in CH4 in the air 

of 2xl0-7 kg C/cm2. If this amount of carbon were replenished on a 1 0-year timescale (the presumed lifetime of 

atmospheric methane), the average supply of juvenile carbon would have to be 2x 10-8 kg/cm2 year. To form the 

estimated global carbon deposits of 20 kg/cm2 entirely 

from this source would therefore take I billion years, a 

figure compatible with the geologic record. While this calculation cannot be taken to be a confirmation of the results 

that have been reported, nor of the proportion of the juvenile supply of CH4, it does demonstrate that measurements 

of the 14C content of atmospheric methane are worth 

doing, and that a substantial fraction of the atmospheric 

methane may in fact be juvenile. If it is, one must suspect 

that such a contribution would have large variations over 

time, as have all other tectonic processes, and that therefore much higher or much lower values of juvenile atmospheric methane could be registered at the present time, or 

at any one time, than the long-term average value. The 

time variations of atmospheric CH4 reported from ice 

cores should be seen in the light of these considerations. 

THERMODYNAMICS OF OUTGASSING 

Assuming the carbonaceous chondrite type of material 

is the prime source of the Earth's surface carbon, the question arises as to the fate of this material under heat and 

pressure, and under the conditions it would encounter as 

buoyancy forces drove some of it toward the surface. 

This problem has been tackled by thermodynamicists, 

most thoroughly by Chekaliuk (1976). His conclusion was 

that at sufficient pressure, such as that at a depth of 200 

km or so, the equilibrium configuration would be a mix of 

hydrocarbon molecules, despite a temperature that would 

be far in excess of the dissociation temperature for these 

molecules (fig. 1). The pressure would provide these molecules with some stability, although any one molecule 

might indeed have sufficient internal energy to fall apart at 

the elevated temperature. At high pressures the assembly 

as a whole would not have enough energy to generate the 

increased volume that the dissociated molecules would demand. Fragments would instantly be reformed in such a 

way as to satisfy the volumetric constraint. No molecule 

would have permanent stability, but a statistical assembly 

of hydrocarbon molecules would represent an average 

equilibrium. The detailed mix of molecules would depend 

on pressure and temperature, and on the carbon-hydrogen 

ratio. Other atoms that might also be present, such as oxygen and nitrogen, would form a variety of complex molecules with the carbon and hydrogen. Metal atoms that 

might be present in the surroundings would form a range 

of organometallic molecules under these circumstances. 

Even with the knowledge that diamonds and their highpressure inclusions have provided, it has been argued that 

hydrocarbons could not come from the deep levels Chekaliuk (1976) considered, because they could not survive at 

temperatures reached in the crust at a depth below 20 kilometers (Hunt, 1975); but these discussions in the petroleum 

literature have not included the effects of pressure. 

The statistical mix of hydrocarbon molecules Chekaliuk (1976) expected from a carbonaceous chondrite source 

material, being less dense than the surrounding rock, 

Cl :300m ... 

= 0 

"' .. • Cl ~ 

ct :r 

l :3km l 

:30km 

:300km 

0 500 1000 1500 2000 2500 

T<•clFigure 1. Stability of hydrocarbons at temperatures and pressures 

in the Earth (from Chekaliuk, 1976). Pressure-temperature regime of Earth is indicated by the shaded region. Thermodynamic 

calculations indicate domains in which various hydrocarbon molecules are stable. The lines marked Paraffins, Naphthenes, and 

Aromatics enclose domains in which a mix of hydrocarbon molecules would be set up from hydrogen and carbon, and on crossing outward from these domains the percentages indicated would 

be retained. Methane is essentially stable to the left of the line 

marked 95 percent, and I 0 percent would still be retained on 

crossing to the right of the line so marked (that is, 90 percent 

would dissociate into hydrogen and carbon). According to these 

calculations, most of the petroleum components would be present 

in equilibrium of a carbon-hydrogen mix at a depth between 100 

and 300 km, and methane streaming up could bring a significant 

fraction of these petroleum components toward the surface. b, 

bar; kb, kilobar; km, kilometer; m, meter; T, temperature. 
66 THE FUTURE OF ENERGY GASES 

would have buoyancy forces driving it toward the surface. 

If present in sufficient concentration, the fluid would fracture the solid rock and ascend in such fracture porosity. 

(Molecular diffusion in rock over large distances is too 

slow a process to be of any significance, even on the long 

timescales of geology.) In that upward travel, the temperature and the pressure would be decreasing, and the various 

molecules would reach levels where the temperature was 

low enough for them to achieve stability. Each one of 

these molecules would then cease the temporary dissociations described above and become effectively permanent. 

If there is a high ratio of hydrogen to carbon in the 

stream, saturated hydrocarbons would become a major 

component;. and, with sufficient hydrogen, methane, the 

most stable of· all the hydrocarbon molecules, might become by far the dominant component. At depth methane 

would behave chemically like a liquid, and it would dissolve the heavier hydrocarbons that may be present, and 

therefore greatly reduce the viscosity of the entire fluid. 

The continuing upward stream would acquire more 

and more of such stable molecules, and the final product 

that may be caught in the reservoirs we tap for oil and gas 

would be the end product of this process. The detailed 

chemistry of the oils in each region would then represent 

this final phase of the oil molecules on their way up, and 

that chemistry would be determined by the pressure-temperature regime the flow had experienced, the initial hydrogen-carbon ratio of the mix, and possibly surface 

catalytic actions and contributions from the rocks through 

which the flow had gone. 

At shallow levels and low pressures, methane, now a 

gas, would separate out from the heavier components, 

leaving those as fluids of higher viscosity, and therefore 

much more subject to retention in reservoir rocks: the 

quantity of methane that would need to have been in the 

stream to facilitate the transport of oils would be many 

times larger than that of the oils, but because of the great 

mobility of methane gas, most of it would fail to be retained in the ground at shallow levels. 

HORIZONTAL AND VERTICAL 

PATTERNS OF HYDROCARBON FIELDS 

Everyone now thinks of the Middle East-especially 

Saudi Arabia, the Persian· Gulf, Iran, and Iraq-as being the 

oil region of the world. It is indeed one large patch that is 

oil-rich, stretching for 2,700 km from the mountains of 

eastern Turkey down through the Tigris Valley of Iraq, 

through the Zagros Mountains of Iran, into the Persian 

Gulf, into Saudi Arabia, and further south into Oman 

(fig. 2). There is no feature that is common to the geology 

or the topography of the parts that make up this entire large 

region and that would give any hint as to why the whole 

region is oil and gas rich. The various oil deposits are in 

different types of rock, in rocks of quite different ages, and 

they are overlaid by quite different caprocks. They are in a 

topography of folded mountains in Turkey and the high 

Zagros mountains of Iran, in the river valley of the Tigris in 

Iraq, in the Persian Gulf itself, in the flat plains of Saudi 

Arabia, and in the mountainous regions of Oman. It cannot 

have been a matter of chance that this connected region had 

so prolific a supply of oil and gas, but resulting from totally 

different and independent circumstances in different parts 

of the region. These hydrocarbon-bearing formations represent times so different from each other that there would 

have been no similarity in the climate or in the types of 

vegetation that existed there during deposition, just as there 

is no similarity in the reservoir rocks or in the caprocks of 

the different regions now. Yet it is a striking fact that the 

detailed chemistry of these oils is similar over the whole of 

this large region (Kent and Warman, 1972). Surely this is 

an example of the need to invoke a larger scale phenomenon for the cause of the oil supply than any scale we can 

see in the geology of the outer crust. 

The island arc of Indonesia, of which Java and 

Sumatra are the main islands, belongs to a much larger arc 

that stretches from the western tip of New Guinea through 

these Indonesian islands into the Indian Ocean, through 

TURKEY ~ 

. SYRIA ... 

• .. 

SAUDI ARABIA 

• 

• 

IRAN 

• 

~'···. • •• • • • . UNITED ARAB 

EMIRATES 

• 

Figure 2. Oil fields of the Middle East, showing continuous region from Turkey to Oman. The dots represent individual fields, 

and the size of each dot indicates the magnitude of the field. 
THE ORIGIN OF METHANE IN THE CRUST OF THE EARTH 67 

the Andaman Islands, into the Irrawaddi valley of Burma, 

and into the high mountains of southern China, over a 

total length of 6,000 km (fig. 3). That it is one connected 

arc all the way cannot be doubted because the frequency 

of earthquakes along the whole of this arc is hundreds of 

times greater than it is away from the arc. Along the 

whole of this arc petroleum is very abundant. But at one 

end, this arc is made up of volcanic islands; at the other 

end, in Burma and China, it is in continental material with 

folded mountains. Again there are great age differences 

and differences in every aspect of the geology in which 

the oil fields exist; but here we have a unifying feature, 

namely the belt of earthquakes and volcanoes which 

stretches over this entire length and which points to causes 

in the deeper crust or in the mantle. 

• 

• 

X 

• 

0 

Many other examples can be cited, and they all point 

to the same conclusion: oil-rich regions seem to be defined 

by much larger scale patterns than those we see in the surface geology or topography of the region. 

Another global observation of similar significance is 

the vertical stacking of hydrocarbons deposits according to 

Kudryavtsev's rule: "Any region in which hydrocarbons 

are found at one level will be seen to have hydrocarbons 

in large or small quantities, but at all levels down to and 

into the basement rock." The most common sequence is to 

find gas at· the deepest ievels, oil above, sometimes more 

gas above the oil, and coal at the shallowest levels. If one 

examines gas, oil, and coal maps of different parts of the 

globe, one finds this rule upheld very frequently. It holds 

in most of the Middle East: many oil wells in Iran have 

EXPLANATION 

Producing oil or gas field 

on or gas indication (seep, show, sealed well, 

or mud volcano) 

Volcano (active or extinct) 

Major earthquakes: M~8.0 (1897-1972) 

Earthquake regions: M~4.5 (1963-1972) 

Shallow and intermediate focus (<300 km) 

NEW 

GUINEA 

Figure 3. Petroleum and tectonic map of Southeast Asia. The map shows the belt of hydrocarbon occurrence 

paralleling the volcanic and earthquake belt from New Guinea, through the southern islands of Indonesia, Java, and 

Sumatra, through the Andaman Islands and on into the Irrawaddy valley of Burma and the mountains of southern 

China. Data compiled from World Seismicity Map (Tarr, 1974) and from the Oil and Natural Gas Map of Asia 

(revised 1975), published by the United Nations Economic and Social Commission for Asia and the Pacific 

(ESCAP). M, earthquake magnitude. 
68 THE FUTURE OF ENERGY GASES 

penetrated through large coal deposits. Deep underneath 

the oil of the Gulf States, large gas fields have been discovered. Almost all the oil wells of Java and Sumatra have 

drilled through coal, and even the deep gas of Oklahoma 

is often underneath coal. What we are seeing is principally 

a succession of hydrocarbons with diminishing hydrogen 

content as one goes from the deepest to the shallowest. 

One presumes that bacterial action, which attacks the hydrogen-rich hydrocarbons first, has been largely responsible for the progressive hydrogen depletion of upwelling 

hydrocarbons. For coal, the situation is more complex because biological factors can be involved in another way 

also. In a hydrocarbon outgassing area, the groundwater is 

strongly anoxic because hydrocarbon-oxidizing bacteria 

are abundant there and quickly remove atmospheric oxygen carried in that water. The result is that the normal processes of fermentation of plant material, which would turn 

the carbon back into the atmospheric C02, will be interrupted. Hydrocarbon outgassing areas tend to become 

swamps filled with the insoluble carbon of plant material. 

What plant fossils there are in bituminous coal (frequently 

there are none) are often themselves filled with the same 

homogeneous coal as that which surrounds them, suggesting a carbon source different from the fossilized plant material itself. It would not seem possible that plant material 

was converted into the homogeneous coal, and yet that a 

fraction survived as fossils with a precise maintenance of 

detail, and that these fossils were then filled by the homogeneous coal derived from similar material. 

The huge gas deposits in the form of methane hydrates in the oceans may not have an adequate explanation 

in terms of the plant debris of the ocean mud. There is 

often little organic mud, and its gaseous products would 

not have migrated downward. Yet it has been said by the 

Russian investigators (for example, Makogan, 1988) that, 

so far as they could see, in every location on the ocean 

floor and in the permafrost of the northern areas where the 

temperature-pressure situation would make methane hydrates stable, such hydrates are found. As the deeper ocean 

regions are being investigated for hydrates, the inadequacy 

of a biological source material for them may become even 

more obvious, since the biological deposits in the deep 

ocean tend to be much smaller than in the continental 

shelf regions that have been the principal targets of gashydrate investigation so far. 

Every deep hole that has been drilled into crystalline 

basement-by several Soviet deep drilling programs, by 

the German ongoing deep-drilling efforts, by deep drilling 

into Swedish granite-has shown the presence of hydrocarbons at depth. While the quantities vary regionally, the 

indications we now have point to a ubiquitous presence of 

some amounts of hydrocarbons at deep levels everywhere. 

Even small amounts of methane or of hydrogen at the 

deeper levels in the rocks show that equilibration between 

the oxygen fugacity of the rocks and of the fluids has not 

taken place, since in chemical equilibrium these fluids 

could not be present. The explanation for this disequilibrium is that only a small fraction of the volume of the rocks 

could equilibrate by diffusive processes with the fluid 

streaming through pores; the pore fluids determine the oxygen levels in these cracks, the rest of the rock takes no 

part. Chemical equilibrium calculations are meaningful 

only in situations where the rocks and the fluids are much 

more tightly intermixed, such as in gases streaming 

through molten rocks. There each moving gas bubble 

keeps meeting new rock material to provide oxygen, and 

in such circumstances most carbon reaches the surface in 

oxidized form as C02. In solid rock there is a mixture of 

various proportions of methane and C02, frequently with 

methane as the major quantity. 

Since methane-hydrate formation is a very efficient 

means of retaining any upward-streaming methane, even 

regions with low rates of methane emission would still 

build up hydrates in the long course of time. C02 hydrates 

could exist also, but very few of these have so far been 

found, presumably because the cool, nonvolcanic regions 

produce mainly methane, and the hot regions do not allow 

formation of hydrates. If plant debris were responsible for 

the formation of the hydrocarbons, C02 would be a major 

component of the gases produced, and C02 hydrates 

should be common. 

If hydrocarbon outgassing is in fact a major source of 

the surface carbon excess, then one must of course consider whether it is also a major source of all the carbonaceous deposits that are found in the crust. Any other 

mode of deposition could not explain the frequent compliance with Kudryavtsev's rule. 

It has often been argued that oil deposits are in the 

vicinity of "source rocks," rocks that contain carbonaceous 

materials which have been assumed to come from biological deposits. Most commonly these rocks are shales, and 

their hydrocarbon content often shows a close chemical 

match to that of the oil pool in the vicinity. This match has 

been taken to verify the source-rock concept, but it would 

only do so if these shales were generally particularly rich 

in discernible fossils. This is not the case, and there is no 

reason for attributing their hydrocarbon content to anything other than a supply from the same source as that of 

the neighboring oil. The so-called source rocks can be regarded as a further demonstration of Kudryavtsev's rule. 

INTERPRETATIONS BASED ON 

CARBON STABLE ISOTOPES 

Carbon has two stable isotopes: 12C (6 protons, 6 neutrons) and 13c (6 protons, 7 neutrons). The natural carbon 

on the Earth contains predominantly 12C, and 13c is 

mixed in at a level of approximately I percent. This mixing ratio must have been determined in the nuclear pro-
THE ORIGIN OF METHANE IN THE CRUST OF THE EARTH 69 

cesses in the stars that cooked up the elements and 

eventually supplied them to form the planets. There are no 

processes that could occur on the planets that would be 

able to change this ratio greatly. Only small variations can 

be produced, not by any effects on the nuclei themselves, 

but by processes that show a slight preference and select 

in favor of either the light or the heavy isotope. 

The study of the distribution of the carbon isotopes in 

relation to petroleum and natural gas has a very extensive 

literature. We shall discuss here only one aspect of it: can 

isotope measurements determine whether a hydrocarbon 

compound was derived from biological material or whether it is primordial? Because many petroleum geologists 

have considered that such a distinction can be made, and 

that petroleum and natural gas appear on that basis to be 

usually of biological origin, it is clear that we must address this aspect here. 

A selection process that enriches one or the other isotope is usually referred to as a process of fractionation. 

The resulting fractionated material is referred to as isotopically light or isotopically heavy, depending on the ratio of 

the lighter to the heavier isotope. Measurements of the 

slight variations in the carbon isotope ratio in different 

samples is usually not done in absolute terms, but by comparison with a standard, and the small departures from this 

standard are then the quantities noted. The standard that 

has been selected for this purpose is C02 prepared from 

belemnites collected from the Upper Cretaceous Peedee 

Formation of South Carolina, a marine carbonate rock. 

The standard is called Peedee belemnite, or PDB, and it 

has a carbon isotope value that is about in the middle of 

the distribution of values for all the marine carbonates. 

The measurements are then quoted as the departure of the 

13C content of the sample from that of the standard, and 

the figure is usually given in parts per thousand (permil) 

and referred to as the 613C value of the sample. 

Unoxidized carbon in plants is derived from atmospheric C02 by the process of photosynthesis. In this process the light isotope, 12C, is slightly favored. As a result 

this carbon is slightly depleted in 13C relative to atmospheric C02, and the effect is larger than that occurring in any 

other single nonbiological chemical process recognized in 

nature. When it was found that most of the deposits of 

unoxidized carbon, such as petroleum, methane, coal, and 

kerogen, show also a marked depletion of 13c, it was considered that this depletion confirmed the deposits' biological origin. 613C for plant organic carbon is generally in the 

range of -8 to -35 permil (PDB standard). The atmospheric 

C02 from which that carbon was derived has a 613c value 

of -6 perrnil, showing the possibility of a large fractionation 

effect. Marine carbonates laid down from atmospheric C02 

dissolved in ocean water have 613C values ranging from 

about +5 to -5 permil (average 0), and thus evidently a 

fractionation averaging 6 perrnil occurs in favor of the 

heavy isotope during that process. 

In the production of methane from plant debris a further fractionation takes place that again favors the light 

isotope, and plant-derived methane is therefore isotopically even lighter and its 6 13C plots at -50 to -80 per mil. In 

the literature we now find that some arbitrary division has 

generally been assumed, so that carbon with 613C values 

lighter than -30 permil is regarded as of biological origin, 

whereas heavier carbon is taken to be from some other 

source. 

There is no clear division in the actual data. Carbonaceous materials have 613C values spanning the range 

from +20 to -110 permil on the Earth, and these values 

span an even larger range in the carbonaceous meteorites. 

There is no natural dividing point in the data, and the use 

of a particular figure in this continuous distribution to 

make the distinction between organic and inorganic origin 

seems very arbitrary. The question is, of course, what 

other fractionation processes can select in favor of the 

light isotope. 

A look at the distribution of the carbon isotope ratio 

in different natural forms of carbon gives immediately a 

strong suggestion (fig. 4). Methane, the only carbon-bearing molecule that is light enough to suffer significant isotopic fraction, shows the largest spread of values. The 

atmospheric C02 from which marine carbonates have been 

deposited throughout geol;gical time seems to have had a 

remarkably constant isotopic ratio, so that 613C values for 

nearly all these carbonates fall into the range of -5 to +5 

permil. 613C in petroleum has a fairly narrow range, from 

-20 to -38 permil. Carbonate (calcite) cements in the rocks 

have 613C values spanning the second-widest range. This 

fact by itself would suggest that the carbonate cements are 

generally produced from methane. That the range of 613C 

values for carbonate cement is 20 to 40 permil heavier 

than the range for methane suggests that a fractionation 

occurs when methane is oxidized in the ground and then 

Diamonds 

Atmospheric C02 

Marine Limestone 

Carbonate Cement 

Methane 

Carbon in plants 

Petroleum 

-100 -80 -60 -40 

813C (%.), PDB Scale 

-20 

rnmm 

~ 

0 20 

Figure 4. Distribution of ratio (expressed as <'1 13C) of the stable 

isotopes carbon-13 and carbon-12 in different terrestrial materials. Methane and carbonate cements span a much larger range of 

these isotope ratios than all other forms of terrestrial carbon. 

PDB, Peedee belemnite. 
70 THE FUTURE OF ENERGY GASES 

combined with calcium oxide to produce the carbonate cement. Everything in the data points to such a process. 

These cements are found in great quantities overlying gas 

and oil fields. They are usually isotopically lighter than 

marine carbonates, the lightest among them having 613C 

values as light as -65 permil. Where methane and carbonate cements are found in the same location, the methane is 

usually isotopically lighter than the carbonate by 613C differences ranging from 20 to 60 permil. The overall isotopic distribution of methane and carbonate cements show a 

similar shift. 

Galimov (1969), a major contributor to the carbon 

isotope investigations, saw that in any vertical column 

methane tends to be isotopically lighter at progressively 

shallower levels. This appears to be true irrespective of 

the type or age of the formation from which the sample 

was taken (fig. 5). It is most unlikely that in all those 

cases methane from two different sources mixed to produce the observed trend. A much better explanation is 

that a progressive fractionation of the methane took place 

in its upward migration. Some of this methane appears to 

be lost to oxidation, ending up as C02 (fig. 6), and a 

fraction of that C02 is transformed, in turn, into calcite 

cement. This oxidation process seems to select the heavy 

isotope, and so the remaining methane gets isotopically 

lighter on the way up. At each level the calcite is thus 

derived from the already-fractionated methane, and so it 

also will be lighter, tracking the methane but always remaining heavier than the methane at that same level. 

Progressive fractionation is an important process because it can drive the remaining material to a very much 

greater fractionation than could be done by any single 

chemical step. It is of course the technique used for comIll 

01 

... 

-01 

::g 

500 

2500 

-30 -70 

• • -:r• •. 

.. 

Figure 5. Carbon isotope ratios (expressed as o13C) of methane 

plotted against depth of occurrence (from Galimov, 1969). Although there is much variability in this relationship, it is almost 

always true that where methane is found at different levels in the 

same area, the methane is isotopically lighter (contains less carbon-13) the shallower the level. 

mercial isotope separation, in which extremely large fractionation factors are required. In the case of progressive 

fractionation of methane, two effects help to create the result. One is the tendency for the oxide to bind slightly 

more tightly with the heavier carbon isotope (in C02); in 

equilibrium conditions at a low temperature the heavy isotope will therefore be enriched in the oxide and depleted 

in the remaining methane. The other effect is the diffusion 

speed, which for methane with the heavier isotope and a 

mass number of 17 will be 3 percent slower than for light 

methane with a mass number of 16. This difference means 

that in any circumstance where methane is diffusing 

through a barrier to fill a reservoir, the methane entering 

initially will have a 30-permil enrichment in the light isotope ( 12C). If this reservoir were to fill another, the lightC02 CH4 

513 

C ("/oo) 

s;.13 

U C (Ofoo) 

0 -10 -20 -70 -80 -90 -100 

0 

Ul 

~ 

-

01 

5 100 

... 

0 

~ 

0 ... 01 

Ill 

~ 200 0 

01 

.D 

.s:; 

-a. 

01 

0 

300 

400 

Figure 6. Comparison of the carbon isotope ratios (expressed as 

o13C) of methane and coexisting carbon dioxide in ocean-floor 

sediments (from Galimov and Kvenvolden, 1983). The carbon 

isotope ratios of the two gases seem to follow the same depth 

dependence, but with the C02 always isotopically heavier than 

the methane. This is the pattern to be expected if progressive 

fractionation were happening, with the C02 produced (probably 

by bacterial oxidation) from methane moving upward through 

the crust. Both the methane and the C02 produced would become isotopica:Ily lighter on the way up, but the C02 would be 

heavier by a constant amount than the methane from which it 

was derived. (This is not the interpretation given by the authors 

of the article). 
THE ORIGIN OF METHANE IN THE CRUST OF THE EARTH 71 

isotope enrichment would augment. Differential removal 

by oxidation, by different solubilities in water, by different 

adsorption on solids, and by bacterial attack will affect the 

final result of a slow percolation of methane through diverse strata of rock. Since in any such progressive fractionation the final effect can be arbitrarily large, one 

cannot conclude that a large fractionation implies as its 

cause a single-step process, namely the one that occurs in 

plants. 

The constancy of the isotopic ratio of marine carbonates spanning all ages deserves further comment. If at any 

time between the Archean and the present a large change 

had taken place in the amount of plant debris that was 

buried, and if this plant debris was, as is usual, isotopically light, then more of the light isotope would have been 

taken out of the atmospheric-oceanic C02 reservoir. The 

remaining C02 in that reservoir would have been driven to 

a slightly heavier composition. If as much as one-fifth of 

the buried carbon was in the form of such plant debris, 

then the shift in the isotopic composition of the remaining 

atmospheric carbon and the resulting shift in the isotopic 

composition of the carbonate deposits laid down from it 

should have been readily observable. When land vegetation suddenly proliferated in Silurian til]le, for example, 

one might well think that twice as much unoxidized plant 

material was buried as before this event. Why is there no 

change in the isotopic ratio of marine carbonates deposited 

in that epoch? An explanation that the primordial carbon 

supply suffered a change in the isotopic ratio just sufficient to compensate is improbable. A more likely explanation is that the quantity of biological debris that is buried 

is a much smaller fraction than is usually assumed. The 

reason for this may be that the identification of much of 

the buried carbonaceous material as plant debris is not 

correct and that a large proportion of this material was derived directly from hydrocarbons ascending from the mantle. The extra contribution made by the time-variable 

burial of plant debris may then be so small an effect that it 

does not show in the isotopic ratio of the carbonates. This 

would be the case if all the dispersed kerogen and the oil 

shales, which have been regarded as source material for 

oil pools, were derived from the primary hydrocarbons. It 

is worth noting that the amount of carbon that would have 

been contained in certifiable fossils is a very small quantity by comparison. 

The remarkable constancy of carbon isotope values of 

marine carbonates also sheds light on the question mentioned earlier, about the amount of carbon that may be 

coming up as a result of the heating of subducted sediment. In such heating some or all of the carbonates may be 

dissociated and the C02 may come to the surface. Much of 

the unoxidized carbon that is in the same sediment, whether derived from plants or from a primordial hydrocarbon 

supply, is known to be isotopically much lighter than the 

carbon in marine carbonates. Of the unoxidized carbon, 

only a fraction would be turned into liquids or gases, limited by the availability of hydrogen; the remainder would 

eventually turn into elemental carbon-graphite or anthracite-and in that form it would be insoluble and stable, 

and would not be returned to the atmosphere. A process of 

multiple recycling of sedimentary carbon would therefore 

always take away more of the light isotope than of the 

heavy, and this would drive the atmospheric-oceanic C02 

to a heavier isotope value. Because such a trend is not 

observed, recycling of sediments cannot account for a significant fraction of the resupply of atmospheric C02 over 

geologic time. 

THE HELIUM ASSOCIATION 

WITH PETROLEUM 

On the basis of hydrocarbon outgassing from great 

depth, we understand immediately why various trace elements, especially helium, should be so commonly associated with deposits of oil and gas. The long pathway 

through pressure-created fracture porosity in the rocks 

will, of course, sweep up whatever helium was available 

in those pores. Helium is generated in the rocks by the 

radioactive decay of uranium and thorium, but at too low 

a concentration to create a fracture porosity or hold it 

open. Its transport is therefore dependent entirely on a carrier gas, such as the more abundant hydrocarbons may 

provide. Helium is not only strongly associated with 

hydrocarbon deposits, it has even been noted to be particularly enriched in gas-oil reservoirs, more so than in drygas reservoirs (Nikonov, 1973). Helium is also particularly 

enriched in reservoirs having a high nitrogen content. Any 

chemical or biological cause for the enrichment can be 

ruled out for the chemically inert helium. Only variations 

in the concentrations of the parent radioactive elements, 

and variations in the length of pathway through the rocks 

from which the helium has been swept, can come under 

consideration as an explanation of the great regional differences of the observed helium concentration. Where 

large variations have to be explained, such as by a factor 

of 100 or more from one location to another, the length of 

pathway through which the carrier gas has swept is likely 

to have been the dominant variant. If carrier gases from a 

depth of 300 km are involved in one case, whereas gases 

only from the depth of sediment are involved in another, 

then this variant will outweigh any likely variation in the 

concentration of the radioactive elements. The helium concentration in a gas is then mainly an indication of the 

depth from which this gas has come. With this explanation 

one would conclude that of all the volatile elements or 

compounds, nitrogen frequently is derived from the deepest levels, oil from the next deepest, dry methane sometimes from shallower levels still, but all from levels far 

deeper than the sediment. Helium enrichment is not found 
72 THE FUTURE OF ENERGY GASES 

in sediment in the absence of larger amounts of hydrocarbons or nitrogen, and I 0-percent helium in methane-nitrogen gases is the highest concentration that has been found. 

Yet if helium could flow without a carrier gas, there 

should be many locations where amounts of helium had 

accumulated that were similar to the amounts of helium in 

some gas fields, but, in the absence of methane or nitrogen, these accumulations would be pur~ helium fields. 

Such fields would have been discovered and would be 

very valuable. Their absence thus supports the carrier-gas 

concept for helium transport. 

Some information can be gained from a study of the 

isotopic composition of the helium. Helium has two stable 

isotopes, helium-4 and helium-3. Most of the helium found 

on Earth is helium-4, the result of the radioactive decay of 

uranium and thorium. In the atmosphere helium is present 

at a concentration of 5.24 ppm by volume. The helium-3 

isotope, which is much less abundant, is present in the atmosphere at about 1.4 parts of helium-3 to a million parts 

of helium-4. In the surface of the Sun and in the solar wind 

one observes a ratio of helium-3 to helium-4 of 3xlo-4, or 

about 200 times higher than the ratio in our atmosphere. 

The primordial helium that was incorporated in the 

Earth as a small impurity in the rock grains must have 

been more similar to the solar composition and thus much 

richer in helium-3 than any present-day terrestrial helium. 

But the total quantity that was brought in by the grains 

was small, and so the continuous production of helium-4 

from the radioactive decay became the major contributor 

to helium in all locations on the Earth. 

While a small proportion of helium-3 can also be produced by radioactivity in an interaction involving uranium 

and lithium, this interaction is not thought to be a major 

contribution to the Earth's helium-3. The lithium production of helium-3 in the most ideal circumstances, where 

lithium and uranium are in close association, could be as 

high as to give 3HefHe ratios of 1.2x 1 o-5, or ten times 

the ratio in the atmosphere (Morrison and Pine, 1955). But 

this high production would occur only in some rare minerals, and the average production of helium-3 in the crust of 

the Earth has been estimated as at least a hundred times 

lower. These figures mean that in any location where we 

find a helium-3 to helium-4 ratio of more than one-tenth 

the atmospheric value, it is probably due to a contribution 

of some primordial helium. In those cases we then know 

that we are dealing with a gas that has at least a component that must have come from deep rocks, since the crust 

in its formation would have largely outgassed, and primordial helium would not have been maintained there. 

However, we cannot assume the converse. Where the 

proportion of helium-3 is low, the gas may well have come 

from mantle depths also, since in a mantle that was never 

all liquid, the gas content could never have become a uniform mix, nor could it have remained a uniform mix if the 

rates of outgassing were different in different regions. 

Where a carrier gas has washed through pore spaces 

that it has created, it will have transported the mix of primordial and radiogenic helium that happens to have been 

there. If such a flow has been going on for a long time, 

then the primordial component will have been depleted, 

while the continuously produced radiogenic component 

will still be present. The helium-3 proportion will have 

suffered a dilution throughout the existence of this flow. 

Pore spaces that have been flushed for a long time would 

have low helium-3 values, but there would be no reason to 

assume that such gases were derived from a smaller depth. 

While high helium-3 values indicate young pathways from 

mantle depths, low helium-3 values do not give a firm indication of the depth of origin of the helium. A great concentration of any helium, however, suggests that sweeping 

by a carrier gas on long pathways has been responsible, 

and thus a high concentration is in itself an indication of a 

deep origin for the helium. 

The partial pressure at which helium is found, whether 

under a caprock or anywhere else, may also serve as in 

indication of its depth of origin. As an inert gas, helium 

cannot have had its partial pressure increased from that of 

its point of origin by any chemical action. In any flow, its 

partial pressure must always decrease; only the (unlikely) 

circumstance of a mechanical pumping action could ever 

cause an increase. Helium must have been derived generally from a location where the radioactive decay could 

produce the partial pressure at which the helium is found, 

or a yet higher one. This is an important consideration in 

estimating whether helium in a given location could come 

from the radioactivity of the surrounding rocks or whether 

it has come from greater depths. For this calculation one 

has to take into consideration not only the local concentration of uranium and thorium, but also the rock's helium 

porosity (the volume of pore spaces large enough to be 

occupied by the helium atom, which includes many imperfections in the rock crystals and will therefore represent a 

larger volume than the porosity presented to a gas of larger molecular size). At deeper levels, where the rocks are 

subjected to a high lithostatic pressure, the helium porosity 

will be small, and a given radioactive concentration will 

send the resulting helium into smaller volumes, and therefore set up correspondingly higher partial pressures. This 

consideration shows that in many locations, even where 

natural gas has a comparatively high helium content, the 

local rock cannot have supplied the helium. It explains 

why helium measurements at or near the surface seem to 

be successful as a means of finding hydrocarbons underneath (Roberts, 1980), but rarely successful as a means of 

prospecting for uranium deposits. 

Regional patterns of helium abundance have been observed in which the helium concentration and the helium 

partial pressure are far higher than the sediments could 

have produced in their entire age (Pierce and others, 

1964), but where the patterns of gas composition (ratios of 
THE ORIGIN OF METHANE IN THE CRUST OF THE EARTH 73 

components) span horizontally over areas very large compared with that of any particular gas field of the region. 

The helium must certainly have come from below the sediment, and it must have arrived there already in regionally 

well-defined mixing ratios with methane and nitrogen, so 

that the different fields of the region could all be filled 

with the same or a closely similar mix. Only a mix that 

had entered the sediment and its individual gas fields from 

below could achieve that effect (Gold and Held, 1987). 

RELATION OF OUTGASSING OF 

HYDROCARBONS TO ATMOSPHERIC 

OXYGEN 

The problem of the maintenance of the atmospheric 

oxygen levels within the bounds suggested by the geologic 

record has not yet been solved satisfactorily, but it is clearly 

closely related to the carbon supply. Photosynthesis in the 

plants produces free oxygen by the dissociation of water. If 

none of the products of photosynthesis escaped from the 

circulation of atmosphere and biosphere, if fermentation 

returned all the content of carbon and hydrogen in plant 

debris back to the atmosphere as carbon dioxide and water 

(the form in which it was taken up by the plants), then there 

would be no net gain or loss of atmospheric oxygen. If 

some hydrogen were to escape, however, as hydrogen does 

escape from the upper atmosphere into space, or if it were 

laid down in hydrides or other hydrogen compounds in the 

sediment, then for every two hydrogen atoms so removed, 

there would be one oxygen atom that would constitute a net 

addition to the atmosphere. 

If all the fresh carbon supply that the atmosphere receives came in as C02, and if all the carbon laid down in 

the sediment were in the form of carbonate rocks (that is, 

CaO from rocks combining with C02 to make CaC03), 

then also this process would neither add to nor subtract 

from the atmospheric oxygen. If, however, as is generally 

thought, about one-fifth of the carbon that is laid down is 

in the form of plant debris, then there would constantly be 

a large addition to the atmospheric oxygen. For each carbon atom that is so buried there would be at most one 

oxygen atom and at most two hydrogen atoms (polysaccharides such as cellulose are (C6H 100 5)x). Every carbon 

atom that came up from the mantle in the form of C02 

provides two oxygen atoms, while the burial of that carbon atom would bury only one oxygen atom and take 

away possibly as many as two hydrogen atoms that had 

been derived from the dissociation of water and would not 

now be available to reform a water molecule with its photosynthetically liberated oxygen atom. Thus, for every carbon atom laid down as biological debris, approximately 

two oxygen atoms would be liberated. For the figures 

given, of 20 kg/cm2 of total carbon laid down, one-fifth in 

biological materials, the total amount of oxygen left over 

to join the atmosphere would be I 0.6 kg/cm2 of 0 2. That 

is more than 50 times the present atmospheric oxygen 

content. All carbon being supplied as C02-one-fifth 

being laid down in plant debris and the rest as carbonate 

rocks-does not seem a possible scenario over long periods of geologic time. 

If a fraction of the juvenile carbon was supplied as 

CH4, the oxygen excess would be diminished because 

both the carbonates and the organic carbon would lay 

down some oxygen, and the left-over hydrogen would 

form water, using up more atmospheric oxygen. Of course 

this scenario could shift the balance toward no gain or 

even loss of atmospheric oxygen. But to maintain the atmospheric oxygen level within the bounds given by the 

geologic record, firstly the supply of carbon as methane 

and as C02 and secondly the laying down of carbon in the 

sediment would have to be balanced very precisely, since 

both processes involve such large quantities of oxygen 

compared to the atmospheric oxygen content. One could 

not attribute such constancy, nor the chance of just producing the balance, to tectonically controlled events over 

long periods of time. Some powerful stabilizing effect 

would have to be at work. 

What are the limits on the excursions of atmospheric 

oxygen content that the geologic record can provide? In 

all the times that forests have existed, oxygen levels cannot have been higher than at present by more than a few 

percent, for we are now not far from that concentration at 

which fires would make it impossible for forests and many 

other major land plants to survive. In earlier times, before 

the emergence of land plants in the Silurian, there may 

have been periods of higher oxygen values, and such periods have been suggested to account for the oxidation 

states of iron in some ancient sediments. The other limit, 

that of low oxygen values, can only be estimated from the 

oxygen requirements of animals both in seawater and on 

land, and from the oxidation state of some sediments. 

Again this limit cannot be set very far below the present 

values for all the periods back to the Devonian, in which 

oxygen-breathing fishes have existed. Before these epochs 

the limits may have been wider. 

What could be the stabilizing influences that are at 

work? The laying down of inorganic sediments may have a 

stabilizing effect, as these sediments can become more 

highly oxidized than the basement rocks from which they 

are derived. A large amount of sulfur may be present now 

in a more highly oxidized state than that in which it came to 

the surface. Another stabilizing effect may be the escape of 

hydrogen from the Earth into space. In the presence of 

smaller atmospheric oxygen values, more hydrogen liberated by photosynthesis could diffuse into the outer atmosphere without being caught by oxidation, thereby leaving 

more oxygen behind. It is doubtful, however, that such 

large quantities of oxygen could have been liberated or absorbed in these processes as would ·be required, or that the 
74 THE FUTURE OF ENERGY GASES 

stabilizing effect could have the required strength to keep 

the atmospheric oxygen levels within the narrow bounds. 

Perhaps the strongest stabilizing effect would be the 

control that the atmospheric oxygen concentration must 

have on the amount of plant debris that will be buried before being reoxidized. Higher oxygen levels in the air, and 

hence in groundwater, will diminish the areas of swamps 

and of anoxic lakes, ponds, and seas, the locations in 

which plant material would escape the fermentation processes that would tum the carbon back to C02, thereby 

taking away atmospheric oxygen. Conversely, low oxygen 

would favor anoxic deposition, leaving more oxygen behind. Possibly this effect could be sufficiently powerful. 

However with the imprecise knowledge of the amounts of 

plant material buried in different epochs, with the strong 

possibility that deposits of organic carbon are in part due 

to hydrocarbons from great depths and not all to plant debris, and with the inexact knowledge of the ratio of oxidized to unoxidized carbon in the primary carbon supply 

to the surface, no firm judgment can yet be made. 

THE MECHANICS OF THE ASCENT OF 

FLUIDS THROUGH THE CRUST 

There are two principal methods of ascent toward the 

surface of fluids that are liberated in the mantle and that 

are of lesser density than the rock and hence buoyant relative to it. One is the ascent in volcanic regions, where 

magma, with its density closely similar to that of the surrounding rock, can hold open vertical pathways down to 

depths of I 00 kilometers or more. Any other fluids that 

can pressure-fracture the rock and make their way through 

cracks into such lava channels can then move upward by 

buoy;mcy forces and quickly reach the surface. Hydrogen 

and hydrocarbons would, as we have said, be largely oxidized in bubbling through magma, but the extent of this 

oxidation would of course depend on the relative proportions of hydrocarbons and magma at any time. There are 

strong indications that small amounts of gases coming out 

of volcanoes at quiet times are largely oxidized, whereas 

in violent eruptions the unoxidized gases-hydrogen and 

methane-are prominent. On many occasions flames have 

been reported during major eruptions and have been seen 

as quite distinct from the ejection of hot material. During 

the episodes of the Krakatoa eruption below the sea surface, following the major eruption in 1883, large regions 

of flames above the water were observed, in this case of 

course in the complete absence of any confusing sprays of 

lava. But even at quiet times some volcanoes emit enough 

combustible gases to bum above the lava lake. This phenomenon has been observed in the Hawaiian volcanoes 

and also in volcanoes of the African Rift. Volcanic eruptions in Java have delivered ashes containing several percent of unoxidized carbon. 

The other possible manner of ascent of fluids from the 

mantle is the buildup of sufficient fluid pressure to fracture 

the rock and create pathways (Gold and Soter, 1984/85). 

For such pathways to stay open, the pressure in the rock 

due to the weight of the overburden (the lithostatic pressure) must be closely similar to the fluid pressure in the 

pore spaces. Since rock is extremely weak in tension, a 

fluid pressure higher than the lithostatic value will quickly 

create more fractures. In compression rock is much stronger and pore-spaces will only be crushed shut when the 

pore-pressure deficit exceeds a certain value. If one considers fluids that are less dense than the rock, then any 

connected system of pore spaces filled with such fluids 

will have a smaller pressure gradient with depth than that 

of the surrounding rock. At the top of such a domain the 

pressure may be close to that in the rock (the lithostatic 

pressure). The bottom of such a domain will then have a 

deficit of pressure, and since this deficit cannot exceed a 

value defined by the compressive strength of the rock, 

there will be a limit to the vertical height that such a domain can occupy (fig. 7). In the volcanic case, the dense 

lava with its pressure gradient closely similar to that of the 

surrounding rock can keep open a channel to a depth of 

100 kilometers or more. In the case where the fluid is a 

hydrocarbon or water, and hence of much lower density, 

only an interval of a few kilometers can be held open: an 

interval whose height can be calculated from a knowledge 

:r: 

1--

o.._ 

w 

0 

j 

PRESSUREFigure 7. Schematic diagram showing pressure of rock due to 

overburden and pressure of fluid (less dense than the rock) in 

connected pore spaces. Pc denotes critical pressure difference 

(between rock pressure and fluid pressure) at which the rock 

compressive strength is inadequate to maintain pores. Dashed 

lines indicate fluid pressures that are physically unrealizable because of the limited compressive strength of the rock. 
THE ORIGIN OF METHANE IN THE CRUST OF THE EARTH 75 

of the compressive strength of the rock and the vertical 

pressure gradients in rock and fluid, given by their respective densities. 

These limitations do not mean that gases or liquids are 

prevented from making their way up. If fluids are evolving 

as a consequence of an increase of temperature or of 

chemical reactions taking place at depth, they may create 

fracture porosity and increase the pressure in such a domain of pore spaces. As more fractures are being created, 

the vertical height of the domain will increase. As soon as 

the height spanned exceeds the critical value, the rock at 

the bottom of the domain will crush shut. Such a domain 

may then be unstable and migrate upwards, driven by the 

force of buoyancy, much like a bubble of gas in a liquid 

makes its way up. Only here, in the presence of solid rock, 

it is not a round bubble but a region of rock with connected pore spaces. Just as the liquid above the bubble will 

split open while the liquid below it closes again, so will be 

the case with the rock above and below the pore-space 

domain. The rock itself does not move upward, but the 

domain of pore spaces with its fluid makes its way up 

through the rock. Above strongly outgassing regions in the 

mantle one may have a frequent dispatch of pore-space 

domains toward the surface. 

Another mode of upward flow is also possible. If the 

generation of fluid is continuous, a set of adjoining, stationary pore-space domains may be set up, and the flow 

may be in the form of a continuous or intermittent leakage 

from one to the next one above. The stability of such a 

flow will require that the drop in pressure from the top of 

one domain to the base of the next will occur as a result 

of the flow through the low permeability of the dividing 

layer (fig. 7). However the flow occurs, it must always 

adopt a stepwise pressure profile, with domains in which 

the fluid pressure gradient has almost precisely the static 

value, given by the density of the fluid, divided from the 

next domain by a region in which the fluid pressure gradient has a much higher value. (If the mass of fluid is small 

compared to the mass of rock, as would mostly be the 

case, then the average pressure gradient over a large vertical interval must be the lithostatic one in both rock and 

fluid.) Such a flow can be compared with a flow of a river 

from the mountains, which creates a system of cataracts. 

Consider the potential energy in the flow: pressure in one 

case, height in the other. In the case of the river, almost all 

loss of height occurs at the cataracts, the flow between 

them being almost quiescent and level. Similarly, in the 

former case, almost all the drop in pressure would occur 

not continuously but in a few sharply defined locations 

(fig. 7). 

If we look at this situation from the surface down we 

may find a system of connected pore spaces frequently 

filled with water, and we therefore define a pressure in the 

pore spaces that is called hydrostatic, and a pressure in the 

rock, called lithostatic. As the two pressure gradients with 

depth are dissimilar, a level must be reached where the 

rock will close. I have referred to this level as the "critical 

layer." Beneath the critical layer we can again have open 

pore spaces, but now only provided that they are filled 

with a fluid at a pressure exceeding the hydrostatic value 

that would be calculated for that depth, but not exceeding 

the lithostatic value. We may then have another domain of 

fluid-filled pores, but again only of a limited vertical 

height. The uppermost domain can be calculated to reach 

from the surface down to a depth of between 3 and 5 kilometers in soft rock, and possibly as much as 1 0 kilometers 

in hard rock. This is the domain in which most of the oil 

and gas exploitation has been done so far, but a comparatively small number of cases exist where the drill has gone 

through a sharp pressure transition and tapped the second 

domain. 

It should be emphasized that such a critical layer is a 

necessity dictated by the finite compressive strength of 

rock. It is thus a caprock layer which must overlie any 

region in which outgassing is occurring. As the strength of 

the rock is of course regionally quite variable, this critical 

layer may be far from level. It may be of a complex shape 

with large variations in height, and there may even be locations where it doubles over on itself. The main thing is 

that it has to be a continuous sheet. This is not to say that 

there may not be other layers of caprock in an outgassing 

region where a material of low permeability was laid 

down, and presumably all shallow gas fields have required 

the presence of such a caprock. The importance of the critical layer is that an outgassing region will inevitably possess that type of caprock at a sufficiently deep level. 

The critical layer, like other layers of caprock, will not 

have zero permeability, and there will be some leakage 

through it, as we have discussed. In a long-term steady 

state of a continuous upward flow, the leakage through the 

critical layer (and through all the similar layers at deeper 

levels) must occur at the mean supply rate. Nothing can 

change the flow rate of this upward stream: it is given by 

the production rate of the fluid below. All that any caprock 

or any critical layer can do is to increase the amount that 

is dammed up underneath it. The situation is similar to 

that of the flow of a river from the mountains to the sea, 

where, we may suppose, the rainfall producing the water 

all occurs up in the mountains. On the way down, the 

river will transport all the water that has been collected, 

and if the river is dammed up anywhere along its length, 

the steady state flow rate will not be changed. All that the 

dam will do is create a lake on the upstream side of it, but 

finally the amount of water flowing over the dam will be 

exactly the same as that which would have flowed without 

the dam. 

This is an important consideration from a practical 

point of view. One has observed that over natural-gas 

producing regions the amount of methane and other hydrocarbons in the soil is greatly enhanced, sometimes by a 
76 THE FUTURE OF ENERGY GASES 

factor of one hundred or more, and any attempts at deducing a flow rate to account for this enhancement gives such 

high rates of methane seepage as to appear incompatible 

with a supply coming only from a gas field below. The 

technique of surface chemical prospecting, such as measuring the soil methane, has been described by some as 

necessarily in error, since it was not conceivable that the 

outflow rate could be so high that the gas field would be 

exhausted in a few thousand years. But of course if there 

is a continuous gas supply from below, and at rates that in 

no way conflict with the limits we can place on such outgassing processes, then it will make good sense to observe 

the surface concentrations of hydrocarbon gases. It would 

also make good sense to extend this technique and introduce tracer gases in a well at some depth, and observe the 

time it takes for the tracer gases to appear in the surrounding soil. From this, and the knowledge of the porosity of 

the ground, an actual flow rate can be established, and so 

one could evaluate for any region how much methane per 

day or per year is seeping out. 

Regions that have a high seepage rate will in general 

be favorable ones for finding good reservoirs, since for a 

seal or caprock of a given quality a larger quantity of gas 

is likely to be dammed up underneath that seal. Surface 

gas prospecting has been certified over many known gas 

fields, the outstanding example being the Cement Field of 

Oklahoma. The technique is yet to be used on a large 

scale in the search for more gas. 

In several regions of the United States, drilling to 5 

kilometers (approximately 15,000 ft) or deeper has revealed 

the sharp pressure discontinuity (at the critical layer) to 

which I have referred. All of the deep gas in the Anadarko 

Basin is below this discontinuity, and there all the deep gas 

seems to form essentially one reservoir. In Louisiana and 

neighboring areas of the Gulf Coast, the pressure discontinuity is a little shallower and the continuous sheet represented by it has been carefully mapped (Jones, 1980), with 

the infopnation available from a large number of wells and 

the interpolation between them from seismic data. In Oklahoma there is, in some instances, a dramatic increase in the 

porosity below the critical layer. Porosities as high as 18 

percent have been found below 20,000 feet in the carbonate 

rocks (Hefner, this volume). It is clearly not possible to 

account for this large porosity by any process of enclosing 

a rock volume tightly and then compressing it to achieve 

the gas pressure in the pores. Since that gas pressure is 

roughly twice that above the critical layer, one would have 

to contemplate an initial gas-filled porosity of 36 percent, 

and then compression of these pores to half their initial 

volume. Thirty-six percent is not a value that has ever been 

seen. The conclusion must be, therefore, that the gas has 

entered from even higher pressure regions deeper down, 

and that it has expanded pore spaces to these values. Investigations of the details of the fracture patterns in the rocks 

confirm such an explanation. 

We may then describe how a flow of hydrocarbons 

from depth may take place. As I have discussed, a high 

proportion of saturated compounds would indicate that 

methane was a major component that dilutes the stream. 

But at shallow levels where the pressure is low, the heavier hydrocarbon molecules will be shed from the stream. 

The largest such effect will take place at the flow through 

the last pressure discontinuity on the way up, the shallowest critical layer. It is there that the oils are likely to be 

deposited, being now viscous and easily retained, while 

much or all of the gases can continue upward and largely 

escape into the atmosphere. Oil deposits are concentrated 

laterally because major faults have facilitated their ascent 

and have caused a confluence toward them, and the oil 

deposits are concentrated vertically because of the sharp 

pressure changes in going from one pore-space domain to 

the next, at which oil and gas get separated. 

RESULTS IN SWEDEN 

The distinction between hydrocarbons derived from 

biological materials and hydrocarbons of primordial origin 

would be made most clearly by examining igneous or 

metamorphic rocks that could not have maintained either 

hydrocarbons or biogenic materials capable of producing 

them before they froze to their present condition. If crude 

oil, methane, and other hydrocarbon gases can be found in 

such locations, at depths that would exclude a seepage 

down from above, then their presence would demonstrate 

an origin from sources below. 

Crude oil has been found and produced from crystalline basement rocks in numerous locations, but mostly in 

places where transport from neighboring sediments could 

be invoked as an explanation. The clearest example we 

have cif a location where hydrocarbon production from 

sedimentary materials can be excluded comes from two 

deep boreholes in the granitic rock of central Sweden 

(Gold, 1991). 

As already noted, the granite and gneiss of Sweden 

have many signs of impregnation. with hydrocarbons. Tar 

is frequently found during tunneling and mining operations as a substance filling cracks in the granite. Methane 

explosions and prominent shows of methane have been 

seen frequently. If hydrocarbons come from depth, one 

might judge that the large granitic block which makes up 

most of Sweden overlies an area of mantle that is particularly hydrocarbon rich, and one might think that the hydrocarbons of the Norwegian Trench or of the countries 

surrounding the Baltic Sea signify an outflow from this 

area of the mantle. Fractures of the rock within Sweden 

may then have been conduits for hydrocarbons from the 

same source. 

It is with this consideration in mind that I persuaded 

the Swedish government to study the region of a giant 
THE ORIGIN OF METHANE IN THE CRUST OF THE EARTH 77 

meteoritic impact crater, the Siljan Ring in central Sweden. An impact that left a circular formation 44 kilometers in diameter would undoubtedly have fractured the 

rock to great depth, and one might therefore expect this to 

be a particularly favorable location for finding upwelling 

hydrocarbons. 

It was quickly ascertained that just the area of the Siljan structure was quite anomalously rich in soil methane 

and other light hydrocarbons, that many ordinary water 

wells produced copious amounts of gas, and that a number 

of stone quarries in the area had oil seeping out of the 

rocks and making oil pools in the ground. It is true that 

the stone quarries were in the sedimentary rock that fills a 

ring-shaped depression, but those sediments are nowhere 

deeper than 300 meters. Oil seepage generated after 360 

million years from such a small quantity of sediments 

seems improbable. Aside from the ring-shaped depression, 

the basement rock is very close to the surface in the whole 

area; there is barely enough soil for the trees to grow both 

inside and outside the Siljan Ring. 

As a result of the clear demonstration that the area 

was quite anomalous for its hydrocarbon content, it was 

decided to engage in a major drilling operation. Since 

I986 two wells have been drilled: one to a depth of 6. 7 

kilometers, the other to a depth of 6.5 kilometers. Both 

holes showed the presence of methane and of other hydrocarbon gases, as well as of crude oil. Whereas in the first 

hole (Gravberg I) diesel oil was used for a time as a component of the drilling mud, only water-based mud was 

used in the second hole (Stenberg 1 ), which is situated in 

the center of the ring and is 12 km distant from the ring 

sediments and from Gravberg I. Although the detailed 

chemical makeup of the oil found at deep levels in 

Gravberg I was not the same as diesel oil, many considered nevertheless that the diesel drilling oil could be held 

responsible. Some 15 tons of oil were pumped up, oil that 

h.ad hydrocarbon components and organometallic compounds that are frequently in natural crude oils, but were 

absent or present only in very much lower abundance in 

any of the drilling fluids. Some biological molecules, steranes, were found to be from the same set and in closely 

similar ratios as had been seen in the surface seepage oils 

(fig. 8), and this similarity strengthened the case that the 

two oils had a common origin. Steranes are thought to be 

derived from sterol, a component of methane-oxidizing 

bacteria. 

In both holes the hydrocarbon content of the rocks increased with depth, and in both holes high spots in methane 

and also in heavier hydrocarbons were in the locations in 

which volcanic intrusive rock, dolerite, was present (fig. 9). 

The carbon isotope ratio (<'1 13C) of the methane became heavier with increasing depth, and in the dolerite 

zones and their immediate surroundings it was as heavy as 

between -12 to -15 permil in the Gravberg 1 well, and -7.2 

to -7.8 permil in the Stenberg 1 well. In both wells the 

12 

10 

!II 8 Cll 

u 

c 

Ill 

"C 

c. 

:I 6 .c 

Ill 

Cll 

> 

~ 4 Gi 

a: 

2 

0 

Solberga oil Tretaspis Shale 

EXPLANATION 

flil C 27 R 

IPJ C 28 R 

~ C29S 

~ C29R 

Black material 

Figure 8. The four most prominent biomarker molecules, steranes, found in the oils of the Siljan region, Sweden. The steranes 

are present in similar proportions in surface-seep oil (Solberga 

quarry), local near-surface oil shale (Tretaspis Shale), and oil in 

black sludge obtained from 5.6 km depth in Gravberg I well. 

This similarity indicates a common origin of all three oils. The 

identity of the four sterane molecules is given in the usual notation by the number of carbon atoms and the right or left symmetry of the molecule. 

2000 

c 

~ .E 

~ .. 1000 t: 

[ 

,; 

~ 1i> 

:; 

19.000 19.500 20.000 

Depth, feet 

20.500 21.000 

Line indicates presence of dolente, double line indicates high proportion 

21.500 

Figure 9. Stenberg I well, Sweden: Methane content of drill cuttings as function of depth. Presence of intrusive volcanic rock, 

dolerite, is marked below graph, showing correlation with high 

spots of methane readings. Heavier hydrocarbons were also measured, and were largely in step with methane. 
78 THE FUTURE OF ENERGY GASES 

helium concentrations were frequently as high as several 

percent of the total gas present, and possibly exceeding the 

highest concentration seen in any well. 

The investigations during the drilling of Stenberg 1 

gave the clearest indication that a range of hydrocarbon 

gases and liquids had indeed entered from deep levels. 

The content of hydrocarbon gases and liquids (aromatics) 

in the drill cuttings was carefully measured at every 5-ft 

interval during drilling. It showed very large increases in 

the dolerite and in the granite closely adjoining it (fig. 9). 

Since the dolerite has undoubtedly intruded from below, 

one has to conclude that the pathways which guided it up, 

or the pathways which it generated in the intrusion, are the 

pathways later used by the hydrocarbons. This relationship 

also confirms that contaminants introduced during drilling 

were not responsible for the observed hydrocarbons. 

In both holes large amounts of a magnetite/oil sludge 

were discovered. The magnetite was present as very small 

grains, mostly submicroscopic, and was highly concentrated in the sense that it formed more than 95 percent of the 

mineral content of the sludge. Twelve tons of this substance were pumped up from Gravberg 1 from a depth 

below 5.2 kilometers. It was suspected that the magnetite 

had been refined and concentrated by bacterial action, as 

has been seen in other oil-bearing regions at shallower 

levels (Sparks and others, I990). Sample collection of 

liquids that entered the Gravberg I wellbore below a 5.2~ 

kilometer depth was carried out by the Swedish State Bacteriological Laboratory in Stockholm, and several strains 

of previously unknown thermophilic and anaerobic microorganisms were cultured from these samples (U. Szewzyk, 

R. Szewzyk, and T-A. Stenstrom, Swedish National Bacteriological Laboratory, written commun., 1993). 

During the test procedure of the Stenberg I well, a gas 

cylinder was brought up containing free gas that wo~ld 

readily bum. Apart from nitrogen contamination (due to 

nitrogen used to expel the drilling water), the gas consisted principally of methane with approximately IO percent 

helium and 10 percent hydrogen. No continuous flow 

could be obtained, apparently due to the blocking effect of 

the entry of dense magnetite sludge into the wellbore. 

The oil brought up with this sludge was investigated 

in detail by the Danish Geological Survey and considered 

to be a biodegraded crude oil. Chromatograms of it 

matched closely those obtained from the oil pumped up in 

Gravberg I. 

The scientific investigations carried out on products of 

the two holes have thus demonstrated that hydrocarbons 

are present deep in granitic rock in the complete absence 

or lack of proximity of any sedimentary materials and in a 

distribution that leaves no reasonable doubt that they have 

come from deeper levels. The mix of the different hydrocarbon molecules, both of the gases and the oils, is quite 

typical, as it is found in other oil- and gas-producing regions. The quantities of oil and gas that appear to be 

present in this 44-km-diameter formation, tested in two 

distant locations, appear to be very large, as judged by the 

porosity measurements and the vertical intervals showing 

high concentrations. Production flow rates could not be 

achieved in either hole, apparently because in a confluent 

flow towards the wellbore, the sludge quickly concentrates 

and blocks the pores. The observed concentration of iron 

oxides in the rock is too low for the magnetite sludge to 

have been generated in the depth intervals in which it was 

found, and it must have been gathered and concentrated by 

a flow. We presume that this flow was that of the oil with 

which the magnetite is now associated. In that case, deeper levels than those that could be reached by the two boreholes (6.7 and 6.5 km) would tap into liquids and gases 

that contain smaller concentrations of magnetite, and 

would therefore cause less obstruction to a flow. 

CONCLUSIONS 

If the main supply of the commercial quantities of hydrocarbons, both gas and oil, is indeed derived from mantle depths and from materials that were incorporated in the 

Earth at its formation, then many points in petroleum geology and in other aspects of geology will have to be reconsidered. The quantity and locations of gas and oil that can 

be found, the method of prospecting for them, and the 

technology involved will all be affected. 

It was thought previously that gas could only be found 

where there was a particularly impermeable caprock, tight 

enough to hold gas, above sediments rich in biological debris. Now one would judge that gas can be found wherever a seepage of gas can be found at the surface, and where 

there is an adequate porosity at some depth below. If a 

low-permeability layer exists over a porous region, then 

this layer may have dammed up the flow sufficiently for 

production. But at deeper levels the critical layer will in 

any case provide a caprock. Thus in searching for gas, the 

requirement of a special caprock and the requirement of 

biological debris have both disappeared. The porosity requirement may be satisfied in many more locations than 

was previously thought, since beneath the critical layer the 

fluids coming from high pressures will frequently have 

created fracture porosity (as is clearly seen in Oklahoma). 

If hydrocarbons have been a major source of all the 

carbon supplied to the surface, then of course the quantities that would be involved are orders of magnitude larger 

than was previously estimated. The shallow zone above 

the shallowest critical layer, which is almost everywhere 

the only zone that has been the subject of oil and gas prospecting, will be seen to be the zone low in hydrocarbons, 

because they have largely escaped from these shallow levels. Oils, which became concentrated at shallow levels by 

the escape of the much more abundant gases, have been 

the chief object of the petroleum explorers. The deeper 
THE ORIGIN OF METHANE IN THE CRUST OF THE EARTH 79 

levels, which must be expected to have maintained the 

much more abundant gas, have not been explored at all 

outside of the United States, and in the United States the 

few areas that have been so explored have been found to 

be very productive. 

Drilling to below 5 or 6 kilometers is still expensive, 

and not much exploration to these levels will be done so 

long as the good prospects there are not recognized. But 

despite the expense of drilling, which would no doubt 

greatly decrease if more of it were d<me, the productivity 

from deep levels has frequently shown itself to be very 

high (Hefner, this volume). Gas at depth below the critical 

layer tends to have a pressure approaching the Iithostatic 

value, which may be on the order of 2,000 bar. The gas 

density is thus hundreds of times higher than it is in shallow wells, and may be as high as half the density of oils; 

therefore the content of gas in a given volume of pore 

spaces is hundreds of times greater than in shallow wells. 

The high pressure differentials into the wellbore mean that 

very high flow rates can be obtained, even from rock 

which at shallower levels would be regarded as of insufficient permeability for production. The ultimate production 

from a given well will be greater, because a greater pressure gradient wiii drive gas to the wellbore, and the expansion of the gas will allow a large proportion of the 

initial gas in place to be produced. It is therefore by no 

means true that gas production from the deep horizons 

must be expensive, and many examples exist already that 

show that production of deep gas can be quite competitive 

with production of shallow gas (Hefner, this volume; Cunningham and Rowe, this volume). The initial investment in 

an area will be higher, but so will be the returns. 

Because deep gas does not have many of the special 

requirements for its accumulation that oil has, one may 

expect it to be in many more locations than oil. Many 

countries in all parts of the world will benefit from a more 

widely distributed fuel source. 

Prospecting by the search for surface seepage of gas is 

a rational procedure, since large quantities of gas must 

constantly be escaping. Oil was found mainly by the attention that oil seeps drew to an area; instruments are needed 

to detect gas seeps but, with more gas than oil coming up 

and escaping more readily, gas seeps are good indicators 

of the presence of gas underneath. The quality of available 

prospecting methods is an item of m-ajor economic importance, especially for the deep horizons where exploratory 

drilling is expensive. 

A flow of hydrocarbon fluids through the crust will 

have affected much of the crust's chemical development. 

The concentration of many types of mineral deposits, especially of metal ores, has not had adequate explanations. The 

leaching out of particular components from the rocks requires fluids that can dissolve these components, and it requires large pressure differentials to drive these fluids 

through the pores of a sufficient quantity of rock to gain 

access to the components. Hydrocarbons ascending from 

depth may provide these requirements. The hydrocarbons 

will be present at a high temperature and pressure, conditions under which organometallic compounds can readily 

form. Such compounds are largely soluble in hydrocarbons, 

and may thus be transported upward by them. These metals 

may include some that have solubilities quite inadequate 

for transport by aqueous fluids, but that can form organometallic compounds. Silver, gold, and the platinum group 

are in that category, and many others may come under consideration for such processes. It is interesting to note that 

gold in particular has been found in many locations together with elemental carbon. Vanadium and nickel have shown 

a strong association with petroleum, both by the presence 

of vandium and nickel compounds in the petroleum, and 

the deposition of such compounds in or near oil fields. Several of the elements that would have a high vapor pressure 

at mantle temperatures have been found associated with 

hydrocarbons, not only helium but also mercury and all the 

halides. A range of new processes will have to be investigated for the understanding of mineralization in the crust, 

and the search for hydrocarbons may become associated 

with the search for certain minerals. The microorganisms in 

the ground that are fed by hydrocarbons may have contributed to highly selective processes; just as magnetite has 

been concentrated in the boreholes in Sweden, apparently 

by microbial action, so perhaps all the large magnetite deposits of Sweden have a similar origin. Judging from the 

quantities of microbial material that have been identified in 

hydrocarbon regions (Ourisson and others, 1984), microbial 

processing may have been of major importance in the evolution of the crust. 

REFERENCES CITED 

Anders, E., Hayatsu, R., and Studier, M.H., 1973, Organic compounds in meteorites: Science v. 182, p. 781-790. 

Beskrovny, N.S., and Tikhomirov, N.I., 1968, Bitumens in the 

hydrothermal deposits of Transbaykal, in The genesis of oil 

and gas: lzdvo Nedra. 

Chekaliuk, E.B., 1976, The thermal stability of hydrocarbon systems in geothermodynamic conditions: Degazatsiia Zemli i 

Geotektonika (P N. Kropotkin, ed.), p. 267-272. 

Clemett, S.J., Maechling, C.R., Zare, R.N., Swan, P.O., and 

Walker, R.M., 1993, Measurement of polycyclic aromatic 

hydrocarbon in interplanetary dust particles: Lunar Planetary 

Science, v. 24. 

Galimov, E.M., 1969, Isotopic composition of carbon in gases of 

the crust: International Geology Review, v. 11, no. 10, 

p. 1092-1104. 

Galimov, E.M., and Kvenvolden, K.A., 1983, Concentrations and 

carbon isotopic compositions of CH4 and C02 in gas from 

sediments of the Blake Outer Ridge, Deep Sea Drilling 

Project Leg 76: Initial Reports of the Deep Sea Drilling 

Project, v. 76, p. 403-407. 
80 THE FUTURE OF ENERGY GASES 

Gold, T., 1991, Sweden's Siljan Ring well evaluated: Oil and 

Gas Journal, Jan 14, 1991, p. 76-78. 

---1992, The deep, hot biosphere: Proceedings of the National Academy of Sciences USA, v. 89, p. 6045-6049. 

Gold, T., and Held, M., 1987, Helium-nitrogen-methane systematics in natural gases of Texas and Kansas: Journal of Petroleum Geology, v. 10, no. 4, p. 415-424. 

Gold, T., and Soter, S., 1984/85, Fluid ascent through the solid 

lithosphere and its relation to earthquakes: Pageoph, v. 122, 

p. 492-530. 

Hunt, J.M., 1975, Is there a geochemical depth limit for hydrocarbons?, in Thermal stability of hydrocarbons: Petroleum 

Engineering, March 1975, p. 112-127. 

Jannasch, H.G., 1983, Microbial processes at deep sea hydrothermal vents, in Rona, P.A., and others, eds., Hydrothermal processes at seafloor spreading centers: New York, Plenum Press. 

Jones, P.H., 1980, Role of geopressure in the hydrocarbon and 

water system, in Roberts, W.H., III, and Cordell, R.J., eds., 

Problems of petroleum migration: Tulsa, !Jkla., American 

Association of Petroleum Geologists, p. 207-216. 

Kent, P.E., and Warman, H.R., 1972, An environmental review of 

the world's richest oil-bearing region-The Middle East: International Geological Congress 24th, Sect. 5, p. 142-152. 

Kravtsov, A.I., 1975, Inorganic generation of oil and criteria for 

exploration for oil and gas: Zakonomern. Obraz. Razmeshchniya Prom. Mestorozhd. Nefti Gaza (G.N. Dolenko, ed.), 

p. 38-48. Naukova Dumka: Kiev. 

Kravtsov, A.I., Ivanov, V.A., Bobrov, V.A., and Kropotova, O.I., 

1981, Distribution of gas-oil-bitumen shows in the Yakutian 

diamond province: International Geology Review, v. 23, 

p. 1179-1182. 

Kravtsov, A.I., Voytov, G.I., Ivanov, V.A., and Kropotova, 0.1., 

1976, Gases and bitumens in rocks of the Udachnaya pipe: 

Akademiya Nauk SSSR Doklady, Earth Science Section, 

v. 228, p. 231-234. 

Kropotkin, P.N., 1985, Degassing of the Earth and the origin of 

hydrocarbons: International Geology Review, v. 23, p. 1261-

1275. 

Kropotkin, P.N., and Valyaev, B.M., 1976, Development of a theory of deep-seated (inorganic and mixed) origin of hydrocarbons: Goryuchie Iskopaemye: Problemy Geologii i 

Geokhirnii Naftidov i Biturninoznykh Porod (N.B. Vassoevich, ed.), p. 133-144. Akademiya Nauk SSSR. 

---1984, Tectonic control of Earth outgassing and the origin 

of hydrocarbons: Proceedings of the 27th International Geological Congress, v. 13, p. 395-412. VNU Science Press. 

Kudryavtsev, N.A., 1959, Geological proof of the deep origin of 

petroleum: Trudy Vsesoyuz. Neftyan. Nauch.-Issledovatel. 

Geologoraz Vedoch. Inst., no. 132, p. 242-262. 

Levin, B.J., 1958, Dber den Ursprung der Meteoriten: Chemie 

der Erde, v. 19, no. 3, p. 286-295. 

Lowe, D.C., Brenninkmeijer, C.A.M., Manning, M.R., Sparks, 

R., and Wallace, G., 1988, Radiocarbon determination of atmospheric methane at Baring Head, New Zealand: Nature, 

v. 332, p. 522-524. 

Makogan, Yu.F., 1988, Gas hydrate accumulations and permafrost development: Proceedings Fifth International Conference (K. Senneset, ed.), p. 95-101. 

Melton, C.E., and Giardini, A.A., 1974, The composition and 

significance of gas released from natural diamonds from Africa and Brazil: American Mineralogist, v. 59, p. 775-782. 

Mendeleev, D., 1877, L'origine du petrole: Revue Scientifique, 

2e Ser., v. 8, p. 409-416. 

Morrison, P., and Pine, J., 1955, Radiogenic origin of helium 

isotopes in rock: Annals of the New York Academy of Sciences, 62, p. 71-92. 

Nikonov, V.F., 1973, Formation of helium-bearing gases and 

trends in prospecting for them: International Geology Review: v. 15, no. 5, p. 534 and following. · 

Ourisson, G., Albrecht, P., and Rohmer, M., 1984, The microbial origin of fossil fuels: Scientific American, v. 251, no. 2, 

p. 44-51. 

Pearson, D.G., Davies, G.R., Nixon, P.H., and Milledge, H.J., 

1989, Graphitized diamonds from a peridotite massif in 

Morocco and implications for anomalous diamond occurrences: Nature, v. 338, p. 60-62. 

Pierce, A.P., Gott, G.B., and Mytton, J.W., 1964, Uranium and 

helium in the Panhandle gas field, Texas, and adjacent 

areas: U.S. Geological Survey Professional Paper 454-G, 

p. Gl-G57. 

Porfir' ev, V.B., 1974, Inorganic origin of petroleum: American 

Association of Petroleum Geologists Bulletin, v. 58, p. 3-

33. 

Roberts, A., 1980, Helium emanometry in exploring for hydrocarbons, part II, in Proceedings of Symposium II on unconventional methods in exploration for petroleum and natural 

gas: Institute for the Study of Earth and Man, Dallas, 

Southern Methodist University Press. 

Robinson, R., 1963, Duplex origin of petroleum: Nature, v. 199, 

p. 113-114. 

---1966, The origins of petroleum: Nature, v. 212, p. 1291-

295. 

Schidlowski, M., Eichmann, R., and Junge, C.E., 1975, Precambrian sedimentary carbonates-Carbon and oxygen isotope 

geochemistry and implications for the terrestrial oxygen 

budget: Precambrian Research, v. 2, p. 1-69. 

Sokoloff, W., 1889, Kosmischer Ursprung der Bitumina: Bulletin de Ia Societe Imperiale de Naturalistes de Moscou, n.s., 

v. 3, p. 720-739. 

Sparks, H.N.C., Mann, S., Bazylinski, D.A., Lovley, D.R., Jannasch, H.W., and Frankel, R.B., 1990, Structure and morphology of magnetite anaerobically produced by a marine 

magnetotactic bacterium and a dissimilatory iron-reducing 

bacterium: Earth and Planetary Science Letters, v. 98 p. 14-

22. 

Sylvester-Bradley, P.C., 1964, The origin of oil and life: Discovery, v. 25, p. 37-42. 

---1972, The geology of juvenile carbon: Exobiology (C. 

Ponnamperuma, ed.), p. 62-94. 

Tarr, Arthur C., 1974, World seismicity map-Lat 70°S to 

84°N, long 105°E to 65°W: U.S. Geological Survey special 

map, scale 1:39,000,000. 

Vernadsky, V.I., 1933, The history of minerals of the Earth's 

crust, Vol. 2, Pt. I [in Russian]: Moscow-Leningrad. 

Yanyanos, A.A., 1986, Evolutional and ecological implications 

of the properties of deep-sea barophilic bacteria: Proceedings of the National Academy of Sciences USA, v. 83, 

p. 9542-9546. 

Further reading: Gold, T., 1987, Power from the Earth: Deep 

Earth Gas-Energy for the future: London, J .M. Dent and 

Sons, 201 p. [U.S. distributor: The Bookery, 215 N. Cayuga Street, Ithaca, NY 14850] 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Energy Gases of Abiogenic Origin in the Earth's Crust 

By John A. Apps 1 and Peter C. van de Kamp2 

CONTENTS 

Abstract ..... .. . .. .. .... . ...... . ... .. . .... ..... . . .. .. .. .. .... .. ... .. .... .. ... ... . 81 

Introduction . . .. . ... ... . . .. ... ... ... ....... .... .. .. .. ..... . .. ... ..... . ... ... . . . 82 

Volatiles in the Earth's Interior .................................... 83 

The Origin of the Earth and the Fate of Hydrogen 

and Carbon . ... .. .. ..... ... ..... ... ... ... ... .. . . .... . . ... .. .... .. ... .. . . 83 

Structure of the Earth and Its Bearing on 

Reservoirs of Volatiles ........................................... 85 

Mantle Oxidation State .......................................... 87 

Phase Equilibria Affecting Volatiles and 

Vapor-Phase Transport in the Mantle .................... 88 

Transport of Volatiles from the Mantle by Magmas .. .. 90 

Transport of Volatiles in the Crust ............................... 92 

Isotopic Methods for the Detection of Gases of 

Mantle Origin .. .. ... ... .. ... . .... .. .... . . .... . . .. . ..... .. .. .. ... ... . . . 92 

Thermodynamic Stability of C-H-0-N-S Gases 

in the Crust ............................................................. 92 

Magma Transport ......... .... . .................. ..... . .. .. .. ..... .. 93 

Magma Oxidation State .................................. 93 

Field Evidence ............................ .... ................. 95 

Continental Lithosphere ............................ 95 

Subduction Zones ...................................... 99 

Mid ocean Ridges and Ocean Islands .. .... .. 100 

Vapor-Phase Transport ........................................... 100 

Oxidation State of the Lower Crust .. ...... ...... .. I 00 

Vapor-Phase Transport from Basement Rocks 

into Sedimentary Basins ................................. 100 

Abiogenic Hydrogen and Methane Formation in the 

Crust .............................................................................. 103 

1

Lawrence Berkeley Laboratory, Earth Sciences Division, I Cyclotron Road, Berkeley, CA 94720. 2Cornelis Corporation, 1750 Cabernet Lane, St. Helena, CA 94574. 

Abiogenic Hydrogen and Methane Formation in the 

Crust-Continued 

Hydrogen Generation ............................................. 1 03 

Water Radiolysis .............................................. 103 

Cataclasis ... .. . .... ... ..... ... .. . .... .. . .. . .. ... . . . ... . . . ... . .. .. . 104 

Hydrolysis by Ferrous Minerals ...................... 105 

Relationship of Methane to Hydrogen ................... 105 

Field Evidence for Hydroloysis by Ferrous 

Minerals .................................................................. 106 

Closed Systems ................................................ 106 

Autogenous Generation of Methane During 

the Cooling of Agpaitic Magmas .... .. .. .... .. ... 106 

Cooling of Layered Mafic Intrusions ........ I 08 

Deuteric Reactions in Igneous and 

Metamorphic Rocks ............ .... ...... .... ...... ... 109 

Open Systems .................................................. 110 

Oceanic Spreading Centers ........................ 110 

Subducting Plate Margins .......................... Ill 

Mafic and Ultramafic Igneous Rocks 

in the Continental Crust ............................. 115 

Economic Significance of Abiogenic Gases in the 

Earth's Crust .................................................................. 120 

Conclusions ................................................................... 122 

Acknowledgments ......................................................... 122 

References Cited ........................................................... 123 

ABSTRACT 

Overwhelming evidence supports the belief that the 

world's natural-gas resources come from the decomposition of organic matter in sedimentary rock formations. Yet 

alternative arguments supporting an abiogenic origin have 

been advanced for more than 100 years. In recent years 

these arguments have centered on the concept that large 

81 
82 THE FUTURE OF ENERGY GASES 

quantities of primordial methane were trapped in the Earth 

during planetary accretion and that this gas is migrating 

into the Earth's crust and accumulating in reservoirs in 

sedimentary rock. The economic implications of these arguments could be profound and merit a thorough review 

of all evidence that might clarify this issue. 

In this paper, we explore the likelihood that methane 

might be migrating from the Earth's interior. We show that 

the Earth's upper mantle is too highly oxidized to support 

the presence of other than minor concentrations of methane or hydrogen. Gases from the mantle are transported to 

the Earth's surface mainly dissolved in magmas. Gases released from these magmas are composed of C02 (+CO), 

H20, and S02 or H2S. The concentrations of methane in 

these gases are insignificant, and they could not be the 

source of commercial gas fields. Although gases including 

methane could migrate advectively from the mantle by 

flow through intergranular pores, there is no evidence that 

methane is transported this way. Gases migrating out of 

basement rocks into sedimentary basins containing natural-gas reservoirs are primarily of crustal origin and contain no detectable methane. 

Abiogenic hydrogen and methane are generated in the 

Earth's crust through hydrolysis by ultramafic and mafic 

rocks at temperatures below 500°C. The quantities of gas 

that could form from bodies of such rocks can be of the 

same order of magnitude as those of typical gas fields. 

Commercial reservoirs of abiogenic energy gases have, 

however, never been found. It appears that most sites where 

hydrogen and methane can be generated abiogenically are 

also those where no structural traps are present, where 

water access is limited, or where the presence of other substances such as sulfate inhibit hydrolysis. We therefore conclude that resources of abiogenic energy gases in the 

Earth's crust are probably small and of little or no commercial interest. Exploration strategies for such resources 

should be critically evaluated in the light of currently available evidence to assess the potential risks involved. 

INTRODUCTION 

Modem research in petroleum geology and geochemistry indicates that most hydrocarbons were derived from 

parent organic matter originally formed at the Earth's surface. Upon burial in enclosing sediments, organic matter is 

diagenetically transformed into kerogen, a precursor of petroleum. At depth, when heated to temperatures in excess 

of 50°C for a sufficient time, hydrogen-rich kerogen is 

transformed into oil and gas plus carbon-rich solid residue. 

This transformation has been conclusively demonstrated 

(Tissot and Welte, 1978). Furthermore, organic-rich rocks 

(source rocks) and oil and gas accumulations have been 

correlated in numerous sedimentary basins. The fluids are 

called "thermogenic" when derived from kerogen by heating or pyrolysis, and "biogenic" when derived at surface 

and near-surface conditions by microbial processes. 

Hydrocarbons produced by combining carbon and hydrogen not derived from natural organic matter are termed 

"abiogenic." Abiogenic hydrocarbons have been made in 

the laboratory (Chang and others, 1983) to determine how 

basic organic compounds were developed in the early history of the Earth prior to the appearance of living organisms. Similar, naturally occurring abiogenic syntheses 

suggest the potential of organic source materials for petroleum. In this paper, we provide evidence for sources of 

naturally occurring abiogenic hydrogen and hydrocarbons 

in the Earth as potential energy sources. 

In recent years, several scientists (for example, Gold 

1978, 1979a,b, 1980, 1987, this volume; Gold and Soter, 

1980; Giardini and Melton, 1981 ; Giardini and others, 

1982) have advanced the view that carbon trapped deep in 

the Earth during planetary accretion and differentiation 

some 4.5xl09 years ago is the principal source of many of 

the world's oil and gas deposits. Gold maintains that methane (or hydrogen) should be chemically stable in the upper 

mantle and that it is migrating into the crust. Many phenomena have been cited (Gold, 1979a, 1987, this volume; 

Gold and Soter, 1980) in support of this position. These 

phenomena include kimberlitic diatreme formation, phenomena associated with seismic activity and surface manifestations of faulting, mud volcanoes, vitroclastic volcanic 

eruptions, evidence of mantle helium, and the distribution 

of oil and gas fields in relation to plate margins and fold 

belts. Gold (1987) also presented arguments supporting alternative interpretations for the origin of oil and gas fields. 

These interpretations, which are offered in support of an 

abiogenic origin of petroleum and gas deposits, have been 

fiercely challenged by the scientific community over the 

past decade. The general consensus is that the weight of 

evidence overwhelmingly favors an organic origin for the 

world's petroleum and gas deposits (Marland, 1984). 

The release of gases from the mantle over geologic time 

is a complex issue. It involves questions regarding planetary 

accretion, the nature of material originally incorporated in 

the Earth, and processes leading to the segregation of the 

Earth's core. The outer shell of the Earth was possibly molten during the latter stages of accretion, and may have governed the evolution and composition of the primitive 

atmosphere. Evidence also points to a mantle and core that 

are continuously convecting and releasing heat due to radioactive decay and gravity segregation. The convection induces the formation of magma in the upper mantle, which rises 

buoyantly and often invades the Earth's crust. The continuous process of magmatic differentiation depletes the upper 

mantle and enriches the crust with lithophilic elements. Volatiles, dissolved in magmas, have also been flushed continuously from the Earth's interior throughout geologic time, 

but it is not certain what quantity of these volatiles may also 

have escaped by intergranular transport. 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 83 

Mantle convection is also responsible for the continuous shifting of lithospheric plates and both construction 

and destruction of oceanic crust. Cold oceanic crust traps 

volatiles and organic material, which are subducted into 

the mantle and recycled. These phenomena are incompletely understood and poorly quantified. As yet, there are 

only tentative answers to such questions as the following: 

1. How much carbon and hydrogen were incorporated 

in the Earth at the time of its formation? 

2. What was the oxidation state of the primitive atmosphere, and to what extent did it influence the oxidation 

state of the upper mantle? 

3. How extensive was melting of the Earth's outer 

shell? 

4. At what rate is the upper mantle being oxidized due 

to recycling of the oceanic crust? 

5. What is the impact of recycled water and organic 

material on the volatile content and oxidation state of the 

upper mantle? 

6. What is the oxidation state of the lower mantle? 

7. What are the volatile fluxes between upper and 

lower mantle? 

8. Is magma flow or advective flow of vapor the principal mechanism for conveying hydrogen and carbon from 

the mantle to the Earth's crust? 

9. To what extent does an oxidized upper mantle act 

as a barrier to reducing gases migrating upward from the 

lower mantle? 

In this paper, we review what is known or inferred 

about the~ volatile content of the Earth's mantle and core, 

how degassing occurs, and what controls the composition of 

the gases. The magnitude and significance of energy-gas 

(that is, hydrogen and hydrocarbon) accumulation in the 

crust due to mantle processes is reviewed. We then focus on 

processes that lead to the formation of abiogenic hydrogen 

and methane in the Earth's crust, and the potential for these 

gases to accumulate as commercial resources. 

The paper is subdivided into four principal sections. In 

the first we consider the content and composition of volatiles in the Earth's interior. In the second we consider mechanisms by which the volatiles are transported to the Earth's 

crust. In the third we examine the fate of mantle volatiles in 

the Earth's crust, and in the fourth we discuss mechanisms 

by which energy gases form abiogenically under crustal 

conditions. In particular, in the fourth section we review 

processes through which mafic and ultramafic igneous rocks 

from the mantle hydrolyze and produce methane and hydrogen. A fifth section addresses the economic significance of 

abiogenic gases in the Earth's crust. 

VOLATILES IN THE EARTH'S INTERIOR 

One of the central arguments for an abiogenic origin for 

oil and gas deposits is that primordial methane was trapped 

in the Earth's interior during planetary accretion and that this 

methane is migrating into the crust. In order to establish the 

plausibility of this argument, we need to examine what is 

known about the behavior of hydrogen and carbon during the 

formation of the Earth. In this section we discuss various 

aspects concerning the fate of these elements and how they 

were distributed early in the history of the Earth. 

THE ORIGIN OF THE EARTH AND THE FATE OF 

HYDROGEN AND CARBON 

The concentrations of hydrogen and carbon within the 

Earth's mantle and core are not precisely known. While it 

is possible to estimate the concentrations of hydrogen and 

carbon in crustal material, this material represents only a 

tiny fraction (<1 percent) of the Earth's total mass. Zeroann and others (1969) presented carbon analyses of tholeiites and peridotites containing an average of 474 and 373 

parts per million (ppm) of carbon respectively. If the 

tholeiites resulted from 20 percent partial fusion, the average carbon content of the mantle rock precursor would be 

393 ppm. Vinogradov (1962) proposed a lower carbon 

content, IOO ppm, for both ultramafic and mafic rocks, but 

this value could still be within the range of present uncertainties for the upper mantle as a whole. Holland (1978) 

estimated that the concentration of hydrogen in the whole 

Earth is 25 ppm, the concentration of carbon is 30 ppm 

(excluding that in the mantle), and the concentration of 

nitrogen is 2 ppm. Tajika and Matsui (1992) gave estimates of the carbon and water contents of the Earth and 

estimated the carbon abundance in the mantle as I56 ppm. 

Assuming a homogeneous mantle, this value is equivalent 

to a total of 5.2xi022 moles (mol) and compares with a 

crustal and atmospheric carbon content of I xI 022 mol. 

The amount of water ·at the Earth's surface is 7.8xi022 

mol, and the water content of the mantle is O.I ppm or 

2.4x 1023 mol. Five times as much carbon remains in the 

mantle as in the Earth's crust, whereas only three times as 

much water remains in the mantle. 

The concentrations of carbon and hydrogen in the 

Earth are generally less than the primordial abundances of 

these elements in the Solar System, which are estimated 

from chemical analyses of meteorites entering the Earth's 

atmosphere and from the composition of the Sun's atmosphere. Carbon and hydrogen and their compounds are 

much more volatile than the elements that make up the 

bulk of the Earth. They were therefore lost from the material composing the Earth either prior to, during, or subsequent to the Earth's formation. 

Although many details concerning the origin of the 

Earth are still being debated, a consensus has been reached 

regarding the general mode of formation (Ringwood, 1979; 

Holland, I984). Initially, about 4.6xi09 years ago, the Sun 

was surrounded by a disc-shaped nebula of condensed 
84 THE FUTURE OF ENERGY GASES 

interstellar dust, the integrated residue of stellar nucleosynthesis. The average composition of the primordial solar 

nebula is believed to have been similar to that of carbonaceous chondrites, a class of stony meteorite. With the exception of volatile elements such as nitrogen, carbon, and 

hydrogen, which are depleted, the composition of these meteorites correlates closely with that of the solar photosphere, (Ross and Aller, 1976). Solar radiation may have 

heated the inner region of the solar nebula sufficiently to 

sublime the volatile constituents, which condensed in its 

outer regions. The composition of the solar nebula was 

therefore probably zoned with only the least volatile components present within the innermost regions, and increasingly volatile compounds condensed sequentially with 

increasing distance from the sun. 

Through a process of aggregation and collision, the dust 

grew into fewer but larger particles. Some of the particles 

eventually attained diameters of several hundred kilometers 

and acquired their own gravitational fields. These so-called 

planetesimals were then able to capture smaller particles 

through gravitational attraction and grow at a comparatively 

more rapid rate until the solar nebula had been reduced 

essentially to the few large planetary bodies composing the 

present Solar System. This process is inferred to have taken 

about 108 years. Accretion was probably erratic as some of 

the collisions involved breakup of colliding planetesimals. 

The temperature at which accretion occurred is not known, 

although initially it appears to have been low. Decaying 

short-term radionuclides such as 26 AI may, however, have 

heated planetesimals to such an extent that transient melting 

and metallic core formation was possible, even in bodies 

only 250 km in diameter (Goldstein, 1964). 

With increasing size of a planetary body, the energy 

released by impacting material increased dramatically. Recent modeling of the accretion process for the Earth suggests 

that energy dissipation was so great that extensive melting 

of the surface occurred. Calculations by Matsui and Abe 

(1986a) indicate that surface melting first occurred when 

the radius of the Earth was only 0.4 times its final value. 

With continuing accretion, however, the melting temperature 

of the predominantly magnesium-iron silicates composing 

the infalling material also increased because of increasing 

pressure. The magma oc~an therefore solidified continuously 

as accretion proceeded. The maximum thickness of the 

magma ocean is not known with any certainty, but it probably 

never exceeded 500 km. Continuous melting of the surface 

layer would have aided in the segregation of metallic iron 

to form the core. 

Several arguments support the hypothesis that segregation of the Earth's core took place within 5x108 years 

after accretion and that the gravitational energy released 

by core formation led to intense convection and mixing. 

Both the upper and lower mantle are therefore believed to 

have a relatively uniform composition. 

With the exception of the refractory oxides of Mg, AI, 

Ca, Si, and Fe metal, all major elements are strongly depleted in the Earth's mantle, the depletions clearly related 

to the elements' volatilities. Ringwood (1979) concluded 

that the Earth formed by accretion of depleted chondritic 

material and that only 10 to 15 percent of the accreted 

material could have originated from carbonaceous chondrites. Using both petrologic and cosmogenic arguments, 

he estimated the composition of the Earth's mantle, which 

he referred to as "pyrolite." Pyrolite consists primarily of 

Si02 (45 weight percent), MgO (38 weight percent), FeO 

(8.0 weight percent), Al20 3 (3.3 weight percent), and CaO 

(3.1 weight percent). 

The material accreting during much of the growth of 

the Earth melted and released volatile components to the 

newly forming atmosphere. Earlier estimates of the mass of 

the Earth's protoatmosphere, which were based on the contents of volatiles in the solar photosphere or in carbonaceous chondrites, neglected volatile loss from the inner 

nebula, the substantial fusion of the outer layer of the Earth, 

and the dissolution of volatiles in the magma ocean. This 

omission led to the conclusion that the Earth's early atmosphere was enormously larger than at present, and various 

mechanisms were invoked to explain how the bulk of this 

early atmosphere was blown away, perhaps during T-Tauri 

stage of the Sun's evolution. Fanale (1971) argued that the 

present constitution of nonradiogenic rare gases, with the 

exception of xenon, corresponds very closely with that in 

normal chondrites. He suggested that catastrophic degassing of almost all the rare gases had not occurred early in 

the Earth's history and that these gases, with the exception 

of helium, which continuously escapes from the Earth's 

gravitational field, have remained in the Earth's atmosphere 

until this day. Regarding volatiles such as C02 and H20, he 

argued that the bulk of these had dissolved in the substantially molten Earth and have remained there to the present. 

While some details of Fanale's hypothesis must be rejected 

in light of subsequent discoveries, the conclusion that the 

protoatmosphere was not lost to space and that much of the 

carbon and hydrogen (as water) remained in the mantle 

appears valid. 

We refer to C02 and H20 as being the principal atmospheric components in the primitive atmosphere because it 

is assumed that the atmosphere was initially relatively oxidizing. The temperature range in the primitive atmosphere 

is not known, but the Fischer-Tropsch reaction, 

(1) 

is displaced strongly to the right at around 1,200°C, the 

temperature of the magma ocean. Methane would react 

with water to produce carbon dioxide and hydrogen, the 

latter escaping into space. Any hydrocarbons introduced 

by carbonaceous chondrites would have been consumed. 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 85 

Ringwood (1979) claims that meteoritic iron would also 

tend to oxidize during ablation in the primitive atmosphere 

and generate hydrogen gas. Abe and Matsui (1985) do not 

believe this process to have been important. 

The distribution of sulfur species in the primitive atmosphere has not been investigated. The reactions 

(2) 

(3) 

(4) 

could have played an important role in buffering the oxidation state of the primitive atmosphere, but more study is 

needed of the dynamics of the primitive atmosphere and 

saturation of the magma ocean before the role of sulfur is 

understood. 

The mechanism of hydrogen generation and escape 

from the Earth's atmosphere, which may have been operative for about I x 108 years must have progressively oxidized the magma ocean even though it was buffered by 

iron-containing minerals and carbon and its gaseous oxides. How much hydrogen was lost by gravitational escape 

during this period may never be known, but it is worth 

noting that much of the upper mantle is now too highly 

oxidized to support the presence of species more reduced 

than C02 and H20. 

Various estimates have been made 'of the vapor pressures of H20 and C02 of the primitive atmosphere in assumed equilibrium with the magma ocean. Holland (1984) 

calculated that PH2

o in the primitive atmosphere was 

about 0.05 megapascals (MPa), assuming that all water 

now present in the crust and oceans was originally incorporated in the Earth during accretion. The low partial pressure is a consequence of the high solubility of water in 

silicate melts, which can incorporate as much as lO to 40 

mole percent water before attaining saturation (Spera, 

1974 ). In contrast, the water vapor pressure was assumed 

by Matsui and Abe (1986a, b) to be approximately 

lOMPa. 

Holland (1984) calculated that a substantial pressure 

of C02 would build up in the primitive atmosphere until 

the concentration of carbon as C02 in the melt was approximately equal to the concentration of carbon in the infalling material. Holland estimated that about one-third of 

the carbon dioxide in the accreting material accumulated 

in the atmosphere, the remainder dissolving in the magma 

ocean. The C02 pressure was believed to be in the range 

from 2 MPa (Holland, 1984; Kasting and Ackerman, 

1986) to as high as 10 MPa (Sato, 1991). According to 

Kasting and Ackerman ( 1986), carbon dioxide at a partial 

pressure of approximately 6 MPa is currently bound up in 

carbonate rocks. 

The solubility of C02 in magma is far lower than that 

of water. Hence, it would be expected that a far larger 

concentration of water than carbon dioxide was dissolved 

in the magma ocean. Upon solidification, much of the 

C02 and H20 was expelled, although some of the carbon 

was undoubtedly reduced and remained as graphite or 

diamond. 

Tajika and Matsui (1992) designed a model to study 

thermal behavior of the Earth and the evolution of the 

C02 protoatmosphere. Their model indicated that most 

C02 degassed early in the Earth's history, and the crustal 

and atmospheric inventory has remained relatively constant for the last 3.5x109 years. The case for water is similar although the initial degassing was much less. For most 

of geological time, the amount of water and C02 entering 

the mantle at subducting plate margins has been roughly 

equivalent to that being released through volcanic action. 

STRUCTURE OF THE EARTH AND ITS BEARING 

ON RESERVOIRS OF VOLATILES 

Direct observations of the subcrustal interior of the 

Earth are not possible, so our understanding of its structure must be deduced by reconciling observations drawn 

from nucleosynthesis, seismology, and meteoritics, and 

fundamental knowledge concerning the density of the 

Earth and its angular momentum. This information is supplemented by high-temperature and high-pressure studies 

of simplified chemical systems simulating subcrustal 

chemistry, and the study of xenoliths that were transported 

from the upper mantle to the surface in mafic magmas. 

These rocks often show evidence of deformation, annealing, and secondary alteration. 

The Earth's interior is composed of a series of layers 

(fig. 1) that subdivide the Earth into the upper and lower 

mantle and outer and inner core. The boundaries between 

the principal layers are interpreted as sharp changes in material density due to phase or compositional changes. The 

discontinuity at 2,900 km is assumed to be due to the segregation of a metallic nickel-iron core, the inner part of 

which is solid and the outer part liquid. This is surrounded 

by a mantle consisting principally of MgO, Si02, and 

FeO, the pyrolite of Ringwood (1975, 1979). 

The subdivision of upper and lower mantle at 680 km 

depth is attributed to a major phase transition in which the 

j3(Mg,FehSi04 phase breaks down to form magnesium 

perovskite (MgSi03) and magnesiowustite, ((Mg,Fe)O) 

(Ringwood, 1979; Jeanloz and Knittle, 1989). At 400 km 

depth in the upper mantle, a somewhat smaller transition 

occurs, and this is attributed to the transformation of olivine, (Mg,Fe)Si04, into the 13 form. 

There is abundant evidence that subsequent chemical 

partitioning and fractionation processes during convection 
86 THE FUTURE OF ENERGY GASES 

Crust (50-90 km) 

Mohorovicic discontinuity 

~_J~~-~~~~~:~~:~~~~~~;;~J Incipient fusion Low-velocity z~e ___ Uppyt.llla.Dtle:: _ _ _ . ol + opx + clpx + pyrope 

(50-150 km) - :; - - - - - - - :: - .:tl-----pyroxene- garnet 

400-km ...... - - - - - - - - - - - ol--+~ phase discontinuity '----~ phase-spinel phase(?) 

680-km CaFe garnet phase--+ pcrovskite phase 

discontinuity spinel phase-+perovskite phase 

+ magncsiowustite Lower mantle 

'----Mg garnet-+ilmenite 

+-+-- perovskite + magncsiowustite 

Figure 1. Internal structure of the Earth. clpx, clinopyroxene; ol, olivine; opx, orthopyroxene. Modified from Ringwood (1979). 

have resulted in a mantle with extensive inhomogeneities. 

Thus, the boundary between the upper and lower mantle, 

attributed to the magnesium perovskite phase transition, 

may also be stabilized by compositional differences, as has 

recently been concluded by Jeanloz and Knittle (1989). Implicit in this conclusion is the postulate that the mantle is 

now segregated into two independently convecting systems 

within the upper and lower mantle, respectively (Christensen, 1989). Only restricted mass interchange occurs across 

the interface. Geochemical evidence (Hofmann, 1989) also 

implies that there exist today at least two chemical reservoirs, both of which are depleted in certain elements with 

respect to primordial material. Rare-gas isotopic analyses 

show quite clearly that a reservoir (or reservoirs) exists 

deep within the Earth, possibly in the lower mantle, which 

still retains rare gases that have been present since the first 

I 00 million years after formation of the planetary nebula. 

The role of mantle convection and plate tectonics need 

not be discussed further, as many standard texts adequately cover the subject. One aspect is of interest, however, as 

it might be influential in modifying the oxidation state, 

and hence the volatile components, in the lower mantle. 

Subducting oceanic crust melts, leaving a dense residue, eclogite, which falls by gravity to the 680 km phase/ 

composition boundary, (Ringwood, 1975, 1979). Whether 

eclogite penetrates this boundary is open to question. Ringwood (1975) and Christensen (1989) believe that it does 

and that it descends to the lower mantle/core interface 

where it accumulates as "dregs" in the so called D layer. 

Eclogite, if it accumulates within the D layer of the 

lower mantle, could have a significant impact on the lower 

mantle's oxidation state. Conductivity and oxygen-fugacity 

experiments (Peyronneau and Poirier, 1989; Wood and 

Nell, 1991) suggest that the magnesiowustite of the lower 

mantle is partially oxidized and therefore cannot be in 

equilibrium with the iron in the core (McCammon, 1993). 

Yet, the core itself may also be partially oxidized. Because 

the Earth's core is less dense than it would be if it consisted of iron and nickel alone, Ringwood (1979) concluded 

that the core must be diluted with FeO. 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 87 

MANTLE OXIDATION STATE 

The oxidation state of the mantle is a critical parameter in defining the composition of any vapor phase that 

might be present. Therefore, in this section we discuss 

vapor components and idealized solid-phase buffers under 

upper-mantle conditions in relation to measurements that 

were made to estimate the mantle oxidation state. 

In figure 2, phase relations of relevant solid and gaseous species are plotted as a function of RTin fo 2 (where 

R is the universal gas constant, T is temperature, and fo 2 

is natural log of oxygen fugacity) between 600 and 

I ,400°C along an average geothermal gradient, with appropriate corrections for pressure. This representation, 

originally used by Marakushev (1981) and here contoured 

for log ! 0 2, displays phase relations more conveniently 

than if log f 02 were to be used as the vertical axis over 

the depicted temperature range. 

Potential redox buffers represented by the following 

mineral assemblages-iron-magnetite (IM), iron-wustite 

(IW), wustite-magnetite (WM), hematite-magnetite (HM), 

carbon (graphite)-carbon dioxide + carbon monoxide 

(CCO), iron + quartz-fayalite (IQF), fayalite + quartz-magnetite (QFM) and pyrrhotite-pyrite + magnetite (PPM)-are 

also included. Other buffers in the figure are represented by 

the assemblages gniphite-enstatite-dolomite-olivine-diopside (GEDOD; reaction 5) and enstatite-magnesite-olivinegraphite (EMOG; reaction 6) (Biundy and others, 1991 ): 

Mg2Si04+0.5CaMgSi206+C+02(gas)= 

olivine diopside graphite 

Mg2Si20 6+0.5CaMg(C03h (5) 

enstatite dolomite 

olivine graphite enstatite magnesite 

Temperature, in degrees Celsius 

Figure 2. Gas-gas and gas-solid-phase equilibria as function of RTln fo 2 (where R is 

universal gas constant, T is temperature, and In f 02 is natural log of oxygen fugacity) 

and temperature on hypothetical 25°C km- 1 geotherm. Shaded areas show measured 

redox equilibria beneath oceanic crust (OC) and continental crust (CC). EMOG, enstatite-magnesite-olivine-graphite; GEDOD, graphite-enstatite-dolomite-olivine-diopside; 

HM, hematite-magnetite; IQF, iron + quartz-fayalite; IW, iron-wustite; PPM, pyrrhotitepyrite + magnetite; QFM, fayalite + quartz-magnetite; WM, wustite-magnetite. Light 

lines from upper left to lower right are lines of equal log f 02, in bars. 
88 THE FUTURE OF ENERGY GASES 

Vapor-phase reactions include those involving hydrogen, 

steam, methane, carbon dioxide, and carbon monoxide. 

Calculations were carried out using the thermodynamic data of the SUPCRT92 code developed by Helgeson 

and his coworkers (Johnson and others, 1992). However, 

we used the 1987 version of the code, which incorporates 

a corresponding state version of the Redlich-Kong equation of state, formulated by Edmister (1968), with improvements by Holloway (1977) and Flowers ( 1979). The 

critical temperatures and pressures for the vapor phases 

were obtained from Mathews ( 1972). 

The curves delineating the reactions between nonoxygen gases and between nonoxygen gases and solids do not 

represent the stability limits of those gases, but merely indicate where the product of the activities of all reactants 

and products (except oxygen) are equal to unity. Therefore, gaseous species in a vapor phase extend over a wider 

range of stability than is indicated by the univariant reaction curves. The reaction curves do, however, generally 

delineate the regions where particular gases predominate. 

Blundy and others (1991) have shown that the most 

reliable estimates of upper-mantle oxygen fugacities (fo2

) 

fall on distinct trends along the geotherms of continental 

and oceanic crust. The regions covered by such estimates 

are shaded in figure 2. The oxygen fugacities associated 

with the continental geotherm are somewhat Jess oxidizing 

than those associated with the oceanic geotherm. The 

former straddle the QFM buffer and the GEDOD and 

EMOD buffers. In contrast, oxygen fugacity data along the 

oceanic geotherm are less well defined and extend to the 

wustite-magnetite (WM) buffer, an environment in which 

f 02 is two to three orders of magnitude lower than that 

underlying the continental crust. 

Sato (1978a, b; 1991) concluded that the oxidation 

state of the upper mantle is generally controlled by reactions involving carbon (as graphite or diamond) and coexisting oxides of carbon, or ceo buffer: 

(7) 

(8) 

or by solid carbonates, as described above. This conclusion may be valid beneath continental crust, but it is not 

clear whether the upper mantle beneath oceanic crust is 

buffered by carbon and its oxides or by Fell and Fem. 

Conditions may have been more reducing where diamond has formed in the upper mantle beneath the continental crust (that is, to at least 400 km depth), because 

native iron and djerfisherite, a complex iron-potassium 

sulfide, have been observed as inclusions in diamond 

(Marakushev, 1981 ). These inclusions suggest an oxidation state close to that of the iron-wustite (IW) buffer. 

Sato's calculations (Sato, 1978b) show the oxygen fugacity of the IW buffer to be about 2 log units less than that 

of the CCO buffer at 10 gigapascals (GPa). Moissanite 

(SiC) has also been found in diamondiferous pipes and as 

inclusions in diamond, but its mode of formation is obscure (Leung and others, 1990). Calculations indicate that 

moissanite's formation in the upper mantle is thermodynamically implausible. 

If the residues of subducted oceanic crust founder and 

accumulate in the lower mantle, mass transfer must occur 

in the opposite direction. Several investigators, notably 

Taylor and Green (1987), Green and others ( 1987), and 

Haggerty (1986, 1987) believe that the lower mantle is 

substantially more reducing and that an upwelling volatile 

flux from the lower mantle contains methane and smaller 

quantities of hydrogen. In figure 2 it can be seen that in 

most of the upper mantle, any vapor phase associated with 

mineral assemblages or melts from which the fo2 estimates cited by Blundy and others (1991) were derived 

would have consisted dominantly of C02, H20, and N2, 

with only trace quantities of reducing gases, such as CH4, 

CO, and H2. Sulfur species should be present primarily as 

H2S along the oceanic crustal geotherm, but could be either S02 or H2S on the continental crustal geotherm, depending on the quantity of water present (Ohmoto and 

Rye, 1979). These findings are corroborated by field studies, analyses of volcanic gases, experimental studies under 

mantle conditions, and examination of fluid inclusions. 

PHASE EQUILIBRIA AFFECTING 

VOLATILES AND VAPOR-PHASE TRANSPORT 

IN THE MANTLE 

The presence of certain minerals in xenoliths-such as 

carbonates, amphiboles, micas, graphite, and diamondaids in defining the oxidation state of the upper mantle. 

The distribution of these minerals suggests that reduced 

species (methane, hydrogen, and ammonia) are expected 

to be present only in minor concentrations in the upper 

mantle. The upper mantle is not homogeneous, however, 

and because of convective transport from the lower mantle, regions exist in which the oxidation state could be 

much lower and methane could be the predominant species (Taylor and Green, 1989; Green and others, 1990; 

Taylor, 1990; Saxena and Fei, 1988; Saxena, 1989). Our 

findings are summarized in figure 3. 

Carbonates are infrequently found as inclusions in 

mantle xenoliths, (for example, see Sobolev and Stankovskiy, 1979; McGetchin and Besancon, 1983), because 

they are unstable and tend to decompose in basaltic magmas during transit to the surface. The solubility of carbon 

dioxide in tholeiitic magmas, even in the mantle source 

regions, is very low, ranging from 1.5 weight percent at 3 

GPa to much less than 0.05 weight percent at the surface 

(Spera and Bergman, 1980). Carbon dioxide is commonly 

found as liquid C02 inclusions in olivines in mantle xeno-
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 

lf 02 =0.02 MPal o~C~O~N~TI~N~E~N~TA~L~------------------~~--------~0 

CRUST 

100-

Hydrated silicates 

Carbonates 

Graphite 

I QFM/ I 

EMOG?I 

Diamond C+2(Fe20 3)c-C02+4(Fe0) ~ 5 

Lithosphere Carbonates 

Hydrated silicates ______ -~-~ 

__ 

200 =-Asthenosphere- -D~-;;-nd -" :.. CH4+2(Fep3Jc=C+4(Fe0lc+2H20 

precipitation 

Diamond 

CH4+N2 (+rare gases) 

2H2+C=CH4 

"' 300- 1-< 

.f!!_ssolution Approximate lower stability limit of melhane- 10 

DJMs 

t? 

<l) 

~ 0 

:Q 

.s 

.ci 

..... 

0.. 

<l) 

400 _iQQ-Is_m ___ P~~LF:.). Si04..d~o~po~it~n _ 

discontinuity with release of H20 

0 500- UPPER 

MANTLE 

600-

t-------------

~8~-~ E_is~o~in~itt ____ _ 

700 t-- MgSi03 perovskite 

+ (Mg,Fe)O 

800 t--

LOWER 

MANTLE 

Hz+Nz 

( + rare gases) 

-20 

-25 

Figure 3. Subsolidus reactions and vapor transport in the mantle beneath the continental crust. c, crystalline phase; ceo. carbon + carbon dioxide + carbon monoxide; 

DHMS, dense hydrated magnesium silicate; EMOG, enstatite-magnesite-olivinegraphite (query indicates uncertainty that magnesite is present); f 02 , oxygen fugacity; 

IW, iron-wustite; MPa, megapascals; QFM, fayalite + quartz-magnetite; WM, wustitemagnetite. Large, open arrows indicate gas fluxes; small arrow indicates range of stability, queried to indicate uncertainty about depth limit of stability. 

89 

liths (Green and Radcliffe, 1975; Roedder, 1965, 1972. 

1984). The presence of carbonates and liquid C02 in the 

upper mantle is consistent with the independent determinations of the oxidation state in the upper mantle and 

strengthens the argument that neither methane nor hydrogen could originate from this region. 

The shallower parts of the upper mantle are believed 

to be relatively anhydrous, with all hydrogen present as 

hydroxyl groups in olivine (Mackwell and Kohlstedt, 

1990; Bai and Kohlstedt, 1992; Bell, 1992), in ~-(Mg, 

Fe)zSi04 (Young and others, 1991), in enstatite (Mackwell, 1991 ), and in minor hornblende, phlogopite, and apatite, although the hydroxyl sites of the apatite are partly 

occupied by fluoride (Aoki and Kanisawa, 1979). Marakushev (1981) notes that biotite from an African kimberlite 

pipe is very rich in F and Cl, suggesting a low partial 

pressure of water during its formation. The presumed very 

dry state of this region of the upper mantle is explained by 
90 THE FUTURE OF ENERGY GASES 

repeated generation of magma into which water partitions 

preferentially during partial fusion. 

Peridotites commonly contain small amounts of graphite or diamond. The presence of these minerals indicates 

an oxygen-fugacity range of the upper mantle, defined by 

the CCO, GEDOD, or EMOG family of buffers. Tingle 

and others (1988) have demonstrated that carbon solubility 

in olivine is negligible to 1500°C and 3.5 GPa. The presence of carbon in solid solution in mantle silicates therefore appears doubtful. 

The stability fields of carbonates and hydroxyl-bearing 

phases are important, because they govern both the existence and the composition of a coexisting fluid phase. Volatiles lower the melting point of peridotite, and the uptake 

of the volatiles in an incipient melt limits the quantity of 

melt formed for any given heat input. 

Double-shock-wave experiments to 90 GPa on methane (Nellis and others, 1981), also show that above 

10 GPa and 725°C (that is, at a depth of about 300 km), 

methane decomposes to diamond+hydrogen. In the lower 

mantle therefore, methane would not be present in any 

vapor phase. Hydrogen could migrate upward in the presence of metallic carbon or diamond. As the hydrogen penetrated upward, it could corrode diamond and generate 

methane. The actual composition of reducing gases in the 

system C-H-0 can only be surmised, as it depends on the 

oxidation state of the lower mantle (about which almost 

nothing is known), the presence of solid carbon phases 

and hydrated silicates, and lastly the stability of methane. 

If reduced fluids invaded the upper mantle, they would 

also depress the melting temperature of peridotites, but to 

a much lesser extent than would more-oxidized water-rich 

fluids. Hence the reduced fluids would be less likely to 

induce incipient melting. Both Hz and CH4 can, however, 

reduce Felli in peridotite minerals and alter the oxidation 

state of the upper mantle. Reactions involving the oxidation of Hz to H20 by Felli, 

Hz(vapor)+Fe20 3(forsterite,enstatite)= 

2FeO(forsterite,enstatite)+H20(vapor), (9) 

and the oxidation of methane, 

CH4(vapor)+ 2Fe20 3(forsterite,enstatite )= 

4FeO(forsterite,enstatite )+C+ 2H20(vapor) ( 1 0) 

will lead to the reduction of Felli to Fen, the precipitation 

of diamond, and the formation of water vapor. The water 

vapor will in tum depress the solidus and induce melting. 

The occurrence of microsized crystals of diamond in kimberlites suggests that such reactions occur. As Taylor and 

Green (1989) have pointed out, in the event that ascending 

vapors do not induce melting, they could migrate toward 

the surface, locally reducing the mantle, precipitating interstitial carbon, and producing hornblende and phlogopite 

mica if sufficient potassium is present from earlier metasomatizing episodes. 

TRANSPORT OF VOLATILES FROM THE 

MANTLE BY MAGMAS 

We now consider several physical chemical aspects of 

magma generation in the upper mantle, and how this 

magma generation affects transport of volatiles into the 

crust. Many magmas erupting in the continental crust and 

all magmas in oceanic settings have their origins in the 

upper mantle. Magmas are subject to many chemical and 

physical processes during their ascent-including assimilation, fractionation and phase segregation, and loss or gain 

of volatiles-leading to a host of different evolutionary 

paths and an enormous variety of igneous rocks as end 

products. In mantle source regions, the magma composition is defined by several critical parameters, of which the 

most important are the geothermal gradient and the presence or absence of volatiles. 

In figure 4 are displayed the relevant univariant reactions and invariant points in pressure-temperature, or depthtemperature, space for a peridotite-COz-HzO system. This 

diagram, originally developed by Wyllie (1980, 1989), 

shows the subsolidus stability fields of the hydrated minerals 

amphibole (hb), phlogopite mica (ph), and dense hydrated 

magnesium silicate (DHMS), and the carbonate minerals 

dolomite (dol) and magnesite (mag). The anhydrous peridotite solidus increases in temperature with increasing depth; 

but with the addition of water, the solidus temperature falls 

with increasing depth until a minimum is attained between 

60 and 70 km. Vapor components probably consist of a 

mixture of COz and H20 under most upper mantle conditions. The family of solidi representing mixtures of COz and 

H20 fall between the H20-saturated and anhydrous solidi. 

The solidus illustrated is for a C02/(C02+H20) mole fraction of 0.8. The magma's initial composition is expected to 

be rich in volatiles, but little is known otherwise of its 

composition. Wyllie and others (1990) discussed the experimental basis for believing that incipient melting would produce a magma containing between 20 and 40 weight percent 

C02; such a magma would be carbonatitic rather than silicic 

(kimberlitic) in composition. 

Two geotherms are shown on figure 4: G1, representing 

a typical continental geotherm found beneath stable cratons, 

and Gz, representing a typical geotherm found beneath oceanic crust. Initial melt formation occurs wherever the geotherm intersects the solidus, as at T m1 and T m2• For the 

continental geotherm (G1), this intersection falls between 

depths of approximately 200 and 300 km. When the continental geotherm just grazes the solidus, the generation of 

magma is very sensitive to local variations in the geothermal 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 91 

0 0 

I 

'.tev~ 

'~v~ \<Po~. 2 '~'% ,~ 

100 ',Gz ~ 

'~ ' '~o ' ,t:.o'£1 4 ' I ' "' "' I c;j ..... u ~ 

v "' «:1 

E l:l. 

«:1 

.£ 6 .~ 

:Q 200 OJ) 

.5 .5 

.s ![ 

::> l:l. "' v 

Cl 8 v "' 

..... 

Q.. 

300 10 

12 

Temperature, in degrees Celsius 

Figure 4. Simplified representation of solidus and subsolidus relations in the system peridotite-COTH20 in the upper mantle. C0_3, 

positions on solidus that influence dissolved volatile content of 

magmas; DHMS, dense hydrated magnesium silicate; dol, dolomite; G1, continental geotherm typical of that below a stable craton; G 1 +• continental geotherm displaced to higher temperatures by 

increase in thermal convection in upper mantle; G2, geotherm typical of that below oceanic crust; hb, hornblende; mag, magnesite; 

ph, phlogopite mica; I, liquid; T m , points at which solidus intersects geotherm and melting occur~;\ vapor. Modified from Wyllie 

( 1989). 

gradient and to volatile and local peridotite compositiOn. 

Increased thermal convection in the upper mantle could displace the continental geotherm (GJ+) to higher temperatures 

at the lithosphere-asthenosphere boundary, and this increase 

in temperature would increase the region of melting to much 

greater depths, as at T m4 • Melting could be induced by an 

increase in heat flow and by volatiles ascending from lower 

in the mantle. Because both hydrates and carbonates are 

stable within this region, a coexisting vapor phase at thermodynamic equilibrium will contain neither C02 nor H20. The 

vapor could, however, contain methane and (or) hydrogen or 

inert gases such as nitrogen (and rare gases) from the lower 

mantle. 

If deep-seated magmas were to migrate adiabatically, 

they could ascend to the surface along fractures and erupt 

with release of dissolved gases and the formation of diatremes. Diatreme eruptions of carbonatitic magmas from 

such depths are, however, rarely reported (Bailey, 1989). It 

myst be presumed therefore, that incipient magmas transpof'ting volatiles from such great depths very rarely ascend 

directly to the surface. It is more likely that the magmas 

cool partially during the ascent, become trapped under the 

solidus overhang between C0 and C3, and solidify. If the 

magma solidified between C0 and C1, it would release 

vapor composed of both H20 and C02. The vapor, especially if rich in C02, could produce extreme local overpressures and induce fracturing. If the fractures were to 

propagate to the surface, high-pressure gases and residual 

magma could produce a characteristic diatreme eruption . 

Between C1 and C2 the vapors would react with peridotite 

to form hornblende, and the residual vapor would be depleted in H 20. Between C2 and C3, both dolomite and 

hornblende are stable and therefore the residual fluid 

would be depleted in H20 and C02. 

The trapping and solidification of magmas under the 

solidus overhang is believed to be responsible for extensive upper-mantle metasomatism in the subcontinental 

lithosphere. The extent of metasomatism is limited by the 

capacity of the rock to react with the volatiles to form carbonates and hydrates. Eventually unreacted residual gases 

could accumulate until the vapor pressure exceeds the 

lithosphere overburden pressure. Release of vapor and entrained kimberlite and carbonatite magma would then 

ensue, as may have occurred in formation of diatremes observed in Utah (McGetchin and others, 1973). 

With increasing mantle convection and higher temperatures, the lithosphere/asthenosphere boundary is deformed 

to shallower depths; this deformation leads eventually to 

continental rifting and sometimes the formation of an oceanic spreading center. Under these conditions the geotherm 

is displaced upward to the position represented by G2 on 

figure 4. Eventually, extensive melting and magma production occurs from the region C0 downward to indefinite 

depths. Large volumes of basaltic magma ascend to shallow depth in the crust or erupt as copious flood basalts. 

Between the two extremes of deep, incipient melting at 

about 400 km and shallow mantle melting underneath oceanic spreading centers, magmas can range from carbonatitic 

and extremely silica-poor (-40 weight percent Si02) kimberlitic magmas through the alkaline basaltic to ocean 

tholeiitic magmas with in excess of 50 weight percent 

Si02. The deep~r seated the source of the magmas, the 

greater the potential volatile content, because of increasing 

C02 and H20 solubility with pressure and increasing C02 

solubility in alkaline magmas. It is therefore not surprising 

that deep-seated kimberlitic magmas often form diatremes, 

which through their structure and shape provide evidence 

of .substantial volatile loss from the mantle (McGetchin and 

Ullrich, 1973; Novikov and Slobodskoy, ·1978). 

The loss of C02 from the mantle is also evident in the 

formation and extrusion of carbonatitic magmas. Most 

carbonatites are composed primarily of calcite and dolomite, although alkaline carbonatites such as at Oldoinyo 
92 THE FUTURE OF ENERGY GASES 

Lengai, Tanzania, have been observed. Carbonatites are 

usually found in complex volcanic centers comprising 

large suites of alkaline basalts and related rocks. Such associations point to a relatively shallow lithospheric subcrustal source region where a primary silicic magma 

differentiated and exsolved immiscible carbonatite magma. 

Wyllie and others (1990) summarized experimental data in 

support of this interpretation. It is probable that such volcanic complexes arise from the melting and assimilation 

of previously metasomatized mantle either during a renewal of volcanic activity or perhaps during the cumulative 

phase of thermal upwelling. Although details of the differentiation process are not clear, the ample field evidence 

for emplacement of carbonatitic magmas in the continental 

crust prior to or during intracratonic rifting convincingly 

demonstrates that the oxidation state of the upper mantle 

lies within the carbonate stability field; reducing gases 

such as methane or hydrogen are not significant vapor 

components under these conditions. 

TRANSPORT OF VOLATILES 

IN THE CRUST 

ISOTOPIC METHODS FOR THE DETECTION OF 

GASES OF MANTLE ORIGIN 

For many years it was possible only to speculate on 

the release of juvenile gases from the mantle because there 

was no unambiguous means of distinguishing gases of 

mantle origin from those derived from crustal sources. 

Now it is recognized that the 3He balance in the Earth's 

atmosphere provides quantitative evidence for mantle degassing. Helium is a light noble gas comprising 4

He, 

formed primarily from the radioactive decay of uranium 

and thorium isotopes, and 3He, an isotope that forms from 

the radioactive decay of 3

H and from nucleogenic reactions involving 6Li(6Li(n,a)3He), when the primary source 

of free neutrons are a, n reactions involving such light 

elements as 0, S, and Mg in cosmic-ray interactions in the 

upper -300 em of the Earth's crust. Because helium isotopes have low atomic weight, they readily escape into 

space from the Earth's atmosphere. The quantity of helium 

in the atmosphere must therefore reflect the competition 

between the rate of loss to space and rates of production 

and addition by auroral precipitation. Helium produced in 

crust of average composition will have a 3

He/ 4He ratio of 

about 10-8 (for example, see Mamyrin and Tolstikhin, 

1984). The present atmosphere is enriched 100-fold in 3He 

relative to this crustal production ratio. Aldrich and Nier 

(1948) discovered that the 3

He/4He ratio varied greatly in 

minerals and well gases, and concluded that the 3

He in the 

Earth's atmosphere must be derived from some primordial 

source. Only 10 percent of the required flux of 3He could 

be accounted for until Clarke and others (1969) discovered 

that helium enriched in 3

He relative to that of the atmosphere was being released from the mantle at oceanic 

spreading centers. The mantle 3HefHe ratio is about 1 o-5, 

three orders of magnitude larger than that due to crustal 

production. The higher ratio is presumed to be due to the 

presence of primordial 3

He that was trapped in the Earth's 

interior during the early stages of planetary accretion. The 

large difference between mantle and crustal helium isotopic compositions makes helium the most efficient detector 

of mantle volatiles in the crustal regime. 

Measurements of the 3He/4

He ratios in gaseous and 

aqueous samples increased greatly with the discovery that 

3He is diagnostic of mantle involvement. This discovery 

stimulated further interest in the isotopic abundances of 

neon, argon, and xenon, which are now also studied in 

order to differentiate between mantle, crustal, and atmospheric sources. 

In the subsurface environment, rare gases are derived 

in varying amounts from the atmosphere (usually dissolved in water) from crustal nuclear reactions, and from 

the mantle. Gases from each source are characterized by 

distinctive isotopic ratios. The study of rare-gas abundances and isotope ratios in sedimentary basins together with 

associated gas-phase compositions is a powerful tool for 

interpreting the processes that lead to the formation of oil 

and gas fields. Although such studies are as yet in their 

infancy, many of the resultant findings are relevant to the 

central issue concerning the source(s) of hydrocarbons in 

sedimentary basins. Often implicit in such studies is the 

assumption that the oil and gas resources were derived by 

bacterial or thermogenic processes from organic matter 

contained in the sediments; this organic origin can be distinguished from a primordial origin on the basis of the isotopic components of the carbon. 

It should be noted that neither 3He nor other rare 

gases can substantiate a mantle origin for the carrier gas in 

which they are found, as the carrier gases could have been 

released and mixed with mantle-derived noble gases anywhere between the source and the sampling point. Methane (and hydrogen) emissions are commonly observed 

during hydrolysis by mafic and ultramafic igneous rocks, 

which also releases helium with a distinctive mantle signature. The emissions of crustal origin are discussed in a 

later section. Although a mantle 3He signature is clearly 

associated with the methane, arguments in favor of a mantle origin for the methane cannot be justified from field or 

theoretical arguments (Jenden and others, this volume). 

THERMODYNAMIC STABILITY OF C-H-0-N-S 

GASES IN THE CRUST 

Before considering the evidence for vapor-phase transport in the crust, it is worth examining the thermodynamic 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 93 

relations of components composing a vapor phase as a 

function of depth in the continental crust. In figure 5, 

phase relations of relevant solid and gaseous species are 

again plotted as a function of RTln f 02, on this occasion 

between 0 and 1 ,000°C along a continental geothermal 

gradient averaged at 1 rc!km, with appropriate corrections for pressure. In addition to the reactions depicted in 

figure 2, other reactions defining the oxidation state with 

respect to volatile species have been included: 

(II) 

(12) 

(13) 

(14) 

(15) 

The reaction 

(16) 

defines the decomposition of methane to graphite + hydrogen. The following text, on clarifying vapor-phase relations, refers repeatedly to figure 5. 

MAGMA TRANSPORT 

MAGMA OXIDATION STATE 

The oxidation state of a magma can be correlated with 

the composition of any evolving gases. Unmodified magmas should possess an oxidation state similar to that of 

their source regions in the upper mantle. Therefore, magmas can under favorable circumstances shed further light 

on the oxidation state of the upper mantle and the stability 

of vapor components. 

In practice, direct measurement of the oxygen fugacity 

of a magma can currently be achieved only through the use 

of an yttria-stabilized zirconia electrode probe inserted into 

a lava lake. Because this technique is limited in its application, and sometimes dangerous, other indirect methods 

have been used to interpret the oxygen fugacity. Such methods involve certain assumptions that cannot always be 

Figure 5. Gas-gas and gas-solid-phase equilibria involving volatile components in system C-H-0-N-S as function of RT!n / 02 

(where R is universal gas constant, T is temperature, and In f 02 is natural log of oxygen 

fugacity) and temperature on a 17.3 oc km -I 

geotherm. Black curves are dashed where 

equilibria are metastable. Light lines from 

upper left to lower right are lines of equal 

log [ 02, in bars. GEDOD, graphite-enstatitedolomite-olivine-diopside; HM, hematitemagnetite; IM, iron-magnetite; IQF, iron + 

quartz-fayalite; IW, iron-wustite; PPM, pyrrhotite-pyrite + magnetite; QFM, fayalite + 

quartz-magnetite; WM, wustite-magnetite. 
94 THE FUTURE OF ENERGY GASES 

tested or proven. These include measurement of (I) the fo2 

of reheated rock samples using an yttria-stabilized zirconia 

electrode, (2) the residual gas-phase and condensate composition in lava vesicles or fluid inclusions in glasses, and 

(3) the Feiii/Fen ratio in the quenched glass or minerals that 

precipitated from the magma. These studies suggest that the 

oxidation states of magmas derived from the mantle range 

from -3 to + 1.5 log units with respect to the oxidation state 

of the QFM buffer (Carmichael, 1991 ). 

In recent years the validity of results ?btained by 

method (1) has been questioned. The presence of deuterjc 

graphite can cause misleadingly low measurements of oxygen fugacity. Mathez ( 1984) pointed out that early-crystallized minerals toward the base of large layered mane 

intrusions imply oxidation states close to that of the IW 

buffer (for example, see Elliot and others, 1982, and Sato 

and Valenza, 1980), which is much lower than that of effusive basalts sourced in the mantle. f 02 measurements on 

spinels from mantle lherzolites using method (I) (Arculus 

and Delano, 1980) also implied that the oxidation state of 

the mantle was near that of the IW buffer. The possibility 

that the loss of volatiles might affect the oxidation state 

and hence the Feiii/Feii ratio in minerals or quenched 

glass led Mathez (1984) and others (for example, see 

Anderson and Wright, 1972; Sato, 1978a; Gerlach, 1980; 

Sakai and others, 1982; Carmichael, 1991; Wallace and 

Carmichael, 1992) to consider this question further. Of 

particular relevance are these reactions: 

0 2(m)=02(v), (17) 

H20(m)=H20(v), (18) 

2H20(m)=02(m)+2H2(v), (19) 

H20(m)+0--(m)=20H-(m), (20) 

s--(m)+HzO(m)=O--(m)+HzS(v), (21) 

2S--(m)+02(m)=20--(m)+Sz(v), (22) 

s--(m)+ 1.502(m)=0--(m)+S02(v), (23) 

S2(m)+20--(m)=2S--(m)+Oz(m), (24) 

so4--(m)=S--(m)+20z(m), (25) 

C03 --(m)=0--(m)+0.50z(m)+CO(v), (26) 

2Fe +++(m)+O--(m)=2Fe ++(m)+0.502(m), (29) 

where (m) represents the melt species and (v) the vapor or 

gaseous species. Melt species are represented formally for 

convenience. Because melts are partially to completely polymerized, some species may be complexed with the silicate structure, here represented as o--(m), whereas others 

are present as ionic or molecular species. Complexation in 

a melt can affect the activities of other dissolved species 

and the fugacities of vapor components. For example, 

water in small concentrations in the melt is almost wholly 

complexed as OH-, decreasing the activity of H20(m) and 

the fugacity of H20(v). 

The loss or gain of volatiles in the magma can cause 

shifts in the oxidation state, which will in tum affect the 

intem<d distribution of species. Sulfur species, for example, are sometimes saturated with respect to a ferrous sulfide melt (Wallace and Carmichael, 1992), thus: 

0.5S2(v)+Fe++(m)+0--(m)=FeS(m)+0.502(v), (30) 

in which fs/fo 2 is constant at a given pressure and 

temperature. 

Volatile loss can occur either through diffusive transport through the magma boundary interface or through exsolution during depressurization or cooling. It is evident 

from reactions 19, 22, 23, 26, and 27 that volatile loss will 

change the oxidation state. 

Sato (1978a) and Dyar and others (1992) believed that 

the diffusive loss of hydrogen gas from magmas, reaction 

19, led to their progressive oxidation. Mathez (1984) invoked reaction 26 under near-surface conditions to justify 

his belief that midocean-ridge basalt (MORB) is more oxidized than the source region. Wallace and Carmichael 

(1992) argued, and presented with supporting field evidence, that because sulfur is present in mafic magmas primarily as s--, the loss of S02 from oceanic-island basalt 

(OIB) magmas causes their reduction (reaction 23). The 

relative importance of these processes and their effect on 

the Feiii/Feii ratio in magmas and in the coexisting mineral phases crystallizing from magma depends on many 

thermodynamic, kinetic, and transport processes that need 

not be enumerated further. The distribution of species in 

the evolved gas phase depends on the contributions of volatiles dissolved in the magma and the concentration of 

iron in the magma. If lavas derived from deep in the upper 

mantle, such as primary carbonatites or kimberlites with a 

relatively high carbonate content, were to ascend into the 

shallow crust, they could evolve C02 (+CO) when the 

volatile pressure exceeded the lithostatic pressure and become more oxidized during emplacement, as is well illustrated by Bailey ( 1989). There is, however, no evidence to 

indicate that typical MORB or OIB magmas contain sufficient volatiles to release gas and modify their oxidation 

states before emplacement in shallow crustal reservoirs 

(Wallace and Carmichael, 1992). Pressure changes between the source region and the crust will also not signifi-
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 95 

cantly alter the distribution of species dissolved in the 

melt. Any shift in oxidation state due to the release of volatiles is therefore likely to take place relatively near to the 

Earth's surface. 

Because basaltic magmas are unlikely to lose volatiles 

during ascent, they would be expected to retain an oxidation state somewhat similar to that of the environment in 

which they are generated. All evidence (Gerlach and Nordlie, 1975c; Sato, 1978a; Mueller, 1971; Gerlach, 1993) 

strongly suggests that the oxidation states of such magmas 

are too high to support methane, and that exsolution of 

gaseous components results in volcanic gases rich in carbon 

dioxide, water, sulfur dioxide, and hydrogen sulfide. The 

oxidation state of more-reduced gases from the ultrapotassic lavas of Nyiragongo, Zaire (Gerlach, 1980) are -0.5 log 

units relative to the QFM buffer. In these lavas, the 

dominant vapor species are C02 (+CO), H20, and 

S02+(S2+H2S). In spite of the uncertainty in establishing 

the mantle oxidation state from crustal igneous rocks, the 

constraints are such that even lavas from Nyiragongo are 

too oxidized to permit significant formation of methane or 

hydrogen. Thus we conclude that most if not all source 

regions in the upper mantle are too oxidizing to permit the 

presence of methane. 

Few magmas migrate to the crust or extrude intact on 

the Earth's surface without any exchange of chemical 

components. Many accumulate in magma chambers, 

where they can become contaminated with crustal rocks, 

lose or gain volatiles, and differentiate through precipitation of rock-forming minerals. Large bodies of basaltic 

magmas, upon crystallization, precipitate ferromagnesian 

minerals enriched in the Fell component over Fe III. The 

residual magma is then:fore increasingly concentrated in 

Felli and becomes progressively more oxidized until titanomagnetite saturates and precipitates (for example, see 

Carmichael, 1991; Snyder and others, 1993). 

As noted earlier, in very large layered mafic intrusive 

bodies, the lowest horizons are sometimes more reduced 

than higher ones. The history bearing on the emplacement 

of these intrusions is complex, and the oxidation state of 

the lowermost horizons may not necessarily reflect the oxidation state of the source region. Late-stage volatile enrichment, the incorporation of volatiles from the country 

rock, and metasomatism in these bodies could impose a 

reducing signature that was not originally present in the 

magma. Recently, however, Snyder and others (1993) 

have critically evaluated the temperature-/02 path taken 

during the crystallization of the Newark Island layered intrusive in Labrador and have supported their evaluation 

with experimental studies. They concluded that the oxidation state of the parent tholeiitic magma was probably 

within about 0.5 log units of the IW buffer. They further 

concluded that many other layered intrusives probably followed similar trends in f 02. Their estimates are somewhat 

lower than the range of oxidation states proposed by 

Blundy and others (1991) for the upper mantle beneath 

the continental crust. It is possible that the oxidation state 

of tholeiitic magmas is buffered initially by the ceo reaction (reactions 7, 8). This oxidation state is still too 

high to stabilize methane. 

FIELD EVIDENCE 

In this section, we discuss field observations that provide direct evidence for the composition of the principal 

gaseous or vapor components emitted from magmas in either the shallow regions of the crust or in the atmosphere. 

We consider available evidence for a range of magma 

types from kimberlite to andesite and dacite. All of these 

magmas are known to be derived from the mantle, and 

exsolving vapors, when measurable, have 3Her4He mantle 

signatures. Their magmas' modes of origin in the mantle 

permit classification into four distinct groups: (1) magmas 

generated beneath the continental lithosphere and intruded 

into stable cratons, (2) magmas generated during subduction of oceanic crust, (3) magmas generated at spreading 

oceanic centers, and (4) magmas generated at oceanic islands. Field evidence for gas evolution in these environments is discussed further below. 

CONTINENTAL LITHOSPHERE 

Continental crustal cratons are subject to rifting and 

breakup. The initial stages of rifting are characterized by 

kimberlitic magmatism with diatreme formation. Diatremes 

form near the Earth's surface during the rapid and continuous 

exsolution of volatiles from a magma body. During the initial 

stages, magmas penetrate upwards along fractures that propagate as a result of regional stresses. During ascent, volatiles 

exsolve from the magma, thus decreasing the mean density 

of the ascending melt-fluid mixture. With breakthrough at the 

surface, the gas and entrained magma in the upper parts of 

the channel can attain very high velocities, estimated by 

McGetchin and Ullrich (1973) to be up to 350 m s-1. The 

venting high-velocity gas and entrained magma carry fragments of wall rock and comminuted particles from great 

depth. The particles ablate the vent channel and cause it to 

develop an oblong or circular cross section beneath the vent 

(Novikov and Slobodskoy, 1978). With dissipation of the 

exsolved gas, the high-velocity jet stage of the eruption 

terminates. In kimberlitic and primary carbonatitic eruptions, 

magma and the initially dissolved gases ascend from depths 

of between 200 and 400 km. Those associated with alkalic 

magmatism may originate at somewhat shallower depths. 

Diatreme eruptions are probably somewhat similar if not 

identical to a classical Plinian eruption, with formation of a 

typical maar-type explosion crater surrounded by pyroclastic 

ejecta. It should be emphasized, however, that not all maars 
96 THE FUTURE OF ENERGY GASES 

form through diatreme activity, and not all diatremes vent at 

the surface to produce maars. Some diatremes dissipate upward into megabreccias, which in turn grade into undisturbed 

country rock (McGetchin and others, 1973; Gabelman, 

1977). 

Bratus and others ( 1987) studied the compositions of 

fluid inclusions in chilled glass spherules from some kimberlite breccias and from the Udachnaya-Zapadnaya, 

Yakutia, Russia, kimberlite pipe. The kimberlite pipe contained a few native iron inclusions, and all spherules were 

similar to melilite in composition. The gases contained in 

the inclusions were primarily nitrogen (75-96 percent), 

methane (4.4-16 percent) and carbon dioxide (2.4-9.5 percent). The gas-phase composition is consistent with the 

presence of native iron and indicates strongly reducing 

conditions near the iron-wustite phase boundary. The presence of such a large concentration of nitrogen is unexpected, and raises questions as to whether the reduced gases in 

the inclusions correspond in composition to fluids in the 

source region of the kimberlitic magma. However, Kravtsov and others (1979) have also reported high nitrogen contents in gases evolved upon crushing samples from the 

Mir pipe in Yakutia. It is possible that such gases are representative of very deep sources where reduced gases are 

oxidized to diamond and a nitrogen residue remains. 

What gas-phase composition is associated with kimberlitic diatreme formation, therefore, remains an open 

question. With the meager information available, an inconsistency exists between the inferred oxidation state of kimberlitic magmas, which suggests relatively oxidizing 

conditions, and the gas-fluid-phase composition in the 

erupted glass spherules, which suggests strongly reducing 

conditions. Hydrocarbon gases and bitumen were also 

found in the Udachnaya-Zapadnaya pipe (Kravtsov and 

others, 1976), but it is not clear whether such occurrences 

are due to the primary release of gases during diatreme 

formation, or whether the hydrocarbons and bitumen have 

formed as a result of hydrothermal alteration after emplacement. Organic material could also have migrated 

from adjacent sedimentary host rocks as is inferred from 

the gas chromatography studies of the bitumens in the 

pipe (V dovykin and others, 1979). Abundant circumstantial evidence, such as the association of kimberlites with 

carbonatitic magmas and the presence of liquid C02 inclusions in olivines incorporated in kimberlitic magmas suggest that the vapor phase of kimberlite eruptions is likely 

to be predominantly carbon dioxide (Murck and others, 

1978; Pasteris, 1988). Clearly, further study of this question is needed. 

Although kimberlite pipes are widespread in continental crust, the cumulative release of vapor during pipe formation is unlikely to have contributed significantly to 

natural-gas resources over geologic time even if the gases 

released were pure methane. No natural-gas reservoirs 

have ever been linked to diatremes. Assuming that carbon 

dioxide is present and near saturation at mantle depths, a 

kimberlitic magma would contain about 3.5 weight percent C02. If all of this gas were released to the atmosphere, it would be equivalent to about 1.9xl0-3 m3kg-1 

of kimberlite. Kimberlitic intrusions are small, however, 

and therefore an isolated intrusive event is unlikely to discharge more than 6x108 m3 gas for 0.01 km of magma. 

This quantity is of the same order of magnitude as the 

quantity of gas discharged from Lake Nyos in Cameroon 

in 1986, to be discussed further, below. 

Volatiles associated with carbonatitic magmas are rich 

in C02 and H20, and are sometimes responsible for extensive carbonate and potassic metasomatism of surrounding 

crustal rocks. Treiman and Essene (1984) found that a 

late-stage carbonatite dike in the Oka, Quebec, alkaline 

complex contained all minerals necessary to define 

uniquely the oxidation state of the magma. At the inferred 

eutectic of the melt at 640°C and 100 MPa, oxygen fugacity was near that of the QFM buffer, and the gas fugacities, in MPa, were as follows: C02, 11.0; H2, 0.46; H2S, 

0.27; CO, 0.05; and CH4, 0.01. It was assumed that the 

difference between the sum of the pressures of the cited 

gases and the 100-MPa total pressure was made up by a 

pressure for H20 of 88.2 MPa. Although the H20 partial 

pressure seems high, even for a late-stage carbonatite, the 

oxidation state is consistent with a mantle fo 2

-

Agpaitic magmas, which are genetically related to carbon<,ltitic magmas, sometimes produce strongly reducing 

conditions upon solidification and cooling, owing to the 

formation of hydrogen and methane as well as smaller 

amounts of C2H6 to C5H 12 and dispersed bitumens. There 

is no evidence, however, of significant methane in gases 

released during volcanic eruptions of such magmas. 

Gerlach ( 1980), using analyses of gases collected in 1959 

from the ultrapotassic nephelinite lava in the lake at Nyiragongo (Chaigneau and others, 1960), estimated that the 

venting gas was composed of 35 to 50 percent C02, 45 to 

55 percent H20, 1 to 2 percent S02, 2 to 3 percent CO, 

1.5 to 2.5 percent H2S and traces of other volatiles including S2 and COS. The oxidation state of this lava lake, as 

noted previously, is about 0.5 log units below that of the 

QFM buffer. 

When mafic magmas fail to penetrate to the surface 

before congealing, the gases released can be trapped in 

overlying sedimentary formations, or they can leak 

through to the surface as gas vents or springs releasing 

copious quantities of gas. In all such documented occurrences, discussed below, the residual gas is always carbon 

dioxide. Whenever measured, all known occurrences of 

crustal carbon dioxide accumulations display evidence of 

mantle carbon '(via () 13C values) and helium (via 3HeflHe 

ratios). Furthermore, most are found in the vicinity of continental rifts and are associated with mafic magmatism. 

The carbon dioxide is the residue of a gas phase that undoubtedly includes H20, S02, and H2S. But the latter 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 97 

components condensed and (or) reacted with the country 

rocks and are therefore no longer evident. 

One of the best described examples of crustal carbon 

dioxide accumulations is in the region bordering the Rio 

Grande Rift in New Mexico and the adjacent Four Comers 

area of Arizona, Colorado, New Mexico, and Utah. This 

region is characterized by numerous isolated centers of 

Tertiary and Quaternary mafic magmatism and scattered 

clusters of diatremes, some of which contain kimberlite 

and (or) carbonatite (McGetchin and Silver, 1970; 

McGetchin and others, 1973). This region includes the 

southeastern corner of the Colorado Plateau, an uplifted 

cratonic block long known for extensive occurrences of 

sandstone-hosted uranium deposits. Speculation on the origins of these deposits is controversial (Nash and others, 

1981). Gabelman (1977) suggests that uranium mineralization in this area might be derived from mantle diatreme 

activity, but it could also originate from the weathering of 

Tertiary intermediate to felsic igneous rocks that are distributed over the Colorado Plateau. 

A distinctive feature of the area is the occurrence of 

carbon dioxide gas reservoirs. They have been discovered 

in sedimentary rocks in the McElmo Dome, Montezuma 

County, Colorado, at Sheep Mountain in Colorado, afld in 

the Bravo Dome in Harding and Union Counties, New 

Mexico (Krivanek, 1978; Broadhead, 1985, 1987, 1990). 

The carbon dioxide is currently being recovered from 

these reservoirs for enhanced oil recovery in West Texas 

oil fields. Two smaller fields closer to the Rio Grande rift, 

the Estancia and Union Des Moines fields, have been 

abandoned. 

The quantity of C02 in these reservoirs is substantial. 

The Bravo Dome alone contains between 5.3 and 9.9 trillion cubic feet (Tcf) (1.5 to 2.8x10 11 m3) over a 324,000-

hectare area (Broadhead, 1987). Staudacher ( 1987) 

reviewed all prior information pertaining to rare-gas isotopic ratios for C02 gas wells of the Bravo Dome and 

showed that helium, neon, argon, and xenon isotope ratios 

were all consistent with an upper-mantle origin with negli- · 

gible contributions from crustal sources and minor atmospheric contamination. Furthermore, o13C values for the 

C02 were typical of those for C02 in vesicles of MORB, 

implying that the carbon dioxide also had a mantle origin. 

Although Tertiary and Quaternary basalts are present 

in the vicinity of the Bravo Dome and other C02 fields in 

Colorado and New Mexico, direct evidence for carbon dioxide degassing from basaltic magma has not been established. Indeed, Broadhead (1987) notes that the areas with 

volcanic rocks and the areas with the largest known C02 

occurrences in northeastern New Mexico are mutually exclusive. Very little volcanic activity has occurred in and 

around the Bravo Dome field. He believes that C02 ascended along deep-seated basement faults from the lower 

crust or mantle. A much closer connection with volcanic 

activity can be made for the McElmo Field of the Four 

Corners region (Krivanek, 1978). The southern flank of 

the McElmo Dome plunges towards the Ute Mountain laccolith, 4 mi distant, and an exposed northeast-striking dike 

radiating from the laccolith is even closer to the top of the 

dome. 

Numerous anticlinal structures in Mississippian rocks 

of the Four Corners region have been explored for oil and 

gas. Many of the wells on these structures have produced 

gases very rich in carbon dioxide, nitrogen, and helium 

(Picard, 1960, 1962; Casey, 1983). Gases with >50 percent 

C02 are concentrated in the Utah and adjacent Colorado 

quadrants, whereas those with >50 percent nitrogen are 

found principally in the New Mexico quadrant of the Four 

Corners area. 

Of particular interest is the high concentration of helium (2-8 percent) in gases of the New Mexico quadrant 

and adjacent Arizona (Casey, 1983). Since the late 1940's, 

these gases have been exploited for their helium content; 

Casey (1983) estimated remaining reserves of 3 to 5 billion cubic feet (Bcf) (0.8 tol.4xl08 m3) containing 5 to 8 

percent He. 

One such example is the Dineh-bi-Keyah field in 

northeastern Apache County, Arizona, which produces oil 

and He-bearing gas (Pohlmann, 1967; McKenny and Masters, 1968). The gas is composed largely of nitrogen (approximately 79-92 percent) with lesser helium (5.2-6.2 

percent) and carbon dioxide (1.4-11 percent) and traces of 

other gases, but with very little methane (0.14-3.4 percent). A distinctive feature of this field is that the oil and 

gas reservoir is a lamprophyre sill, 0 to 180 ft thick covering an area of about 6 mi2. The rock is characteristic of 

those with a deep-seated origin in the upper mantle. The 

sill is slightly altered and has a primary vugular porosity 

averaging 10 percent, suggestive of a high initial concentration of gas dissolved in the parent magma. The oil presumably migrated from nearby source rocks into the 

porous igneous sill. Assuming that the sill was intruded at 

a depth about 1,250 m below the surface, at 1,200°C and 

that the primary vugular porosity was 8 percent, the total 

gas released by this sill must have been on the order of 

I X I o9 m3 at standard temperature and pressure (STP). 

Unfortunately, isotopic studies of gases from the Four 

Corners region have not yet been published. The extent of 

mantle gas contribution is thus unknown, even though 

many of the numerous volcanic rocks in the region suggest a deep-seated mantle origin. The C02 content of these 

gases could therefore have been due to degassing of primary magma, but it could also be attributed to metamorphism of Mississippian limestones by the numerous 

intrusions in the region, although the metamorphic origin 

seems less likely. 

The gases with high helium content occur in proximity to uranium deposits hosted in sandstones of the Jurassic 

Morrison Formation and are probably radiogenic. Helium 

could be derived from crustal uranium or from uranium 
98 THE FUTURE OF ENERGY GASES 

concentrated in the shallow lithosphere by metasomatic 

processes. If the helium is radiogenic and has its origin in 

the crust, the observed correlation of helium concentration 

with nitrogen concentration might be expected, as will be 

discussed below. The Four Comers region evidently has a 

complex tectonic history, and the isotopic compositions of 

the gases merit further study. 

Carbon dioxide accumulations in sedimentary rocks 

and associated with recent intraplate basaltic volcanism 

have also been observed near Mount Gambier in South 

Australia (Chivas and others, 1987). At this locality, C02 

is produced from a single well at depths below 2.5 km 

from a carbonate-poor Cretaceous sandstone at 92°C and 

24 MPa. Chivas and others report a production rate of 

28,000 tonnes/year (1.6x107 m3 yr-1). 

The association of maar formation with alkaline basaltic magmatism is quite common and lends credence to the 

hypothesis that most maars are due to C02 degassing from 

magmas, as suggested by Chivas and others (1987), rather 

than the generation of superheated steam through magma 

contacting ground water. An occurrence of maar formation 

associated with the release of C02 gas was documented by 

Barnes and McCoy (1979). In April 1977, two maars 

formed on the Alaska Peninsula during a few days of intense phreatic eruptions during which olivine basalt was 

extruded. Gas Rocks, 3 mi from the newly formed maars, 

was observed in July 1977 to be emitting "enormously 

greater discharges of [COz-rich] gas than previously." The 

gas contained 97 percent C02 with o13C=-6.36 permil, 

typical of a mantle origin. Although the maars are associated with a subduction zone, their formation has much in 

common with continental cratonic environments. 

The more quiescent loss of C02 from wells and fissures in the Eiffel districts, adjacent to the Rhine Graben 

in Germany, is also noteworthy. In a region containing numerous maars, C02 is being released to the atmosphere at 

a rate of 0.5 to lxl06 tonne yr- 1

, (2.8 -5.6xi08 m3 yr- 1

) 

(Puchelt, 1983). The magmas in both the West and East 

Eiffel districts are alkaline (Illies and others, 1979). Those 

in the West Eiffel are mainly undersaturated nephelinites 

and leucitites, whereas those in the East Eiffel range from 

intermediate to phonolitic in composition. 

Recently, Griesshaber and others (1992) reported on 

the helium and carbon isotopic systematics in mineral 

springs and gas discharges from the Eiffel, Rhine Graben, 

and Black Forest areas. All discharges show a mantle helium component ranging from <1 percent to nearly 70 percent. C02 isotopic signatures likewise reveal apparently 

simple binary mixtures of mantle and crustal thermogenic 

components. In the Eiffel districts, especially, the mantle 

component is very high, with 3He content ranging from 

0.8 to 5.6 times that found in the atmosphere. The highest 

values are clustered in two small regions of I 0 and 

125 km2, the first of which is bordered by the Rieden, 

Wehr, and Lacher See calderas. Griesshaber and others 

(1992) showed that the regions with high mantle 3He/4

He 

ratios are far more widespread than the surface volcanic 

rocks and concluded that much of the magmatic activity 

fails to break through to the surface. In this respect, the 

Rhine Graben is similar to the Sacramento Valley of California (Poreda and others, 1986; Jenden and others, 

1988a) and the Four Comers area gas fields. 

Xu and others (1990, 1991) described several gas 

fields in China, all of which have strong mantle helium 

signatures. With the exception of one field with 

RIRA=0.27 (where R=3He/4He in measured sample, and 

RA=3He/4He in air, or 1.4x1Q-6), all others have R/RA ratios between 2.65 and 5.01. With two exceptions, all o13C 

values for C02 are typical of C02 from the mantle (-8.9 

to 1.0 permil). The compositions of gas from a number of 

these fields are almost entirely C02, ranging from 85 percent to >99 percent. The most C02-rich fields, in eastern 

China, are all associated with the Cathaysian rift and Mesozoic and early Tertiary volcanic activity. 

Evidence that basaltic magmatism might be the source 

of large accumulations of C02 in the crust was also made 

apparent by the Lake Nyos disaster in Cameroon. Lake 

Nyos occupies a maar crater 1,400 m long, 900 m wide, 

and 200m deep (Sano and others, 1987b), one of several 

resulting from diatreme eruptions in the area (Kusakabe 

and others, 1989). The diatremes form part of the Cameroonian Volcanic Line, a chain of alkaline volcanic centers 

trending northeast across Cameroon from the Atlantic 

Ocean. Pyroclastic deposits containing mantle xenoliths 

are present on the north and east flanks of the Lake Nyos 

crater. 

In 1986, a large volume of C02 gas, estimated by 

Giggenbach (1990) to be 240,000 tonnes (1.2x108 m\ 

erupted from the lake and asphyxiated 1,700 people and 

all animal life as far as 14 km away. A similar but smaller 

event in nearby Lake Monoun killed 37 people in 1984. 

Subsequent investigations of the rare-gas content of waters 

from both lakes showed that the 3He/ 4He ratio was typical 

of those found in circum-Pacific volcanic zones, and after 

correction for atmospheric contamination using the 

HeP~e ratio, indicated that the rare gases were almost 

entirely derived from the mantle. Furthermore, o13C values were also consistent with a magmatic (that is, upper 

mantle) origin (Sano and others, 1987b; Kusakabe and 

others, 1989). Tuttle and others ( 1992) concluded that the 

distinctive dense carbonate- and iron-rich waters of the hyperlimnion in Lake Nyos are being recharged from the underlying diatreme. These waters form when ascending 

magmatic C02 dissolves in water saturating the mafic pyroclastics in the diatreme neck and leaches Fe++, Mg++, 

and Si02 (aqueous). 

Finally, reference must be made to gas emissions 

accumulating in Lake Kivu in eastern Central Africa. 

Enormous quantities of methane, about 6x109 m3, are dissolved in the stratified lake. The methane concentration in-
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 99 

creases with depth, the highest abundances occurring at 

the lake bottom, (Tietze and others, 1980; Schoel and others, 1988). Gold and Soter (1980) and Gold (1987) attributed the source of this methane to the mantle because the 

lake occurs in a rift zone and Nyiragongo, an active volcano emitting silica-poor alkaline basaltic lavas is found on 

the north shore of the lake. 

Less attention has been paid to the fact that the lake 

contains five times as much C02 as methane, about 

3xl010 m3. This C02 has a typical magmatic or mantle 

&13C signature (Tietze and others, 1980; Schoell and others 1988). Apparently the nutrients in the lake promote 

planktonic growth, which reduces the C02 to organic matter that settles through the hyperlimnic, anoxic lower regions of the lake and accumulates on the lake floor. 

Methanogenic bacteria subsequently destroy the organic 

detritus and release methane to the water. &13C, &D, and 

14C values confirm. bacterial activity in methane gas generation (Schoell and others, 1988). 

SUBDUCTION ZONES 

Although less commonly recognized, carbon dioxide 

degassing is also associated with calc-alkaline magmatism 

above subduction zones at island arcs and continental margins. One such example occurs in the Cascade Range of 

North America. Subsurface accumulations of C02 with 

&13C between -5.38 and -6.10 permil have been found in 

a well at the Klickitat C02 field near the Columbia River 

in Washington state (Barnes and others, 1982). The size of 

the gas accumulation is unknown and little is known about 

the associated igneous rocks, but its presence in the heart 

of the Cascades Volcanic Belt suggests subsurface degassing of magmas that are forming through subduction and 

fusion of the underlying Juan de Fuca Plate. Another example is from the Indonesian archipelago. Carbon dioxide 

gas released from a fissure during a phase of active volcanism on the Dieng Plateau in Java asphyxiated 142 villagers (Le Guem .and others, 1982). The previously cited 

maar eruption on the Alaska Peninsula (Barnes and 

McCoy, 1979) is also an example of carbon dioxide release during subduction-zone magmatism. 

Volcanism associated with the subduction of oceanic 

crust is known for violent pyroclastic eruptions in which 

the release of volatiles from the magma plays a major 

role. Gold ( 1987) has suggested that these eruptions, particularly those which produce large calderas, are manifestations of the catastrophic releases of enormous quantities 

of mantle gases. Petrologic data provide overwhelmingly 

evidence for the exsolution of water vapor with smaller 

quantities of carbon dioxide, hydrogen sulfide, and sulfur 

dioxide from such magmas during eruption. H2 and CH4 

are only very minor constituents. Therefore the presumption that volcanic eruptions in subduction zones release 

large, uncontrolled volumes of mantle methane cannot be 

substantiated by field evidence. The oxidation state of 

these magmas is commonly near the QFM buffer or higher. Pyroclastic magmas inherit water from the fusion of a 

subducting oceanic crust, but could also take up significant 

quantities of water during ascent through a hydrous crust. 

The concentrations of water in such magmas is sometimes quite high. For example, a dacite pumice erupted 

by Mount St. Helens, Washington, some 3.5 million years 

ago contains 6.4 weight percent H20, and a pre-1991-

eruption dacitic magma from Pinatubo, Philippines, was 

found to contain 5.5 weight percent H20 (Rutherford, 

1993). Experimental studies also indicated that magmas 

erupting from Mount St. Helens between 1980 and 1985 

originally contained about 4.6 weight percent H20 (Rutherford and Devine, 1988). These water contents are 

equivalent to water fugacities of approximately 150 to 

200 MPa in the magma. Although H20 is the dominant 

volatile dissolved in pyroclastic magmas, C02 (+CO) is 

also present in significant concentrations. Measurements 

of the H20/C02 mass ratios are difficult to come by, but 

the ratio appears to be on the order of I 0 to 100. The 

quantity of C02 emitted by a mafic. eruption is therefore 

very large. Assuming a ratio of 30, the May 1980 pyroclastic eruption at Mount St. Helens would have released 

over 3x 109 m3 C02 at STP. Harris and others (1982) estimate that Mount St. Helens emitted a further 9.1 x 105 

tonnes (5x108 m3

) of C02 during the months of July to 

October following the eruption. 

The C02/S02 mass ratio during the Mount St. Helens 

eruption is better known but fluctuated with time, ranging 

from 2 to 15, with an average around 7. According to Casadevall and Greenland (1982), most of the sulfur dissolved 

in the Mount St. Helens magma was in the sulfide, that is, 

in the form Hs-, and it was released as H2S. The principal · 

sulfur species in the plume of El Chich6n, Mexico, after its 

eruption in March 1982 was also H2S (Kotra and others, 

1983). Increased water vapor fugacity shifts the reaction 

0.67H2S+02=0.67S02+0.67Hp (13) 

to the left (Ohmoto and Rye, 1979). Because pyroclastic 

magmas contain so much dissolved water, H2S is stabilized, even though the oxidation state of the magma is 

near the QFM buffer. Apparently, once the sulfur species 

are released to the atmosphere, they are rapidly oxidized 

to S02 and eventually to H2S04 aerosol, the reaction 

probably being catalyzed by the surfaces of ash particles. 

In some subduction-zone volcanoes, the magmas also 

contain so much sulfur and the oxidation state is sufficiently high that primary anhydrite· and magnetite crystallize from the magma prior to eruption as was the case at 

El Chich6n and Pinatubo (Rutherford, 1993). Both Pinatubo in 1991 and El Chich6n in 1982 erupted enormous 

quantities of sulfur species that could be readily identified 
100 THE FUTURE OF ENERGY GASES 

by airborne detection methods and satellite imagery (Bluth 

and others, 1992; Arnold and others, 1990; Hirono and 

Shibata, 1983). The Pinatubo eruption released 1.8xl07 

tons or 7.3x109 m3 of S02 (Rutherford, 1993). The quantities of C02 and water vapor released have not been computed but were undoubtedly of similar magnitude or 

greater. 

MIDOCEAN RIDGES AND 

OCEAN ISLANDS 

Gases emitted by magmas at midocean-ridge spreading centers and ocean-island plumes are somewhat more 

reducing than those erupting from subduction zones, and 

they contain substantially less water. The carbon and sulfur species are approximately equivalent to the water content (Nordlie, 1971; Gerlach and Nordlie, 1975a, b, c; 

Mathez, 1984). The predominant species are C02, H20, 

CO, S02, S2, and H2S, in order of abundance. Hydrogen 

and methane contents are negligible. 

Gases associated with ocean-island volcanism are released from magma chambers subaerially, as in Hawaii, or 

from the sea floor. Almost all gases released from midocean 

ridges, with the exception of those released on Iceland, are 

released from the sea floor. Structural traps containing 

gases from these sources have not been reported. 

Gases from magma chambers underlying midocean 

ridges are discharged through hydrothermal vents and may 

be mixed with gases produced during ultramafic- and 

mafic-rock hydrolysis. A later section in this report deals 

in greater detail with the origin of gases from midoceanridge hydrothermal vents. 

VAPOR-PHASE TRANSPORT 

Field observations provide overwhelming evidence 

that volatile transport from the mantle takes place primarily, if not entirely, through magma incursions into the crust, 

and that mantle gases derived from depressurized and 

cooling magmas release their gases into structural traps or 

the atmosphere. Within the crust, gaseous components can 

migrate considerable distances from their source, dissolved 

in and transported by aqueous fluids. The nature of the 

species transported depends very much on the oxidation 

state of the crustal environment. 

OXIDATION STATE OF THE LOWER CRUST 

The oxidation state in the lower continental crust appears to be similar to that in the subcontinental upper 

mantle. The presence of carbonate-bearing meionite scapolite in granulites of basaltic composition (Lovering and 

White, 1964, 1969; Edwards and others, 1979) suggests a 

higher oxidation state. The lower crust would also tend to 

become depleted in water during lower-crustal magmatism. With partial anatexis, . H20 would partition into the 

silicate melt, leaving residual fluids enriched in liquid C02 

(Pineau and others, 1981) and possibly associated with an 

immiscible brine component (Sisson and others, 1981 ). 

The lower continental crust appears unlikely to support the 

presence of a vapor phase containing significant concentrations of methane. Fluid inclusions in many minerals in 

granulites are commonly rich in C02 and N2 with rare 

CH4 (Touret, 1986), thus an oxidizing environment is indicated in the lower crust. Carbon dioxide inclusions in 

Archean granulites in southern India contain mantle-derived helium indicative of an oxidizing environment in the 

ancient upper mantle and lower crust (Dunai and others, 

1992). These and further data cited by Valley and Lamb 

( 1986) indicate that metamorphic rocks from the lower 

crust are oxidized and could not equilibrate with methanerich fluids. 

Calculations of the oxidation state of the lower continental crust using mineral assemblages are uncommon. 

Glassley (1982) estimates that the oxygen fugacity, determined by the biotite-muscovite-feldspar assemblage at 

T=700°C, P=700 MPa, would result in coexisting fluids 

consisting dominantly of C02 and H20. We therefore conclude that the lower crust, like the upper mantle, could act 

as a redox potential barrier to the migration of any reducing gases from the lower mantle. 

VAPOR-PHASE TRANSPORT FROM BASEMENT ROCKS 

INTO SEDIMENTARY BASINS 

Gases from deep sources could also migrate along 

pores and fractures from the upper mantle into continental 

and oceanic crust, without being transported in and exsolved from a melt. Small quantities of reducing gases 

such as methane, hydrogen, and carbon monoxide would 

probably be oxidized in the upper mantle to C02+H20 before reaching the lower crust. Below 800°C, any carbon 

monoxide would disproportionate into graphite+carbon dioxide. Graphite films observed in gneisses from the lower 

crust (for example, see Mareschal and others, 1992) might 

be a relic of carbon monoxide infiltration. 

The evidence for infiltration of methane or its precursor gases from the mantle is generally lacking. Gold 

( 1987) contended that the migration of mantle gases into 

the shallow crust is sufficiently rapid that chemical interactions between the invading gases and the mantle and 

crustal rocks do not occur. Green and others (1987) and 

Taylor and Green (1989) have also suggested that the persistent upward migration along the fracture zones in the 

lithosphere would eventually overwhelm locaHy oxidizing 

conditions and permit the accumulation of methane in 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 101 

continental crust. Unfortunately, there is no field evidence 

in support of such transport processes. Indeed, the evidence for any form of subsolidus degassing from the 

upper mantle is tenuous and conjectural. Estimates have 

yet to be made of rates of reactions between reduced gases 

and mantle or crustal rocks with a higher oxidation state. 

It is therefore impossible at this stage to confirm or deny 

the slow migration of reducing gases from the mantle 

without developing alternative lines of evidence. It would 

be of great scientific interest if researchers using current 

diagnostic methods in isotope chemistry could find a single case that unequivocally demonstrated the release of 

deep-mantle reducing gases. 

A key argument advanced by Gold (for example, see 

Gold, 1987; Gold and Held, 1987) for the abiogenic origin 

of oil and gas deposits is that methane from the mantle 

has migrated upward through rocks of the continental 

lithosphere and penetrated into shallow crustal oil and gas 

traps. Because this argument is critical to Gold's hypothesis, it is worth examining the evidence for vapor transport 

from the underlying crust into oil and gas reservoirs. 

In several natural-gas fields, as in the Panhandle and 

Hugoton fields of Texas and Kansas (Pierce and others, 

1964; Gold, 1987; Gold and Held, 1987), in Chinese gas 

fields (Xu and others, 1982 1990, 1991 ), in gas fields of 

Alberta (Hiyagon and Kennedy, 1992), and in the Four 

Comers Region of Arizona, Colorado, New Mexico, and 

Utah (Picard, 1960, 1962; Pohlmann, 1967), a strong correlation is observed between helium and nitrogen contents. 

These correlations are probably the result of mixing between gases from different sources and with different 

compositions. Although the correlation is commonly quite 

uniform within a given field and occasionally even extends to adjacent fields, the correlation coefficient can vary 

considerably. Usually, a field with a high helium content is 

also high in nitrogen, although the converse is not necessarily the case (Jenden and others, 1988b ). The helium and 

nitrogen concentrations in some of above-cited fields are 

high, with helium attaining more than 8 percent, and nitrogen more than 90 percent. 

Several lines of reasoning suggest that the helium and 

nitrogen originate either in sedimentary formations or in 

basement rocks at greater depths than the formations containing the oil or gas reservoir. Pierce and others ( 1964) 

noted that the quantities of helium and argon present in 

the Panhandle and Hugoton fields is so great that they 

could not have been derived from the uranium, thorium, 

and potassium in the reservoir host rocks. In United States 

gas fields, and in an undisclosed oil- and gas-producing 

region of southwest China, Tongish (1980) and Xu and 

others (1982), respectively, showed that both the helium 

and 40 Ar concentrations are linearly correlated with the nitrogen concentration. Although Xu and others (1982) considered that_ uranium associated with organic matter in the 

sediments could have caused the radiolytic decomposition 

of amine functional groups and thereby explain a heliumnitrogen correlation, this argument could not explain the 

linear correlation of nitrogen with 40 Ar. Furthermore, in 

conformity with comments by Pierce and others (1964) 

concerning the Panhandle and Hugoton fields, Xu and others (1982) argued that the accumulation of helium and 

40 Ar indicates an age far greater than that of the enclosing 

Permian sediments. Gold (1987) also concluded that, although some of the nitrogen in the Panhandle and Hugoton fields is derived from the enclosing sediments, this 

nitrogen could be readily distinguished from the nitrogen 

associated with the helium because the minimum nitrogen 

concentration for any given helium concentration defines a 

sharp boundary to the field of data points in a heliumversus-nitrogen plot. Tongish (1980), in a comprehensive 

survey of helium occurrences in the United States, investigated the relationship between helium, nitrogen, carbon dioxide, and argon in gas wells. As expected, he found a 

generally positive correlation between helium, nitrogen, 

and argon, but a negative correlation between helium and 

carbon dioxide. 

More direct evidence that some of the nitrogen (and 

accompanying helium) is derived from basement structures has been reported on several occasions. Pierce and 

others (1964) showed that the helium and nitrogen in the 

Texas Panhandle gas field appear to be discharging from 

deep-seated faults adjacent to the Amarillo Uplift. They 

concluded that the helium source, together with the natural-gas source beds, is located at depth in the Palo Duro 

Basin to the south. Jenden and others (1988b) cited Headlee (1962) and Beebe and Curtis (1968), who observed 

that the nitrogen content increases toward the basement in 

some gas-producing regions. Hiyagon and Kennedy (1992) 

also observed a similar phenomenon in Alberta gas fields. 

Maksimov and others (1976) argued in support of a deepseated origin for nitrogen gas accumulations underlying 

the impermeable Zechstein salt in the Rotliegende of Germany and Poland. The nitrogen concentration increases 

adjacent to tectonic zones or ancient lineaments. 

Dobbin (1935) and Picard ( 1962) noted that the helium content of gases increases with depth in the wells and 

with proximity to the underlying Precambrian crystalline 

basement rocks. This evidence suggests the helium-rich 

gases are derived from the basement rocks and migrate 

upward into the overlying sedimentary rocks. 

Evidence that mantle volatiles have penetrated sedimentary basins is provided by 3He/4He ratios in natural 

gases drawn from structural traps. In many cases, these 

ratios indicate very clearly that helium with a mantle signature found in basins that are associated with basaltic magmatism, the younger the basin and the more recent the 

magmatism, the stronger the mantle signature. 3He/4He signatures are especially strong in gas accumulations that have 

formed in and adjacent to continental rifts, as in the Rhine 

Graben (Hooker and others, 1985; Oxburgh and others 
102 THE FUTURE OF ENERGY GASES 

1986; Griesshaber and others, 1992), adjacent to the Dead 

Sea in Israel (Bosch and others, 1989), and associated with 

the Cathaysian rift zone in eastern China (Xu and others, 

1990, 1991). In older basins, where volcanic activity took 

place early in the history of basinal subsidence, the mantle 

helium signature is weaker. In many basins where there is 

no magmatic activity, there is also no mantle-derived helium The association of mantle helium signatures with mafic 

magmatism led Ox burgh and others ( 1986) to speculate that 

the only mechanism by which gas volatile transfer from the 

mantle could occur is through magma transport. However, 

recent studies, especially those by Hiyagon and Kennedy 

( 1992) and Kennedy and others (1992), indicate that some 

basins with no evidence of basaltic magmatism nevertheless contain helium with elevated concentrations of 3He. In 

the Alberta gas fields, this anomalous helium is not associated with the nitrogen and helium from the basement, but is 

found higher in the sedimentary sequence. The helium accompanying the nitrogen is entirely radiogenic. The origin 

of the anomalous helium is currently unknown, but its location in the field shows that it cannot have been derived 

directly from the mantle by way of the lower crust. 

The preceding evidence indicates that the natural gas 

in sedimentary basins could not have been derived from 

the mantle by advective transport through the underlying 

basement rocks. Because the gases emerging from the 

basement contain no 3

He mantle signature and have mixed 

with the natural gas, the natural gas must be derived independently from source rocks in the sedimentary basin. 

Because evidence supports the release of C02 from the 

upper mantle through mantle magmatism, it is expected 

that mantle-derived C02 in sedimentary basins would contain mantle-derived helium. The co2PHe ratio in the mantle gases has been determined to be about 2x 109 (Marty and 

Jambon, 1987; see also Wainger, 1988; Marty, 1989). The 

3He concentration in sedimentary basins can be correlated 

in favorable circumstances with the quantity of mantle C02 

carrier gas, particularly if many samples are taken that reveal mixing of C02 with differing 613C values (Poreda and 

others, 1986; Taylor, 1986; Matthews and others, 1987; 

O'Nions and Oxburgh, 1988; Griesshaber and others, 

1992). It is doubtful, however, that 613C values in C02 

alone would unambiguously reveal a mantle signature in oil 

or gas fields, because of the overwhelming contribution of 

C02 from the decay of kerogen and other organic material 

trapped in the sediments during deposition, and the fixation 

of C02 in secondary carbonates. It would be far more difficult to identify methane from the mantle in a sedimentary 

basin, given the expected very low concentrations of this 

gas in a vapor phase from the mantle. Furthermore, thermogenic methane would swamp any mantle 13c or D signature from mantle-derived methane (see Jenden and 

others, this volume). Hence the mantle CH4PHe ratio could 

be used only to set an upper limit to the concentration of 

mantle methane in a sedimentary basin. 

Rare-gas isotopic signatures in sedimentary basins provide no evidence that mantle helium (or other rare gases) 

were carried by liquid or vapor hydrocarbons, although 

there is strong evidence that mixing between atmospheric 

crustal and mantle components occurred in ground water 

prior to gas-phase separation and fractionation (Ballentine, 

1991 ). No correlation exists between the mantle helium signature and the quantity of gas or petroleum present in an oil 

or gas field. Furthermore, carbon isotopic data and mass 

spectrographic data of en distribution in associated oils in 

oil fields suggest biogenic or thermogenic origins (Whiticar, 1990), and potential sedimentary source rocks can usually be identified. The weight of evidence is therefore 

against a mantle origin for hydrocarbons in sedimentary 

basins whether or not a mantle helium signature is present. 

The ratios of CH4PHe in magmatic gases range from 

approximately 106 to possibly as high as 108, depending on 

the redox potential of the magma and the degassing temperature (Charlou and others, 1991). Some CO in the magma 

could also be eventually converted with H2 to CH4 by the 

subsolidus Fischer-Tropsch reaction (see section "Ocean 

Spreading Centers," below). Given the assumption that 

vapor-component transport into the crust occurs primarily 

through magmatism rather than advective vapor-phase flow, 

this ratio can be used to calculate the approximate concentration of mantle-derived methane in natural-gas fields. 

Two examples from the literature suffice to show that even 

when 3He/4He ratios are very high, the concentration of 

magmatic, that is, mantle-derived, methane is very small. 

The first example is the Green Tuffs region of northem Japan, (Sakata and others, 1986; 1989; Wakita and 

others, 1990). The Green Tuff rocks are Miocene and 

Pleistocene sediments interstratified with volcaniclastic 

rocks, breccias, agglomerates, and. lavas accumulated in 

backarc basins in and adjacent to the Japan Sea. The tuffaceous rocks have been extensively altered by diagenetic 

and hydrothermal activity. Some of the associated organicrich sedimentary rocks in the Green Tuff formations are 

excellent, thermally mature petroleum source rocks. Natural gas, primarily methane, has accumulated in the porous 

volcaniclastic reservoirs. 3He/4He ratios in these gases are 

very high, as would be expected, ranging from 0.10 to 6. 7 

RA (Wakita and others, 1990). Sakata and others (1989) 

calculated the concentration of mantle-derived methane 

using a CH4/

3

He ratio of I x 106 and assuming that the 

magmatic 3He/4He ratio is >10.9xl0-6. They considered 

the magmatic CH4 fraction in the natural gas to be si0-3. 

Even allowing for CH4PHe of 108, the concentration of 

mantle-derived methane does not exceed 10 percent. Most 

of the gases were mixtures containing far less than the calculated upper limit of magmatic methane. 

The second example is gas fields of the Sacramento 

Valley, California (Poreda and others, 1986; Jenden and 

others, 1988a), where a major accumulation of Mesozoic 

and late Tertiary sediments, up to 5,000 m thick, formed in 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 103 

a forearc basin. Dacitic magmas intruded these sediments 

in the Pliocene and Pleistocene time. Except in two instances, the intrusions failed to break through to the surface, but they did create domal structures in the overlying 

sediments, into which thermogenic gas migrated. Not all 

of the gas fields, however, have obvious or inferred associations with the intrusives. 3He/4He ratios in most of the 

fields are high, ranging from 0.11 to 2.75 RA, indicating 

that between I and 34 percent of the helium is derived 

from the mantle. The CH4PHe ratios range from 2x 109 to 

1012, (Poreda and others, 1986). Hence the magmatic 

methane content is less than 0.05 and 5 percent, depending 

on the presumed 3He/4He ratios. 

Similar arguments can be applied to gas fields in other 

areas. In all cases, the quantity of magmatic or mantlederived methane is very small. Thus the concentration of 

mantle methane in natural-gas fields is inconsequential. It 

should be noted in passing that Sakata and others (1986, 

1989) concluded that the abiogenic methane content in 

Green Tuff gases is considerably less than 0.1 percent. In 

contrast, Wakita and others (1990) assumed that magmatic 

C02 is reduced to methane during hydrothermal diagenesis and alteration of the Green Tuff rocks, a plausible 

mechanism for crustal generation of. abiogenic methane 

from mantle-derived igneous rocks. 

ABIOGENIC HYDROGEN AND 

METHANE FORMATION IN THE CRUST 

Abiogenic hydrogen and methane are produced in the 

Earth's crust through a variety of inorganic processes, of 

which hydrolysis is the most important. Because hydrolysis produces hydrogen in the absence of carbon, we consider hydrogen formation first. Afterwards, we consider 

the thermodynamic relationships between hydrogen and 

methane in the natural environment, and the conditions 

under which methane would form in preference to hydrogen in the crust. Finally, we examine field occurrences of 

these gases. 

HYDROGEN GENERATION 

There are at least six possible processes in which 

crustal hydrogen is generated: (l) reaction between dissolved gases in the system C-H-0-S in magmas, especially 

in those with basaltic affinities; (2) decomposition of 

methane to carbon (graphite) and hydrogen at T~600°C; 

(3) reaction between C02, H20, and CH4 at elevated temperatures in vapors; (4) nidiolysis of water by radioactive 

isotopes of uranium, thorium, and their daughters, and potassium; (5) cataclasis of silicates under stress in the presence of water; and (6) hydrolysis by ferrous minerals in 

mafic and ultramafic rocks. 

Gas-phase equilibrium in magmas-process (1 ), has 

been discussed in a preceding section. Hydrogen produced 

through this process is a minor component and has no economic significance. Processes (2) and (3), represented by 

reactions I6 and 1, respectively, are kinetically favored at 

elevated temperatures and relatively low pressures in the 

Earth's crust. In figure 5, the reaction 

(16) 

shifts to the right near 600°C, suggesting that local reducing conditions generated, for example under hydrothermal 

conditions near magma chambers at oceanic spreading centers, could liberate hydrogen and leave residual graphite. 

Process (3), the well-known Fischer-Tropsch reaction, 

reaction I, can generate methane below 600°C depending 

on the fugacity of hydrogen. How fast this reaction proceeds in the natural environment and how it is affected by 

natural catalysts is currently unknown. We will assume as 

a working hypothesis that in favorable environments, equilibrium between the participating species is achieved, but 

further study of this process under natural conditions is 

needed. 

WATER RADIOLYSIS 

Process (4) is of particular interest because field evidence suggests it could be significant in facilitating the formation and maturation of oil and natural gas. The radiolysis 

of water proceeds mainly through the following reactions: 

(31) 

20H·=HOOH (32) 

(33) 

(34) 

where "·" denotes a free radical. 

The source of the radioactivity is primarily uranium 

and thorium and their daughters. According to Dubessy 

and others (1988), the dose of absorbed y rays is only 0.02 

times the dose of absorbed a particles in a given time. 

Therefore the primary cause of water radiolysis is a particle radiation. Also, according to Spinks and Woods ( I976) 

(cited in Dubessy and others, 1988), a single 1-megaelectronvolt (MeV) a-particle can ionize 105 molecules as it 

loses energy. 

The intermediate oxidation products of radiolysis are 

quite reactive in contrast to hydrogen, which, in shallow 

crustal environments, is almost inert. Thus, HOOH would 

oxidize other species-for example, Hs- to sulfate, or Fen 

to Feiii in surrounding iron-bearing minerals--or form 
104 THE FUTURE OF ENERGY GASES 

unstable organic peroxides in organic-rich sediments. If supersaturation with respect to anhydrite or celestite occurred, 

these minerals would precipitate in the vicinity. 

Voytov and others (1967) studied the distribution of 

gaseous species in formation waters in Triassic and Permian rocks penetrated by a 6,000-m-deep well in an interdomal trough of the Caspian depression. They found 

that dissolved gases were predominantly C02 and H2. 

But in intervals characterized by sharp increases of undersaturated C2-C4 alkenes (up to 15 percent of total hydrocarbon gases), there was a clear deficit of hydrogen. 

Conversely, in the intervals with excess free hydrogen, 

the alkene concentration fell by several orders of magnitude. A correlation between the concentrations of the C2-

C6 alkenes and their saturated homologs was also found. 

The explanation of these observations is that hydrogen 

participates in the saturation of alkene intermediates during thermogenesis. Voytov and others (1967) attributed 

the origin of the hydrogen to hydrolysis due to radiation 

from nuclear transformations, although no supporting evidence was given. 

The foregoing observations are consistent with the 

conclusions of Eisma and Jurg (1969) and Weres and others (1988) that the low-temperature hydrous pyrolysis of 

organic matter in sediments may be explained in terms of 

free-radical chain reactions in which heavy hydrocarbons 

crack to produce free radicals. These reactions permit radiolytic hydrogen free radicals to saturate alkene intermediates and form light alkanes. 

Vovk (1987) contended that water radiolysis is a contributing factor to the increasing salinity of ground waters 

with depth, as is typically observed in igneous and metamorphic rocks of shield areas (for example, see Frape and 

others, 1984; Fritz and Frape, 1987; and Nurmi and others, 

1988). The release of hydrogen is coupled with concurrent 

oxidation of Fe11 in host rock minerals and reduced species 

in ground water (for example, HS- and NH4 +). The hydrogen eventually escapes to the Earth's surface or is trapped 

in impermeable structures in overlying sedimentary strata, 

where it is available to react with and saturate hydrocarbons. Implicit in this process is the assumption that hydrogen is relatively unreactive in comparison with oxygen (or 

hydrogen peroxide). One would also expect a qualitative if 

not quantitative relation between 4He or 40 Ar and hydrogen. A crude correlation does exist in some cases, such as 

in the Gravberg deep hole in Sweden. Also relevant to this 

issue is the close correlation of He with nitrogen observed 

in several sedimentary basins, as noted earlier. 

Vovk (1987) conducted experiments in which he irradiated various water-saturated rocks and extrapolated the 

resulting observations to geologic time scales. When using 

conservative assumptions, he showed that very high salinities could be achieved in 3.5x 109 years. This figure is consistent with estimates by Dubessy and others (1988 ). 

Radiolysis probably contributes only moderately to the 

concentration of dissolved salts. Other processes such as 

secondary alteration, the breakdown of fluid inclusions, 

and desorption of chloride salts from silicate minerals 

(Neil and Apps, 1981) could also contribute. 

CATACLASIS 

Hydrolysis can be induced during the fracturing of silicate minerals (Sugisaki and others, 1983): 

=Si-0-Si= = =Si·+·O-Si= 

=Si-O·+H20 = =Si-OH+OH· 

2H·=H2 

20H·=HOOH 

(35) 

(36) 

(37) 

(38) 

(32) 

Silicate cataclasis in rocks occurs wherever host rocks 

are subject to strain in excess of that which permits stress 

relief through stress corrosion or intracrystalline elastic or 

plastic deformation. Cataclastic deformation is both pressure and temperature dependent and is normally encountered at temperatures and pressures characteristic of the 

upper 10 km of the Earth's crust, that is, T=O to 300°C 

and P=O to 350 MPa. Although cataclasis is normally associated with faulting, it occurs in all brittle rocks, where 

it is manifested by extensive joints and microfractures. 

Sugisaki and others (1983) demonstrated in the laboratory 

that the grinding of silicates under water releases hydrogen. Giardini and others ( 1976) stressed circular rock discs 

of granite and gneiss at progressively higher pressures 

until rock failure, while measuring the gases evolved. 

They showed that both the total volume of gases released 

and the percentage of hydrogen (and methane) increased 

dramatically with departure from linearity of the stressstrain curve before rock failure around 470 to 480 MPa. 

About 0.5 and 1.08 cm3 of gas at STP per gram of granite 

and gneiss, respectively, was released between 400 MPa 

and failure. These data, though limited in scope, provide 

some qualitative guidance as to the potential magnitude of 

the phenomenon in nature. 

The quantity and rate of hydrogen generation by cataclasis in sedimentary basins during compaction and subsidence has not been investigated, but is probably small. 

Hydrogen emissions along faults are quite common (Sugisaki and others, 1983; Sato and others, 1985, 1986), but it 

has not been demonstrated that such emissions are due to 

cataclasis. It should be mentioned that drilling is itself cataclastic and liberates hydrogen both from comminution of 

the rock penetrated and through wear and tear of the drill 

bit (MacDonald, 1988). 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 105 

HYDROLYSIS BY FERROUS MINERALS 

With falling temperature, Feiii becomes progressively 

more stable with respect to Fell at lower oxygen fugacities 

(see line labeled QFM on fig. 5). The oxidation of Fell 

must be coupled with the reduction of another species 

(such as H20 to H2, C02 to C, or C to CH4.) 

There are two broad classes of reactions in which Febearing minerals participate and hydrogen and hydrocarbons are generated: (I) closed-system reactions in which 

the local chemical system bulk composition is fixed and 

there is no loss or gain of chemical components, and (2) 

open-system reactions in which chemical components are 

exchanged with the surrounding environment. Almost all 

natural systems are to a certain extent leaky, but it is convenient to adopt this classification as a basis for comparing field examples. 

Closed systems are represented by crystallizing mafic 

magma bodies in which a residual exsolved aqueous or 

COz-CO-rich phase reacts with the iron-bearing minerals 

at temperatures both above and below the solidus. The 

temperature range represented by both super- and subsolidus reactions extends from over 1 ,000°C down to ambient 

temperature. Deuteric reactions refer specifically to those 

reactions that take place within an igneous rock during 

cooling below the solidus. They are often constrained by 

slow reaction rates, especially below 250°C, by the rapidity with which a cooling igneous body loses heat to its surroundings, and by exhaustion of accessible reactants such 

as water. 

A corollary is the process of prograde metamorphism 

of sedimentary or igneous rocks. During this process, minerals dehydrate and liberate water, carbonates react with 

silica and release carbon dioxide, and minerals containing 

Felli are reduced by hydrogen, methane, or ammonia. The 

process can be reversed during retrograde metamorphism. 

The relevant open systems are those in which water penetrates mafic and ultramafic rock masses in various crustal 

settings. This class has a greater potential for generating 

substantial volumes of hydrogen and methane. 

Essentially, all mafic and ultramafic rocks in the crust 

are derived from the upper mantle, either as a result of 

partial fusion, or through tectonic processes resulting in 

physical translocation of a depleted mantle. Such rocks 

contain between 5 and 15 weight percent of the FeO and 

minor concentrations of Fe20 3 in olivine and pyroxene. 

Referring to figure 5, it can be seen that the QFM buffer 

intersects the water decomposition curve at 25°C. 

Summing both reactions leads to the following: 

In the absence of carbon, hydrogen is generated through 

the decomposition of fayalite, and the creation of quartz 

and magnetite. 

In a natural system, a basalt or peridotite containing 

olivine and pyroxene will alter hydrothermally, and the 

FeO component will react at somewhat higher temperatures than would fayalite at the QFM buffer. Evidence 

suggests that greenschist formation occurs at 350 to 400°C 

(Ernst, 1990). Peridotites alter at temperatures ranging 

from less than 100°C (Wenner and Taylor, 1971) to an 

upper limit between 500 and 600°C, above which olivine 

is stable (Bowen and Tuttle, 1949; Scarfe and Wyllie, 

1967). Serpentinization of ultramafic rocks and propylitization of mafic rocks will induce strongly reducing conditions in which water is reduced to hydrogen as Fen is 

oxidized to Fem. There is ample field evidence that hydrolysis by Fell is the principal mechanism through which 

energy gases are generated abiotically in the Earth's crust. 

RELATIONSHIP OF METHANE TO HYDROGEN 

Hydrolytic hydrogen can be consumed through reactions with other components. Of these, carbon is particularly relevant in regions where hydrogen is unstable with 

respect to graphite or methane, that is, where reactions 1 

and 16 would shift to the left, hydrogen would be consumed and methane or methane+water would be produced. 

As noted previously, hydrogen is also consumed during 

the thermogenesis of organic matter. Experimental evidence also shows that hydrocarbons can be generated during grinding and cataclasis (Melchanov, 1967). Where 

mafic minerals induce hydrolysis, similar processes of reduction involving C02, graphite, and methane operate. Referring again to figure 5, we see that the QFM buffer 

intersects the graphite-C02 and CH4-graphite+H20(vapor) 

boundaries at about 250°C, where carbon dioxide could be 

reduced to graphite, and graphite to methane in the presence of water, thus: 

In figure 6 is shown the calculated log fcH/fH2 and log 

fcH4 plotted as a function of temperature between 0 and 

300°C for several hypothetical secondary mineral assemblages that might form during the hydrothermal alteration 

of mafic and ultramafic rocks. These assemblages represent 

the IM, QFM, and HM redox buffers with the addition of 

carbon, either as graphite or as calcite. It is clear that the 

region between the QFM-calcite and 1M-graphite assemblages is where most of the observed occurrences of abiogenic hydrogen and methane occurrences fall. 

Under relatively oxidizing crustal conditions, defined 

by the QFM-calcite assemblage, hydrogen predominates 

over methane by between seven and ten orders of magnitude, but the hydrogen partial pressure is low, ranging 
106 THE FUTURE OF ENERGY GASES 

+20~---------------------------, 

--------------- +10 

+16 ---- +5 

+ 12 IM - graphite 

::r: "' 

~ or--------------------------~~ -10 

::r: 

-:::: -4 

CJJ 

0 

-

-12 

-16 

-20 , 

, 

, 

, 

---

QFM -calcite 

-24 ,' 

0 

, 

, 

100 200 

Temperature, in degrees Celsius 

-15 

-20 

-25 

-30 

-35 

300 

..,. 

::r: 

u ...,_, 

CJJ 

.::: 

Figure 6. Log fcH4/fH (solid lines) and log fcH4 (dashed 

lines) as functions of tefnperature for various redox buffers 

with either calcite or graphite. HM, hematite-magnetite; 

IM, iron-magnetite; QFM, fayalite + quartz-magnetite. 

from 10-10·

3 to 10-3·

9 MPa between 0 and 300°C. Thus, 

typical water-saturated granitic rocks would not be expected to yield methane, and only minor quantities of hydrogen would be present. 

The 1M-graphite assemblage represents extremely reducing conditions experienced in hydrothermally altered 

ultramafic rocks. In the presence of liquid water, very high 

CH4 and H2 partial pressures would be generated. Overburden pressures would be exceeded, and the gases would 

be released during rock failure. In nature, such high gas 

pressures would not be sustainable and would, in any case, 

probably be limited by the availability of water. 

FIELD EVIDENCE FOR HYDROLOYSIS BY 

FERROUS MINERALS 

CLOSED SYSTEMS 

Drill holes penetrating mafic igneous rocks and some 

metamorphic rocks sometimes encounter gas pockets or 

fractures yielding methane and other heavier hydrocarbons. 

Such rocks show little evidence of hydrothermal alteration 

or metasomatism. Field evidence suggests that the reactions 

leading to the generation of methane occurred within the 

rock in the absence of meteoric water. In this section we 

discuss the environments in these rocks that lead to the 

observed occurrences of abiogenic hydrocarbons. 

AUTOGENOUS GENERATION OF METHANE DURING THE 

COOLING OF AGPAITIC MAGMAS 

Several large intrusive complexes of agpaitic alkaline 

rocks contain natural gas in fluid inclusions in the rockforming minerals, and a variety of bitumens and asphaltenes in pores and fractures. Petersil' ye (1962) estimated 

that the closed pores alone in one such complex, the Khibiny massif of the Kola Peninsula in Russia, contain 7xl08 

m3 of hydrocarbon gases, predominantly .methane, whereas the open pores and fractures contain two to three times 

more mass in solid hydrocarbons. The methane content in 

these rocks ranges from 8 to 283 cm3 per kilogram of rock 

(cm3 kg- 1

) and averages 28.5 cm3 kg- 1. Agpaitic intrusions are relatively rare, however, and therefore the total 

amount of recoverable hydrocarbons is insignificant when 

compared with that of thermogenic gas reservoirs. Although they have very limited economic potential, these 

igneous rocks contain enough organic matter to raise questions regarding their genesis. 

Several alternative theories have been proposed to account for the origin of the hydrocarbons (for example, see 

discussions by Petersil'ye, 1962; Gol'dberg and Chernikov, 

1969; Gold, 1987). Isotopic and fluid-inclusion studies, 

however, overwhelmingly support the interpretation that the 

hydrocarbons in the fluid inclusions evolved during crystallization of the magma and during subsequent deuteric 

alteration (Galimov and Petersil'ye, 1967; Petersil'ye and 

Pripachkin, 1979; Konnerup-Madsen and others, 1979; 

Konnerup-Madsen and Rose-Hansen, 1982; and Welhan, 

1987). No significant exchange of components with the 

country rocks is anywhere indicated in agpaitic intrusions 

of the Kola Peninsula. Yet the penetration of agpaitic intrusions by thermogenic hydrocarbons from adjacent sediments 

undoubtedly occurs, and cannot be discounted in all instances (for example, see Gol'dberg and Chernikov, 1969). 

The crystallization temperatures for agpaitic melts 

range from about 1, 1 00°C to below 450°C depending 

upon the volatile concentration. Petrologic and thermodynamic arguments, supported by melt-inclusion homogenization temperatures and field observations, show that the 

initial volatile content of these magmas must be quite low 

(Kogarko and Romanchev, 1977; Kogarko, 1987). Konnerup-Madsen and Rose-Hansen (1982) estimated that the 

C02 content of the primary magma at llimaussaq, Greenland, could have been no more than 0.2 weight percent, a 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 107 

concentration that would have saturated the melt at total 

pressures of 200 to 300 MPa. Kogarko and Romanchev 

( 1977) and Kogarko (1987) believe that the partial pressure of H20 is only about 10 to 30 MPa in such magmas, 

and that the water content in hyperalkaline melts approaches 1.5 weight percent, (Kogarko and Romanchev, 

1977). The initial solidus must therefore be near the upper 

temperature limit for anhydrous melts. 

Some agpaitic· melts initially crystallize anhydrous 

minerals such as nepheline and potash feldspar, causing a 

progressive concentration of volatiles in the residual 

magma and a depression of the final solidus temperature. 

This depression of the solidus temperature permits a 

reequilibration of dissolved volatiles with precipitated 

phases, which cannot occur to the same extent in magmas 

with higher solidification temperatures. Of particular relevance is the inte~action between Fen -bearing phases and 

the H20 and C02 components; in such interactions, for 

example, magnetite could oxidize to maghemite: 

After crystallization of the magma, iron-bearing minerals undoubtedly continue to react with residual fluids to 

form more methane and hydrogen. In hornblendes, ferrous 

iron might oxidize to ferric iron while the hydroxyl groups 

lose hydrogen. Pyroxenes are probably unaffected. 

The changing vapor-phase composition and hydrocarbon formation during the cooling history of an agpaitic intrusion is recorded in fluid inclusions and vein fillings. An 

abundant literature details petrology and fluid-inclusion 

history in several of these intrusions, for example, at Ilimaussaq (Galimov and Petersil'ye, 1967; Petersil'ye and 

Sorensen, 1970; Petersil'ye and Pripachkin, 1979; Konnerup-Madsen and others, 1979, 1988; Konnerup-Madsen 

and Rose-Hansen, 1982), at Khibiny (Petersil'ye, 1962; 

Galimov and Petersil'ye, 1967; Kravtsov and others, 1967; 

Zezin and Sokolova, 1967; Petersil'ye and Pripachkin, 

1979; Ikorskiy and Shugurova, 1975), and at Lovozero, 

Russia (Galimov and Petersil'ye, 1967; Kogarko and Romanchev, 1977). 

Several generations of fluid inclusions are found in 

agpaitic intrusions (Kogarko and Romanchev, 1977; Konnerup-Madsen and others, 1979; Konnerup-Madsen and 

Rose-Hansen, 1982). At Ilimaussaq, primary fluid inclusions in nepheline, the first mineral to crystallize from the 

melt (Kogarko and Romanchev, 1977), contain more than 

60 percent C02, nearly 30 percent nitrogen, and nearly 5 

percent CO (Sobolev and others, 1970). Similar primary 

fluid inclusions containing 88 to 54 percent C02 were also 

observed elsewhere in nepheline by Sobolev and others 

(1974). These inclusions were entrapped at a temperature 

of approximately 1,000°C. According to Konnerup-Madsen and others (1979), a highly saline aqueous phase was 

also entrapped as primary inclusions in minerals between 

about 500 and 1 ,000°C. Postdating the brine inclusions is 

a more abundant third stage of gas-phase inclusions, 

which are found in healed fractures of the rock-forming 

minerals. The sequence of fluid-inclusion types indicates 

successive supersaturation of the magma during crystallization with a COTrich gas, a saline brine, and a methanerich gas. 

Konnerup-Madsen and others (1979) determined that 

the temperature range of hydrocarbon fluid-inclusion entrapment was between 800 and 500°C at pressures between 100 and 140 MPa. The temperature range is 

consistent with that required for complete crystallization 

(Larsen, 1976). But independent thermodynamic calculations by Gerlach (1980) on Nyiragongo lava gases and by 

Kogarko (1987) suggest that these inclusions must have 

formed below about 600°C to account for the high methane content. 

According to Kogarko and Romanchev ( 1977), gas and 

gas-liquid inclusions in nepheline and apatite from the Lovozero and Khibiny intrusions were secondary and formed 

between 200 and 400°C. At Ilimaussaq, a few other inclusions containing aqueous liquid and gas, and with a salinity 

less than 10 percent, homogenized at temperatures as low 

as 140°C. The presence of these low-temperature fluid inclusions suggests that a residual aqueous phase might have 

been expelled from this igneous complex upon complete 

crystallization. It is evident, therefore, that the formation of 

hydrocarbons in agpaitic intrusions takes place over a wide 

range of temperatures and conditions, from 600°C under 

presolidification conditions to as low as 200°C under deuteric conditions. 

Petersil'ye (1962) found variations in the gas content 

of different igneous rocks of the Khibiny massif, which 

correlated with variations in their aluminum content. He 

attributed a catalytic effect to the aluminum in synthesizing the hydrocarbon gas. He also noted variations in the 

hydrocarbon content in individual minerals from pegmatoids in the massif. Konnerup-Madsen and others (1979) 

also found a variation in the total gas content of different 

minerals in naujaite from_Ilimaussaq. In the latter case, the 

concentration decreased progressively according to the sequence of crystallization and ranged from approximately 

1,000 cm3 kg-1 in sodalite to approximately 170 cm3 kg-! 

in arfvedsonite. The gas composition was mainly CH4, but 

significant amounts of C2H6 (5-18 percent), H2 (4-34 

percent), and nitrogen ( 4-25 percent) were also present. 

The concentration of helium, probably of radiogenic 

origin, ranged widely, from <0.01 to 2.8 percent. Very 

minor amounts of other hydrocarbons and C02 were also 

present. No clearly discernible trend in gas-phase compositions can be correlated with the crystallization sequence. 

Noteworthy, however, were the relatively high H2 (16-34 

percent), C2H6 (13-8 percent) contents and relatively low 

CH4 (43-49 percent) and N2 (4-8 percent) contents in 

eudialyte, a mineral known to host uranium and thorium. 
108 THE FUTURE OF ENERGY GASES 

The distribution may be due to radiolysis of the trapped 

gas. 

Although Konnerup-Madsen and others (1979) observed some of the gaseous fluid inclusions in contact with 

secondary exsolved microcrysts of aegirine (NaFeSi20 6) 

in nepheline, fluid inclusions in sodalite and eudialyte are 

not in contact with iron-bearing minerals. Furthermore, 

Konnerup-Madsen and Rose-Hansen (1982) showed that 

regardless of the present fluid composition, the molar H:C 

ratio in all fluid inclusions is relatively uniform at about 

20:80, indicating that the initial hydrocarbon gas was nearly pure methane. Therefore the gaseous hydrocarbon inclusions may have remained closed, but reequilibration at 

lower temperatures was facilitated by radioactivity or Fe11 

catalysis in arfvedsonite. 

Most of the analyzed hydrogen probably formed naturally. It is doubtful that much hydrogen was produced 

through grinding the minerals with steel balls to release 

the gases from fluid inclusions. Otherwise it would be difficult to explain the relative uniformity of the C:H ratio 

observed in the gaseous fluid hydrocarbons. Petersil'ye 

(1962) believed that the source of hydrogen in methanerich gases in the Khibiny massif is due to reduction by 

Fen in ferrous minerals, in accordance with Gerlach 

(1980). Kravtsov and others ( 1967), however, maintained 

that the hydrogen is the consequence of radiation-induced 

hydrolysis. Because agpaitic rocks often contain elevated 

concentrations of uranium and thorium, radiolysis may be 

a contributing factor, especially in the polymerizarion of 

hydrocarbons in veins and open pores and in the formation 

of bitumen and asphaltene. 

A fully integrated study in which all aspects of the 

mineralogy and geochemistry of agpaitic rocks is evaluated 

has yet to be made. It is therefore not possible to weigh the 

relative contributions of Fen hydrolysis and radiolysis in 

the evolution of the gas-phase composition during cooling, 

or the importance of catalysts in achieving thermodynamic 

equilibrium. Furthermore, the original water content of the 

parent magmas is not known with certainty, and there are 

no reports of water contents in the gaseous inclusions. 

The most likely scenario is that consumption of H20 

by reaction 42 and precipitation of hydrous minerals leads 

to undersaturation with respect to the brine phase. This undersaturation is followed by a shift in volatile content of 

the magma as CH4 forms at the expense of C02 and H20. 

The shift raises the·vapor immiscibility curve until it intersects the solidus curve of the residual magma, and causes 

the exsolution of a vapor-rich phase in the melt. 

COOLING OF LAYERED MAFIC INTRUSIONS 

Large layered intrusions such as the Bushveld complex (South Africa), the Musk Ox (Northwest Territories, 

Canada), the Skaergaard (Greenland), and the Stillwater 

(Montana, United States) form through the invasion of 

very large quantities of basaltic magma into the continental crust. The intrusions are usually sill-like in configuration, although funnel-shaped and dike forms also occur. 

They presumably form during early stages of continental 

rifting and are sometimes found on continental margins. 

When rifting fails to form an ocean, the layered intrusions 

are left embedded in the continental crust. 

Most layered intrusions contain graphite. Some of this 

graphite appears to be the result of deuteric alterations or 

metasomatism, although some could be primary (Mathez 

and others, 1989). In those intrusions in which mafic minerals, particularly olivine, have been serpentinized, the graphite is secondary (Pasteris, 1988). During mining to recover 

platinum-group metals, high-pressure gas emanations are 

encountered, which contain methane and hydrogen or hydrogen sulfide and hydrogen gas, especially in areas containing so-called potholes (Elliot and others, 1982). 

"Potholes" are breaks in the otherwise uniform layers within the intrusion and are found in platinum-producing horizons in the Bushveld and Stillwater complexes (for 

example, see Elliot and others, 1982; BaUhaus, 1988). 

Graphite appears to be ubiquitously correlated with these 

potholes and is clearly related to their formation. 

Also of relevance are the platiniferous dunite pipes: 

the Onverwacht, Mooihoek, and Driekop in the eastern 

Bushveld. These pipes contained relatively high concentrations of platinum-group metals and were mined out early 

in the development of platinum resources of the Bushveld. 

The orebody in the Driekop pipe was 18 to 25 m across 

and was mined to a depth of 200 m. The alteration zone 

around the orebody, however, extended into the intrusion 

300 m farther. These pipes also contained graphite, which 

precipitated along pipe fractures (Stumpe! and Rucklidge, 

1982; Schiffries, 1982). 

According to Schiffries, the Driekop pipe formed 

through dissolution of plagioclase, replacement of pyroxene by olivine with release of Si02, and iron enrichment 

of olivine with respect to the unaltered host rocks. Residual plagioclase in the margins of the pipe was also enriched 

in calcium (Schiffries, 1982). Dissolution of plagioclase 

and replacement of pyroxene with olivine resulted in a 

substantial volume reduction leading to downwarping of 

the layering toward the core and eventual collapse and 

breakup of the rhythmic layering within the core of the 

pipe (Schiffries, 1982). 

Before discussing the proposed origin of the pipes and 

potholes and their associated methane and hydrogen, consideration must be given to vapor-phase equilibria during 

the crystallization of large mafic intrusions. This subject 

has been investigated by Mathez and others (1989), particularly in relation to the Bushveld and Stillwater complexes. Mathez and others (1989) were confronted with several 

ill-defined parameters in their estimation of the vaporphase composition and the oxidation state of the magma. 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 109 

On the basis of evidence that primary graphite precipitated 

from the magma during cooling and circumstantial evidence that the chlorine content of the Bushveld magmas 

was relatively high, they arbitrarily assumed that the HCI 

component in a saturating vapor phase was 10 atomic percent. They also fixed log f 02 equal to the log of the nickel-nickel oxide (NNO) buffer minus 2.8 (=log QFM-2.1) 

on the assumption that graphite began crystallizing from 

the Bushveld magma at 1,050°C and 400 MPa. To simplify their evaluation, they also discounted the impact of sulfur species. 

Although Mathez and others' (1989) assumptions will 

undoubtedly require modification as further research reveals new data, particularly in relation to the magma's chlorine content and its saturation state with respect to a vapor 

phase, they reached some striking conclusions, which could 

be relevant to pipe and pothole formation. They found that 

the dominant species in the magma at graphite saturation 

were C02, HCl, and CO. With cooling, the C02 content 

decreased rapidly and the H20 and CH3Cl (chloromethane) 

contents rose. At 750°C, H20 and CH3Cl predominated 

with minor HCl and CH4. The formation of CH3Cl inhibits 

the formation of H20, CH4, and H2, which would otherwise form in the absence of chlorine. 

The formation of chloromethane in such environments 

needs confirmation, but it should be noted that Afanas'yev 

and others (1972) identified chloroform in the Beden pluton in Russia. It would also be interesting to compare 

these findings with the contents of vapor components in 

alkaline magmatic systems as described in the preceding 

section. Presumably the H20 content is less in alkaline 

magmatic systems, and the Cl component is present as 

NaCl or KCI, both of which have lower vapor pressures. 

Hence, the chloride component tends to remain in the 

magma. 

Schiffries ( 1982), in his studies of the Driekop pipe, 

concluded that it formed as the result of metasomatism by 

chloride-rich (aqueous) solutions at about 600±150oC and 

350± 100 MPa. Where these solutions come from is open 

to question. One interpretation is that the pipes formed as 

a result of vapor release by the sedimentary formations 

underlying the Bushveld complex. The relative contributions of deuteric and hydrothermal fluids are difficult to 

assess without further study. Yet many of the chemical reactions hypothesized by Schiffries (1982) to have occurred 

during pipe formation can be reconciled with purely deuteric reactions. It is, however, noteworthy that little if any 

alteration to olivine took place, implying, as Schiffries 

points out, that metasomatism and pipe formation ceased 

above the stability limit of serpentine, and therefore any 

residual aqueous phase was probably consumed during 

Fe11 hydrolysis and the dissolved constituents precipitated 

or sublimed in the metasomatized rock. 

Given the high pressures and temperatures during pipe 

formation, either a vapor containing H20 and CH3Cl 

(+HCl+CH4) or a highly saline chloride brine was present. 

The high Cl content of homblendes in the pipe and the 

need to transport Si02+Na20 out of and CaO and FeO 

into the altered region argues for a saline brine. But residual CH3Cl in a vapor could have played a role in graphite 

precipitation through a reaction such as 

in which the chloromethane. is consumed with formation 

of graphite and a chloride-rich brine. Although metasomatism led to enrichment of olivine with the fayalite component, as would be expected during crystallization of a 

basaltic magma, reactions typical of those involving the 

oxidation of Fe11 also appear to pave been influential. The 

excess graphite and deficiency of water in this system undoubtedly buffered the oxidation state and prevented more 

reducing conditions with the formation of kamacite or 

awaruite. In some respects, the pipe metasomatism is a 

high-temperature, water-poor equivalent to the serpentinization processes to be discussed in a subsequent section. 

DEUTERIC REACTIONS IN IGNEOUS AND 

METAMORPHIC ROCKS 

Deuteric reactions refer to those autogenous processes 

that take place during the subsolidus cooling of igneous 

rocks. Residual fluids react with the previously formed 

host-rock minerals, or with glass, to produce secondary 

minerals. The reactions occur as soon as a disequilibrium 

state is induced by cooling and continue with falling temperature. The most extensive deuteric alteration therefore 

takes place between 700 and 200°C. Of particular interest 

are those reactions between residual trapped fluids and 

minerals containing ferrous iron. 

Residual carbon monoxide disproportionates and 

leaves a residue of graphite below 700°C, probably as a 

thin coating on mineral grains. Ferrous iron in mafic minerals hydrolyzes and releases hydrogen at temperatures 

below about 500°C. Any unreduced sulfur species are reduced to H2S, which in tum reacts to form additional 

quantities of sulfide minerals. Remaining hydrogen reacts 

with the graphite coatings to produce methane. If all water 

is consumed during ferrous iron hydrolysis, and all graphite is reduced to methane, nitrogen may be reduced with 

formation of ammonia. The ammonia neutralizes HCl 

which in turn reacts with phyllosilicates and feldspars to 

form KCl by ion exchange. Ammonium ion exchange 

drives down fNH3 and limits back reactions. The reverse 

sequence of reactions is likely to be observed during prograde metamorphism. 

The scenario outlined is consistent with the thermodynamics of the participating chemical components and with 

field observations of residual gases in some, but not all, 
110 THE FUTURE OF ENERGY GASES 

igneous and metamorphic rocks. Neither the mechanisms 

of deuteric reduction nor the kinetics of the reactions are 

known fully over the temperature range of interest. 

Furthermore, radiolysis could modify the composition and 

oxidation state of the rocks and residual gases over time. 

An interesting example can be seen in the distribution 

of gases in fluid inclusions from the Dome de I' Agout, 

France (Kreulen and Schuiling, 1982). This dome comprises an ellipsoidal mass of gneisses and migmatites, 

60 km by 20 km in area, surrounded by chlorite-sericite 

schists. The dome reflects a localized hotspot in which five 

zones of increasing metamorphic grade are distinguished. 

Estimated temperatures of metamorphism range from less 

than 500°C in zone I the margin of the dome, to about 

700°C in zone V at the center of the dome. Two major 

kinds of fluid inclusions were observed: those containing 

CH4 and N2, and those containing C02, CH4, and H20. 

Trends in N2, CH4, and C02 contents with metamorphic 

grade are erratic, but the nitrogen content increases quite 

steadily toward the center. CH4 content generally increases 

towards the margin, whereas C02 content increases erratically toward the center. In zone I, C02 content is high and 

methane content low, in conflict with the general trend. 

Evidently, as the temperature increased toward the 

center of the dome, NH4 + was oxidized to nitrogen, and 

CH4 was oxidized to C02, accounting for the reciprocal 

relationship between CH4 and C02 contents· The increased temperatures caused decarbonation reactions and 

formation of calc-silicates in the country rock around the 

periphery of the dome, accounting for anomalously high 

C02 contents of the fluid inclusions in zone I. Kreulen and 

Schuiling ( 1982) did not investigate changes in NH4 + contents in phyllosilicates with increasing temperatures but 

noted that the NH4 + contents in biotite of the Dome de 

I' Agout were very high, ranging from 200 to I ,000 ppm. 

Also noteworthy is the observation that little if any free 

water was present within the dome. 

OPEN SYSTEMS 

Reducing conditions are observed wherever ultramafic 

rocks have been serpentinized below about 500°C in crustal environments. Mantle peridotites immediately underlying oceanic crust are hydrothermally altered adjacent to 

oceanic spreading centers. They are sometimes incorporated in accretionary wedges overlying subduction zones together with contiguous fragments of oceanic crust and 

sedimentary cover. These so-called ophiolite assemblages 

are usually exposed as long narrow belts paralleling 

present or former converging-plate margins. Ultramafic 

rocks are also found in the lower horizons of large layered 

mafic intrusions such as the Bushveld, Musk Ox, Skaergaard complexes, and in intrusive alkaline complexes in 

continental crust, and where ultramafic magmas, such as 

kimberlites, have solidified in diatremes. The following 

sections cite some of the field evidence for the development of reducing conditions in these environments. 

OCEANIC SPREADING CENTERS 

Hydrothermal circulation at oceanic spreading centers 

has been recognized for nearly two decades (Wolery and 

Sleep, 1976). The first high-temperature hydrothermal 

vents to be observed and sampled on the sea floor were 

those at 21 oN. on the East Pacific Rise (Spiess and others, 

1980). Since then, hydrothermal activity, characterized by 

black and white "smokers" and chimneys composed of 

massive sulfides or silicates has been discovered in various 

tectonic settings, including slow and fast spreading centers, 

backarc regions, and ocean-island hotspots (Charlou and 

Donval, in press). The venting fluids contain carbon dioxide, methane, hydrogen, some hydrogen sulfide, and helium 

with typical upper mantle 3He/4He ratios, that is, approximately eight times those found in the atmosphere (Welhan 

and Craig, 1979; Jean-Baptiste and others, 1991). The vents 

are characterized by benthic communities of tube worms 

and giant clams. The organisms exist by deriving their energy from bacteria that metabolize hydrogen sulfide and 

methane emanating from the vents. Because 3He, a conservative tracer, is released at concentrations some 3,000 times 

that found in sea water, and methane, while not conservative, is present in the vent fluids at concentrations some 

1 ,000 times above background, both species have been 

used as tracers in locating hydrothermal discharges (Charlou and others, 1991 a, b). 

The fact that carbon dioxide and hydrogen sulfide are 

also present in concentrations from 5 to 100 times greater 

than methane (Welhan, 1987; Charlou and Donval, in 

press) has not been emphasized in the literature. Welhan 

( 1987) pointed out that the CHiC02 and CH4/H2 ratios in 

East Pacific Rise hydrothermal fluids are remarkably similar to those in MORB vesicles (about 0.01 and 0.2, respectively). Furthermore, citing lPC isotopic data of the 

coexisting methane and carbon dioxide from Welhan and 

Craig (1983), he argued convincingly that the gases could 

have been in isotopic equilibrium only at temperatures between 550 and 750°C. At such high temperatures, neither 

methane nor hydrogen could be generated by olivine or 

enstatite hydrolysis because these minerals are thermodynamically stable with respect to their hydrolysis products. 

The dissolved gases in high-temperature hydrothermal 

vents are therefore the products of degassing of molten or 

quenched basaltic magma with an oxidation state in the 

region of the QFM buffer. They are typical of COz-rich 

magmatic gases and do not result from hydrolysis by mafic 

rocks. The o13C ratio of the C02 from the East Pacific Rise 

vents is typically magmatic, ranging from -5 to -7 permil 

relative to the PDB (Peedee belemnite standard), and is 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST Ill 

inferred to be of mantle origin. Although the water from the 

vents must originally have been seawater containing about 

129 mg L -I Co3-- (Nordstrom and others, 1979), most if 

not all of this carbonate probably precipitated as calcite in 

the descending limbs of hydrothermal convection cells. Evidence for seawater carbonate in C02 in the hydrothermal 

vents could be checked through examination for the presence of 14C. 

Although high-temperature vents might contain dissolved gases of presumed magmatic origin, it would be 

surprising if no methane or hydrogen in hydrothermal 

vents were derived through serpentinization or greenschist 

metamorphism. Some clues to relative magnitudes of the 

two sources might be gleaned from comparisons of the 

CH4PHe ratios in fluids from MORB vesicles with those 

in fluids from hydrothermal vents. Charlou and others 

(1991 a) have summarized these ratios from various submarine sites around the world. The ratio in basalts varies 

between 0.7 and 2.5x106, whereas the ratio in and around 

hydrothermal vents varies, with the exception of ratios 

from the Guaymas Basin, between 0.15 and 100x106. 

Given the possibility that some of the methane observed in 

the quenched basalts might have formed during cooling as 

a result of CO reaction with water vapor: 

CO+H20=C02+H2 (44) 

(1) 

it would not be surprising if the CH4PHe ratios in the 

magma were somewhat less than those reported in 

quenched basalts. The similarity between the ratios in basalts and those in high-temperature hydrothermal vents reinforces the proposition that the gases are primarily of 

magmatic origin. 

Isotopic equilibrium bet\\:een carbon species during the 

reduction of C02 to graphite or CH4 by mafic or ultramafic 

rocks is unlikely to be achieved in hydrothermal vents at 

temperatures much below 500°C (Welhan, 1987). In the 

presence of magmatic C02 with 6 13C values of about -7 

permil, 613C values for coexisting methane would not normally be less than about 22 permil. 613C values for mixtures of methane from different sources should therefore 

range from -22 permil to more positive values, superficially conveying the impression of being derived from even 

higher temperature sources than the magmatic methane. 6D 

and o13c isotopic evidence from other hydrothermal vents 

is minimal, and therefore the quantity of mixing of methane 

with different isotopic signatures must await future study. 

Recently, Charlou and others (1991 b, 1992), Rona and 

others (1992), and Charlou and Donval (in press) have reported the existence of a large plume of methane in the 

vicinity of diapiric domes of serpentinite in the Mid-Atlantic Ridge rift valley at 15° N. This plume appears to be 

related to the pervasive release of fluids from serpentinizing peridotite. The plume is distinctive in that the molar 

ratio of total dissolved manganese to methane in the 

plume is only 0.11, compared with 3.60 over the so-called 

TAG site, an active black-smoker field located at 26° N. 

on the Mid-Atlantic Ridge (Charlou and Donval, in press), 

or 7.4 over hydrothermal vents on the East Pacific Rise 

(Charlou and others, 1991 a). The much lower manganese 

content is primarily a reflection of elevated pH of pore 

waters and (or) lower temperature in the serpentinizing ultramafics. These recent discoveries substantiate the belief 

that serpentinization is active at oceanic spreading centers 

and that methane is being generated as a result. 

In summary, there are two distinct sources of methane 

emissions from oceanic crust at spreading centers and 

other regions of high heat flow. The first source is related 

to the degassing of mafic magmas and (or) cooling of 

mafic igneous rock. Emissions occur at high-temperature 

hydrothermal vents characteristically associated with black 

smokers. Methane is only a small fraction of the total gas 

composition in the vent fluid, the principal species being 

carbon dioxide and hydrogen sulfide. The second source 

of methane emissions is serpentinizing ultramafic rocks 

and, perhaps, hydrothermally altering mafic igneous rocks. 

Vents emitting methane from the second source are cooler 

and much more diffuse. The relative magnitudes of contributions from the two sources and the extent to which the 

two sources are interrelated is not currently known. Further study is needed to characterize the magnitude and distribution of fluids discharging from the second source. 

SUBDUCTING PLATE MARGINS 

Recognition of plate tectonics nearly three decades 

ago led inevitably to the question of whether subducting 

oceanic crust would lead to rapid thermogenesis of organic 

matter contained in the sedimentary rocks. Gwilliam 

( 1982) reviewed the initial development of ideas concerning oil and gas found in subduction zones and credited 

Hedberg (1970) with first recognizing the potential for oil 

and gas generation in this environment. Since that time, 

scientific investigations of subduction zones and associated accretionary wedges have proceeded with ever-increasing scope and detail. The potential for hydrocarbon 

thermogenesis in subduction zones is now recognized (Underwood and Laughland, 1990), but the release of hydrogen and methane during serpentinization of oceanic crust 

and mantle rocks and their role in saturating thermogenic 

hydrocarbons is unknown. The purpose of this section is 

to explore this and related issues. 

Because seawater fills pores and fractures in the oceanic crust, accelerated hydrolysis of ferromagnesian minerals could continue until the remaining water is expelled 

or consumed. Deeper in the subduction zone, at approximately 400 to 500°C, water of dehydration could migrate 
112 THE FUTURE OF ENERGY GASES 

back up the descending plate and also be hydrolyzed. How 

much unaltered ferromagnesian minerals are available has 

not been determined. Basaltic crust and peridotite are altered and lose CH4 and H2 to the ocean adjacent to 

spreading centers. Alteration probably continues at a lower 

rate during the time it takes the oceanic crust to reach a 

subduction-plate boundary. The residual primary ultramafic and mafic rocks may therefore be insufficient to act as a 

significant source of hydrogen or methane. 

During subduction, some of the lower density surficial 

hemipelagic abyssal-plain deposits and forearc sediments 

(for example, turbidites, pyroclastic deposits, and cherts), 

low-density serpentinite, and altered crust are scraped off. 

The scrapings accumulate as an accretionary wedge in advance of the subduction zone. The material is heterogeneous and complexly faulted. 

In figure 7 is shown a schematic cross section of a 

typical accretionary wedge (that associated with the Lesser 

Antilles subduction zone in the southeastern Caribbean 

Sea) illustrating commonly observed structural features. 

The size of the accretionary wedge varies depending on 

the character of th_e subduction. A subduction zone adjacent to a continental margin may accumulate large masses 

of land-derived erosional products and organic matter in 

the forearc basin. 

Measured subduction rates range from 0 to 10 em yr- 1

, 

although most average 3 to 5 em yr- 1

. At average subduction rates, sediments can be buried rapidly at depths and 

temperatures where entrained organic matter pyrolyzes to 

yield petroleum and natural gas. Such hydrocarbons could 

be generated both within the accretionary wedge and in the 

sediments subducted with the oceanic crust. Horizontal tectonic compression of the accretionary wedge can increase 

pore-fluid pressures, which in some cases approach local 

lithostatic pressure (Von Huene and Lee, 1983). Such high 

pressures are observed in boreholes penetrating the Barbados accretionary wedge (Moore and others, 1982), the Gulf 

of Alaska accretionary complex (Hottman and others, 

1979), and the accretionary wedge of the Oregon-Washington thrust belt (Moore and others, 1990). Modeling of the 

w 

latter by Wang and others ( 1990) confirms that fluid pressures can approach the lithostatic overburden pressure 

under certain conditions. Pore-water heating, the production of thermogenic methane, and water released during the 

dehydration of smectites could also contribute to the overpressures. The elevated pore pressures weaken the rocks 

and facilitate rock failure and thrusting as is typically observed in accretionary wedges (Moore and others, 1982, 

Vrolijk and others, 1991). 

Elevated pore pressures in the accretionary wedge 

may cause poorly consolidated sediments to disintegrate 

entirely and mobilize as mud. Because the porosity of the 

mud approaches 50 percent, the mud is less dense than the 

surrounding rocks and is displaced upward along fractures 

or is deformed and intruded as mud diapirs. Dissolved 

methane in mud diapirs exsolves with falling pressure during ascent, encouraging the formation of mud diatremes 

(Brown, 1990). Surface manifestations of mud intrusions 

in the form of mud volcanoes, mounds, and extrusive features have been observed at scattered subaerial localities 

around the world (Gold and Soter, 1980; Brown, 1990). 

Recently, similar phenomena have been observed in submarine environments by Kvenvolden and Field (1981), 

Westbrook and Smith (1983), Silver and others (1986), 

Langseth and others (1988), Henry and others (1990), Le 

Pichon and others (1990), Kulm and Suess (1990), and 

L.D. Kulm (pers. commun., 1988, cited in Wang and others, 1990) and Shipley and others (1990). 

An interesting variation of diapir formation has been 

observed in the Mariana forearc (Haggerty, 199 I). In this 

subduction zone, only minor accretionary complexes 

occur, but about 50 to 150 km arcward of the subduction 

zone trench, numerous mounds and seamounts with serpentine cores were found by Fryer and others (1985). The 

mounds and seamounts are believed to be sea-bottom expressions of serpentine diapirs that forced their way 

through formations in the overlying plate; fluids for serpentinization were provided during dewatering of the sedimentary slab. Sea-floor observations show that one such 

mound is covered with flows of particulate serpentine rnaE 

(Vertical exaggeration=2X) 

Figure 7. Cross section of the Barbados accretionary wedge. Modified from Speed (1990). 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 113 

terial whose genesis is unexplained. According to Haggerty ( 1991 ), pore fluids extracted from cores of this material 

were deficient in chlorine and bromine in comparison with 

seawater, but they contained twice the sulfate and were 

very alkaline, with pH=12.6. Methane, propane, and 

ethane as well as acetate and formate were present. Fluid 

inclusions in carbonate chimneys from the same seamount 

also contained methane, as well as aromatic compounds 

and aliphatic acids. Vent-fluid temperatures were cold. It is 

interesting that a sympathetic variation between alkalinity 

and ammonia concentration was observed in pore waters 

sampled from this mound (Shipboard Scientific Party, 

1990b, cited in Haggerty, 1991 ). This sympathetic variation suggests extremely reducing conditions within the serpentine body, due possibly to hydrogen saturation of 

hydrocarbons containing amine functional groups with release of ammonia. Somewhat less likely, though not impossible, is the reduction of nitrogen by hydrogen in the 

serpentine body. 

The fluids emerging from the serpentine mound have 

been modified by serpentinization, but Haggerty ( 1991) 

believed the mode of the hydrocarbon formation to be 

thermogenic alteration of carbon derived from organic detritus in the sedimentary mantle of the subducting plate. 

The presence of relatively high sulfate concentrations in 

the fluids is surprising and is thermodynamically inconsistent with the presence of light alkanes, suggesting that the 

fluids are mixtures from different sources. 

The compaction of sediments in the accretionary 

wedge and subducting plate leads to reduction of porosity 

from as much as 40 to 50 percent to as little as 5 percent. 

Large quantities of pore fluids and dissolved methane must 

therefore be expelled. Recent sea-floor exploration has discovered submarine venting of pore fluids offshore Oregon, 

at the north end of the Nankai Trough, in the Japan Trench, 

and in Sagami Bay adjacent to the Sagami Trough (Kulm 

and others, 1986). Offshore Oregon vents range in size 

from a few square meters to about 400 m2

. Their locations 

appear to be controlled by back thrusting in the fault-bend 

fold overlying the most forward frontal thrust, and by the 

underlying decollement and frontal thrust (Moore and others, 1990). The fault planes might therefore channel the 

expelled fluids. Although it has been suggested otherwise 

(Wang and others, 1990), the fault planes are probably barriers to fluid migration and force ascending fluids to migrate updip toward the exposed fault traces. Fluids 

undergoing expulsion should also convey heat from greater 

depths and accelerate diagenesis and thermogenesis of organic matter. The hydrology of water expulsion and heat 

transfer in rocks undergoing deformation and subduction at 

plate margins has not been studied extensively (but see 

Wang and others, 1990, for references to earlier work), and 

therefore much remains the subject of speculation. 

Geochemical studies of the fate of methane in accretionary wedges and subducting plates are very preliminary, and 

not enough is known to identify all processes involved. We 

have therefore linked the limited factual information from 

accretionary-wedge environments with observations based 

on field evidence in other sedimentary environments to 

present a synthesis of probable mechanisms. In figure 8 is a 

schematic representation of the geochemical processes affecting the evolution of water advectively ascending from 

subducting oceanic crust through overlying sedimentary 

rocks and ultimately discharging through the sea floor. It is 

not certain whether expelled fluids from the oceanic crust are 

able to cross the decollement interface and enter the overlying 

accretionary wedge. Further study of this issue is needed. At 

present it is assumed that interflow between the subducting 

slab and the accretionary wedge is possible as is inferred by 

Moore and others (1990) and Vrolijk and others (1991). 

We start at the top and work downward. In this way 

we can consider the progressive steps in diagenesis and 

metamorphism as sediments and oceanic crust are buried. 

Temperatures and pressures range from about 2°C and 

30 MPa at the ocean bottom to 600°C and 750 MPa in the 

descending plate, covering a wide diversity of geochemical processes affecting the generation of abiogenic methane and hydrogen and the reactions of these gases in the 

accreted sediments. 

Submarine sites where pore waters are expelled often 

reveal carbonate crusts, pillows, or tubes composed of calcite, aragonite, or dolomite (Kulm and Suess, 1990). The 

origins of the carbonate precipitates are complex. Some of 

the carbonate forms from the oxidation of methane. There 

is, however, no evidence that this methane was abiogenic 

in origin. Some of the methane is derived from the action 

of methanogenic bacteria immediately below the sea floor 

(Kulm and Suess, 1990). Methane is also generated at 

temperatures between 50 and 300°C in the subduction 

zone through thermogenesis, which occurs relatively rapidly in a subducting environment. 

In the subducting oceanic crust, at temperatures between about 200 and 500°C, basalts and gabbros are altered 

to greenschist-facies rocks, and peridotites are altered to 

serpentinites. The water required for alteration is seawater 

trapped prior to subduction, or water of dehydration ascending the slab from greater depths. Some of the resulting 

hydrogen or methane permeates upward. The hydrogen is 

consumed by reacting with thiol and amino functional 

groups, releasing H2S and NH3. It also participates in the 

saturation of alkenes through free-radical reactions, thereby 

increasing the yield of saturates with lower molecular 

weight; that is, higher gravity oil is produced, and the yield 

of light alkanes such as methane is increased. 

Saturation of cyclic hydrocarbons also decreases the 

asphaltene residue. It is unlikely that any hydrogen released at depth will penetrate upward beyond the thermogenesis zone, and therefore hydrogen discharge into the 

overlying ocean, as observed in hydrothermal vents at 

spreading centers, would not be expected. 
114 

!::vo 

·- ::l d)'~ ao:l "' (::-

·- cd cdu <U~ !::'"' "' ... 

d) 

., 

d) ._.rn ·-~ ::lO. •d) 

O.f:! vocd £a Eo.o vob.() o.o 

~.g f:!ll.l ll)-

o..E O:.Q 

0 0 0 

100 125 5 

200 250 10 

300 375 15 

400 500 20 

500 675 25 

600 750 30 

THE FUTURE OF ENERGY GASES 

Hp 

Sea water -sediment interface 

CH4 and NH4 + consumption by bacteria i Plagioclas~ I · · · · I --smectite CH4 hydrate +calcite 

I 

I 

I 

(laumontite) 

¢::JH20 

I Hs- NH + , 4 

Hydroge~atio~ (saturatiOn) "II 

ofoil 1 

I I 

CH +H~(+NH4 +) 

Oil 

Asphaltene 

Dissordered 

graphite Carbonate 

decomposition 

calcareous - Serpentinization 

Greenschist alteration 

silicates 

H20 (prehnite, 

I I 

I I 

I 

I I 

I I 

¢::JHp 

(N2) 

n 

pu)llpellyite, 

1 ZOISite, etC.) 

Sericite- K-spar+quartz 

I 

I I 

I I 

Dehydration 

serpentine --olivine 

Graphite 

Figure 8. Diagenetic reactions involving vapor components at various depths (and corresponding pressures and temperatures) in an accretionary wedge. Open vertical arrows indicate 

regions of generation and upward migration of volatiles; they are dashed to indicate uncertainty in the upper limits of temperature and pressure of volatile generation. Open horizontal 

arrows indicate water uptake. Vertical lines indicate regions where diagenetic reactions occur; 

they are dashed to indicate uncertainty in temperature and pressure ranges. 

Evidence for hydrogen saturation of hydrocarbons in 

subduction zones and accretionary wedges is circumstantial and inconclusive. Several oil fields in Cuba occur in 

large serpentine bodies in a complex overthrust belt (Wassal!, 1956; Gurko and others, 1982; Echevarria-Rodriguez 

and others, 1991 ). Gurko and others (1982) studied the hydrocarbon compositions in three fields in Cuba, one of 

which, Jarabucca, is in serpentinite host rock. Oil from 

this field is characterized by low density (0.5331 ), low viscosity, the absence of asphaltenes, low resin contents, and 

low aromatic contents. All of these characteristics could be 

attributed to maturation in a hydrogen-rich environment, 

as might be expected in a serpentinizing peridotite. Gurko 

and others believed, however, that these characteristics are 

the result of sorption during migration of the oil from 

source rocks, leading to relative enrichment of the migrated oil with low-molecular-weight hydrocarbons. It is noteworthy, however, that these characteristics seem to be 

most highly developed in the serpentinite-hosted oil field. 

With greater depths of burial, at temperatures >300°C, 

carbonates react to form hydrated calcium aluminum silicates-such as prehnite, pumpellyite, and actinolite (Ernst, 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 115 

1990)-and residual organic matter is decomposed to asphaltene. Whether secondary porosity is created in this 

environment is open to question, but if it is, ascending hydrogen and methane could be trapped with carbon dioxide 

beneath the carbonate seal unless the seal is ruptured by 

greater-than-lithostatic overpressures. Both the temperature 

and duration of reaction could be such that local equilibrium would be established between COz, CH4, and H2. 

Given the possibility of excess hydrogen being released 

from the underlying oceanic crust, some of the C02 could 

be reduced to carbon or methane. Very high pressure abiogenic methane accumulations under the thermogenic carbonate seal might be found. It is possible that convective 

circulation within imbricated thrust sheets might also enhance the creation of closed cells, as has been suggested 

by Hunt (1990) and by Dewars and Ortoleva (1988). 

As far as we are aware, no concerted efforts have been 

made to investigate potential gas traps in accretionarywedge and subduction-zone environments (however, see 

Stevenson, this volume). The limited evidence in the published literature is not encouraging. Fisher and Brantley 

(1992) investigated second-generation quartz-vein formation associated with the development of platy cleavage in 

shales in the Kodiak accretionary complex (see also Vrolijk 

and others, 1988). Conditions of formation of the quartz 

veins were similar to those of prehnite-pumpellyite-facies 

development in adjacent volcaniclastic sandstones and are 

therefore representative of conditions under which carbonates decompose. Fluid-inclusion thermometry and barometry suggested temperatures between 180 and 270°C and 

pressures between 220 and 300 MPa. The composition of 

the fluid inclusions was predominantly water and C02 with 

varying amounts of salt and CH4 (Myers, 1987). Fisher and 

Brantley (1992) found that the quartz veins were repeatedly 

disrupted and refilled with secondary quartz at intervals of 

102 to 104 yr. They suggested that upward fluid flow occurred intermittently from the decollement into a fracture 

network in the overlying wedge. It is not known whether 

the fracturing was triggered by the buildup of lithostatic 

pore pressures or was due to fluctuations in the partial pressure of C02 under varying deviatoric stress due to seismic 

activity. The periodic fluid releases, and fluid inclusion 

compositions in which C02 is in excess of CH4, do not 

make such an environment a tempting target for seeking 

economic reservoirs of abiogenic natural gas if we are to 

generalize from this isolated study. 

As temperatures exceed about 500°C, serpentinized 

ultramafic rocks will dehydrate to forsterite and liberate 

water (Bowen and Tuttle, 1949; Scarfe and Wyllie, 1967). 

Between 650 and 700°C, chlorite in greenschists will decompose (Delaney and Helgeson, 1978). Thus, there will 

be a tendency toward dehydration and release of water. 

The water could either penetrate updip into lower temperature regimes or be subducted and participate in fusion of 

the slab and overlying mantle wedge. The high water content of some andesitic and dacitic magmas erupting over 

subduction zones is persuasive evidence that at least some 

of the water eventually returns to the surface through volcanic activity. 

Rare-gas isotopic studies of expelled pore fluids provide indirect evidence for hydrolysis of oceanic crust and 

underlying peridotites. Sano and Wakita (1985), Sano and 

others (1987a), and Jeffrey and others (1988) have found a 

mantle 3He signature in gases from several convergent 

plate margins. In the forearc region in New Zealand, R/RA 

ratios range from 0.08 to 2.7, with most below 0.30 (Sano 

and others, 1987a). Wakita and others (1990) sampled natural gases from the forearc regions of the Japan trench. Here, 

RIRA ratios ranges from 0.07 to as high as 2.0, although 

most cluster around 0.1 to 0.2. Elderfield and others (1990) 

report measurements of 3He/4He ratios from pore fluids in 

cores of the Peruvian continental margin that are 0.088 and 

0.092 times that of the atmosphere. The R/RA values from 

most forearc regions indicate a small, and for the most part 

insignificant, involvement of mantle material. 

MAFIC AND ULTRAMAFIC IGNEOUS ROCKS 

IN THE CONTINENTAL CRUST 

Within the continental crust, mafic and ultramafic bodies are commonly exhumed or, in the case of layered intrusives, are mined for valuable metals. It is therefore 

possible to examine the alteration mineralogy and draw inferences about the actual or former presence of reducing 

gases. In this section we review some of the field observations concerning such rocks in the continental crust. 

Field evidence of the extremely reducing conditions 

induced by serpentinization of peridotites in ophiolite suites 

is very widespread. The occurrence of nickel-iron alloys is 

commonly reported (Eckstrand, 1975; Grudinin and Sekerin, 1979; Deutsch and others, 1977; Hahn-Weinheimer 

and Rost, 1961; Krishnarao, 1964; Ramdohr, 1952). Graphite, which may be primary or may be the result of carbonate 

reduction, has been observed in several ultramafic rocks 

(Cady and others, 1963; Krishnarao, 1964; Shteynberg and 

Lagutina, 1978). Shteynberg and Lagutina ( 1978), in particular, have documented the correlation between graphite and 

cohenite (Fe3C) contents of ultramafic rocks and the degree 

of serpentinization. Afanas'yev and others, (1972) even reported the existence of chloroform, volatile organics, and 

carboxylic acids in serpentinized ultramafic rocks of the 

Beden pluton in the former USSR. 

With respect to the evolution of methane and hydrogen from such sources, Thayer (1966) reports two analyses of gas seeps from peridotite in the Zambales ultramafic 

complex of the Philippines near Mount Lanat containing 

41.4 and 45.6 mole percent hydrogen and 52.6 and 53.8 

mole percent methane, respectively. Similar results were 

obtained by Abrajano and others ( 1988, 1990), who also 
116 THE FUTURE OF ENERGY GASES 

analyzed coexisting noble gases and concluded that the 

gases are products of peridotite hydration. The presence of 

reducing gases in serpentinites in Germany has also been 

noted by Hahn-Weinheimer and Rost (1961), and in the 

Semail ophiolite, Oman, by Neal and Stanger (1983) and 

Fritz and others (1992). The Semail ophiolite methane, 

ethane, and hydrogen are apparently forming at a groundwater temperature of 23 to 25°C (Fritz and others, 1992). 

Johan and LeBel (1980) noted that fluid inclusions in secondary chromite from altered ophiolites contain methane. 

Methane, together with small amounts of hydrogen, 

ethane, and propane has also been observed emerging 

from ultramafic rocks of the Moncheyorsk ultramafic pluton of the Kola Peninsula, Russia (Petersil'ye and others, 

1970). Soda springs of the Sierra Nevada, California, 

whose waters have contacted ultramafic rocks at depth 

also contain small concentrations of methane (Barnes and 

others, 1981). A somewhat similar environment favorable 

for methane production has been described by Bezrodnov 

(1979) from the Pechenga synclinorium of the Kola Peninsula. The synclinorium is filled with a sedimentary volcanogenic sequence and gabbro-diabasic and peridotitic 

rocks. The volcanogenic rocks consist of basalts, diabases, 

and pillow lavas. All the rocks have been metamorphosed 

to greenschist facies. Wells in the synclinorium intersect 

fissures containing water of alkaline bicarbonate-soda-lime 

or chloride-lime-soda composition, and these waters contain dissolved gases having a predominance of methane 

(up to 81.5 percent) and hydrogen (up to 24.8 percent). 

Methane has been observed in several wells drilled in 

basalt flows in the Pasco Basin of the Columbia River Basin, 

Washington (Gephart and others, 1979; Rockwell Hanford 

Operations, 1982), although in this case it is not clear whether the methane originates from the basalt or from organic 

matter in the occasional sedimentary interbeds. Methane 

and bitumens in kimberlite pipes (Kravtsov and others, 

1976; Vdovykin and others, 1979) and methane of residual 

gases present in mantle xenoliths (Chaigneau, 1975; Lutts 

and others, 1976; Petersil'ye and Pripachkin, 1979) are 

probably due also to hydrolysis. But, as noted earlier, these 

rocks are subject to alteration and contamination, and therefore should be examined carefully for evidence suggesting 

alternative explanations of the origin of methane. 

Numerous occurrences are known of methane and associated gases in crystalline basement rock of shields. 

Abiogenic gases-many flammable and containing methane (up to >80 percent), hydrogen (up to 30 percent), nitrogen (up to 80 percent), helium (up to 20 percent), argon (up 

to 4 percent) and minor amounts of noble gases and higher 

molecular weight hydrocarbons-are common in crystalline igneous and metamorphic rocks of Precambrian shield 

areas in Canada and Fennoscandia, as reported by Fritz and 

others (1987), Sherwood and others (1988), Sherwood-Lollar and others (1989), Nurmi and others, (1988), Guha and 

Kanwar (1987), and Lahermo and Lampen (1987). Vovk 

(1987) documented methanic gases of abiogenic ongm 

found in boreholes of the Ukrainian and Baltic shields at 

depths of a few hundred to 12,000 m. 

The Canadian gases are found in fractures and boreholes in mines from 300 to 2,000 m in depth and are commonly associated with alkaline saline waters and brines. 

Flows of flammable gas with flow rates up to 8 ft3

/min 

(225 Llmin) persisting for months from boreholes 1.25 inch 

(3.2 em) in diameter have been recorded, implying the 

presence of a significant gas reservoir and (or) rapid generation and evolution of gas in crystalline rocks. The sustained gas flow after drilling of the holes indicates that the 

gases are not artifacts of the drilling process. 

The abiogenic gases from shield areas are distinguished 

from biogenic and thermogenic gases by their high contents 

of He and Ar and distinctive heavy C and light H isotopic 

compositions in methane (fig. 9; Whiticar, 1990), and they 

are comparable to gases found in granitic and diabasic 

rocks in the Gravberg 1 well in the Siljan Ring impact 

structure, Sweden (see Castano, this volume). Dissolved 

gases in the formation waters in Finnish mines (Nurmi and 

others, 1988) are dominantly CH4 (with heavy carbon relative to biogenic CH4, b13C=-24.9 to -25.3) and N2 with 

lesser H2, 0 2, C02, Ar, and He. These compositions are 

similar to those of abiogenic gases elsewhere in Fennoscandia and Canada. The CH4 and H2 components are most 

abundant in intervals of graphitic schist and serpentine in 

one Outokumpu, Finland, borehole examined by Sherwood-Lollar and others (1989). 

Host rocks in mines of shield areas where abiogenic 

methane occurs have been documented by Fritz and others 

(1987), Sherwood and others (1988), and Sherwood-Lollar 

and others (1989). These papers are summarized below 

with additional information from Douglas (1969) and Thurston and others (1991 ). 

In the Strathcona Mine, North Range, Sudbury, host 

rocks are norite, mafic footwall rocks (metamorphic), and 

metasedimentary rocks. At the Thompson Mine, Manitoba, 

nickel ores occur mainly in peridotite and also in adjacent 

metasediments and gneisses. In the Red Lake Camp, Ontario, host rocks for gold occurrences are mafic to felsic 

metavolcanic greenstones, including komatiites, basalts, 

and gabbro. The Kidd Creek mine, Ontario, exploits massive sulfides in mafic to felsic greenstones including komatiites, tholeiites, and rhyolites. Gold is recovered from 

shear zones in basaltic greenstones at the Sigma Mine, Val 

d'Or, Quebec. At Matagami Lake and Norita, Quebec, gold 

ore is hosted in mafic-felsic volcanic rocks with associated 

gabbro and anorthosite. Host rocks at the Consolidated 

Giant Mine, Yellowknife, Northwest Territories, are metavolcanic rocks including chlorite schist and amphibolitized 

pillow lavas, with interlayered argillaceous and quartzose 

graywacke. At Outokumpu, Finland, the ore host rocks are 

serpentine and graphitic schist, among other schists, carbonates, skarns, and gneisses. 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 117 

In the Denison Mine, Elliot Lake, Ontario, uranium 

ore occurs in quartz-rich sandstone and conglomerate of 

the basal Matinenda Formation originally deposited 

on granitic Archean basement rocks. High-reflectance 

(R0=3.0, where R0 is vitrinite reflectance in oil) kerogen is 

common in subgreenschist- to greenschist-facies uraniumore-bearing rocks (Willingham and others, 1985) and is 

the likely source of thermogenic methane. Gas at this site 

is very high in He (14 and 19 percent in two samples), 

apparently due to uranium decay. If hydrogen was originally present in the gas, it probably contributed to formation of saturated hydrocarbons. 

Mafic and (or) ultramafic rocks are present at all sites 

except Elliot Lake. At Outokumpu, graphite-rich schist is 

also present. The evidence that the host rocks hydrolyzed to 

yield abiogenic methane is persuasive. At Elliot Lake, the 

Huronian sedimentary rocks yield helium-rich methane gas, 

which likely developed by thermogenesis from the kerogen 

occurring with the uranium ores. 

Frape and others (1984) found concentrated Na-Ca-Cl 

brines at depths greater than 650 m in the Canadian shield. 

They suggested that these brines may have been concentrated by removal of water under closed-system conditions. 

The gas flows observed from fractures and borings in basement rocks described by Sherwood <\nd others (1988) and 

the compositional data on saline waters and brines documented from these rocks by Fritz and others (1987) support 

our proposed hypothesis that hydrolysis by plagioclase, amphibole, and biotite has produced Fe-oxides, secondary sili-

--100 ·- . § 

v 

0.. -80 

.8 

v 

§ -60 ~ ....... 

v 

8 .c.) -40 r<"l 

,..... 

C;Q 

-20 

cates, hydrogen, methane, and waters rich in Na, Ca, and 

Cl. Circulation of meteoric waters with accompanying hydrolysis by silicates evidenced by oxygen and deuterium 

isotopic exchange to depths of 10 to 15 km in the crust has 

been documented by Wickham and others (1993 ). Radiolysis may have contributed to increased salinity as noted earlier in this report. 

Methane associated with diabase (dolerite) sills in 

granites beneath the Siljan Ring, Sweden, is a typical example of the widespread phenomenon outlined above. Because the occurrence has been well studied (see Ca;>taiio, 

this volume), it is worth discussing some of the implications of observations made during and after the drilling of 

the Gravberg I hole into this structure. 

Several techniques were employed to obtain samples 

of gas during drilling. These have been described by Jeffrey and Kaplan (1988), who analyzed the samples for 

light hydrocarbons including methane, hydrogen, carbon 

dioxide, and occasionally helium. A.W.A. Jeffrey, then of 

Global Geochemistry Corp., kindly provided us with data 

of the gas analyses from various samples collected for 

evaluation during the drilling of the Gravberg l. Numerous problems were caused by contamination during sampling (see Castano, this volume). The interpretations are 

therefore preliminary in nature. 

It is not possible to relate the concentrations of gaseous 

species in samples used for analysis with the concentration 

of those species in interstitial fluids in the host rock, because 

it is not known to what extent dilution by drilling fluids 

OL---L-~--~--~--~--~--~~--~--~--~r-~~ 

-700 -600 

8D-methane, in permil Greenland gas inclusions 

(Konnerup-Madsen and others, 1988) 

Figure 9. Isotopic compositions of methane from various biogenic and abiogenic sources, modified from Whiticar (1990). Data for 

Norita, Timmins, Val d'Or, Red Lake, Elliot Lake, and Sudbury (all in Canada) are from Sherwood and others (1988). Data for 

Gravberg l well (Sweden) are from Jeffrey and Kaplan (1988). EPR, East Pacific Rise; THERM, thermogenesis. 
118 THE FUTURE OF ENERGY GASES 

occurred. Furthermore, gases released from fluid inclusions 

in the rock-forming minerals during drilling would have 

mixed with fluids filling the continuous pores in the granite, 

and the two could be of completely different compositions. 

Hence, the samples collected could not be used to make 

quantitative estimates of dissolved-gas concentrations in the 

ground water for comparison with calculated gas-species 

distributions at thermodynamic equilibrium. 

Castano (this volume) notes that two distinctive formation waters were present: ( 1) a dilute meteoric water down 

to 5,000 m depth, and (2) a highly saline brine observed 

below 5,000 m. 

Samples of the connate brine from below 5,453 m 

were recovered from the well during an extensive pumping operation in 1990 (Castano, 1990). Chemical analyses 

of the brine, in conjunction with the mineralogical descriptions, permit a provisional assessment of the geochemical 

environment, and an evaluation of the expected partial 

pressures of gaseous species (Pco2

, PH2, PcH4) that would 

coexist in equilibrium with the brine at that depth. The 

chemical analysis of sarpple 14 reported by Castano 

( 1990) is shown in table 1. Of those analyzed, this sample 

is believed to be the least contaminated by extraneous 

fluids. 

Gases separated from the brine were also analyzed and 

estimated by Castano to yield the concentrations in solution 

at depth reported in table 2. 

The oxygen gas is probably due to atmospheric contamination. Subtraction of the oxygen and corresponding 

nitrogen contamination yields the corrected aqueous concentrations shown in the righthand column in table 2. 

A temperature of 119°C was estimated from the ratio 

[Na+]/[K+], (Apps and Chang, 1992), assuming that potash 

feldspar and low albite are in equilibrium with the formation water. This temperature corresponds to a depth of 

6,705 m below the surface, which is consistent with downhole measurements. 

We calculated the distribution of species, mineral saturation indices, and gas fugacities in the brine, assuming 

saturation with respect to muscovite, quartz, low albite, 

pyrite, and hematite. Given the limitations of the model 

used and associated thermodynamic data, results are, for 

the most part, consistent with an equilibrium state between 

the ground water and the host-rock granite. 

Some of the relevant information from the calculation 

is reported in table 3. Species reported at or near saturation 

have not all been observed as secondary minerals in the 

granite. The calculated saturation index for calcite, + 1.30, 

is too high but probably within the limits of uncertainty of 

the model. The most significant discrepancy is the calculated hydrogen fugacity (log fH2

=-4.72 at oxidation potential 

(Eh)=-0.28 volts) in comparison with that estimated from 

the gas analysis (log fH2

=-0.85 at Eh=-0.42 volts). Furthermore, were the hydrogen at equilibrium with carbon 

dioxide and methane, according to the Fischer-Tropsch reTable 1. Chemical analysis of formation 

brine recovered from Gravberg 1 well, 

Sweden, in 1990. 

[Analysis of sample 14 of Castano (1990)] 

Species 

Na --------------

K ---------------

Mg -------------

Ca --------------

5 r ---------------

Cl---------------

HC03 ---------

SO 4 ------------

Concentration 

(mg L-1) 

17,725 

335.5 

1.5 

43,613 

445 

93,000 

89 

300 

Table 2. Concentrations of gases in solution formation brine 

recovered from Gravbeg 1 well, Sweden, in 1990. 

[Analysis of gases recovered from sample 14 of Castano (1990). cm3, cubic 

centimeter; L, liter; mol, mole] 

Reported concentration Corrected concentration 

Gas (Castano, 1992) (this study) 

(cm3 L-1) (mol L- 1) 

N2 ------ 137.9 4.96x!0-3 

Ar------- 4.45 1.74x w-3 

He------ 113.15 4.62x!0-3 

Hz ------ 3.01 1.23x 10-3 

Oz ------ 4.41 0.0 

action, log fcH4 would be about +6.0 (MPa), and log fNH3 

would be about -2.0 (MPa). 

The amount of dissolved hydrogen is clearly in excess 

of what would be expected if the ground water were in 

homogeneous equilibrium. The hydrogen concentration 

could be an artifact of the drilling and sampling procedures, but the extended pumping to acquire the formationwater sample militates against such interpretations. The 

hydrogen and other gases have been migrating from much 

deeper and higher temperature domains, either by diffusion or by convective transport through fracture conduits. 

Because the mineralogy and composition of the rocks at 

greater depths are not known, the temperature and depth 

at which the measured hydrogen concentration would approach equilibrium with the formation water and host 

rocks cannot be estimated precisely, but the temperature 

probably falls between 200 and 450°C and the depth between 10 and 25 km. The hydrogen could be the product 

of radiolysis due to uranium and thorium decay. Because 

some of the intervals in the granite contain relatively high 

concentrations of thorium, and a crude correlation of heli-
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST _119 

Table 3. Analysis of brine chemical equilibria in the 

Gravberg 1 well, Sweden, at about 6,000 m depth. 

[Calculations assume that T= I I 9"C and groundwater is saturated in the 

minerals quanz, muscovite, low albite, pyrite, and hematite. aq, aqueous; f, fugacity; m. molality, or moles per kilogram of water; MPa. 

megapascals] 

COMPUTED AQUEOUS SPECIES CONCENTRATIONS 

Species 

Fe++ ----------------

Fe+++ --------------

AJ+++ --------------

Si02(aq) -----------

Hs- ----------------

pH (mol)-----------

Eh (volt)-----------

Mean charge 

imbalance 

(percent). 

Concentration(m) 

3.15xl0-4 

<l.OOxJ0- 10 

2.60xl0-7 

1.20x I o-3 

2.57x!o-7 

6.76 

---D.28 

+5.30 

SATURATION INDICES 

Mineral 

Ca-beidellite ------

C<ilcite -------------

Clinochlore --------

Dolomite-----------

Epidote-------------

Heulandite ---------

Illite ----------------

K-feldspar ---------

Kaolinite-----------

Laumontite--------

Magnetite----------

Paragonite---------

Prehnite ------------

Siderite-------------

Strontianite--------

Tremolite ----------

Zoisite--------------

Gas 

NH 3 ----------------

C02 ----------------

H2S -----------------

N 2 ------------------

Hz ------------------

CH4 ----------------

Saturation index 

---D.04 

+1.31 

+0.94 

+0.27 

2.06 

---D.21 

---D.04 

-D. OJ 

---D.63 

---D.Ol 

+2.29 

---D.04 

+1.93 

+0.03 

+0.28 

---D.l7 

+0.58 

GAS FUGACITIES 

log f (MPa) 

-5.67 

-2.12 

-5.72 

1.00 

-4.72 

-8.58 

urn with hydrogen is observed with increasing depth, this 

potential explanation has some merit. Finally, the hydrogen could be the result of cataclasis. Hydrogen evolved 

during the meteorite impact would not still be present in 

the granite, but the region is currently experiencing postglacial isostatic rebound, and therefore the crustal rocks 

are currently under stress. 

The calculated concentration of methane in the recovered 

brine should be nearly four orders of magnitude less than that 

of hydrogen; this prediction is partially verified by the gas 

analysis, as methane was not detected by Castano (1990). 

The most notable feature observed in gas samples collected during drilling was the anomalous concentration of 

methane when drilling through the diabase sills, as illustrated in figure 10. Records of the thickness and number 

of sills penetrated are not detailed, and the anomalous 

methane is not coincident with every sill. The methane 

anomalies are, however, undoubtedly due to the reducing 

conditions caused by the secondary alteration of olivine in 

the diabase. Current descriptions of the secondary mineralogy and the available thermodynamic data are inadequate 

to predict whether the present environment would support 

a redox potential sufficiently low to produce the observed 

CH4(gas)/H2(gas) ratio in the samples, even if it reflects 

ambient conditions. 

Within the limits of the sampling intervals, the methane anomalies appear to be very strong and localized. If 

the diabases were altering in response to the incursion of 

present-day ground waters, the methane peaks would be 

less pronounced due to CH4(aqueous) diffusion into the 

surrounding granites. Alternatively, the granites could oxidize all methane that diffuses out. The latter explanation 

is not justified by the small redox buffering capacity of 

the granite and the lack of visible evidence that the hematite staining of the feldspars is being reduced to magnetite 

adjacent to the sills. The most plausible explanation is 

that the methane is contained in closed pores or fluid inclusions that were ruptured during drilling. Although fluid 

inclusions have been observed in the diabases, their 

compositions have not been determined (Castano, this 

volume). 

The qualitative distribution of hydrogen with depth in 

the Gravberg I hole shows some interesting patterns. As 

illustrated in figure 10, hydrogen appears to show higher 

concentrations adjacent to diabase sills in the granite than 

within the diabase sills where the methane anomalies occur. 

This distribution raises the interesting question of whether 

the hydrogen anomalies are relics of hydrogen released by 

the mafic magma at the time of intrusion when it interacted 

with and reduced connate water in the host granite. 

The fugacity of oxygen in mafic magmas is about I o-9 

MPa at 1,200°C, and fH2 would be about 1.0 MPa. On 

cooling, the hydrogen would react with C02(aqueous) according to the Fischer-Tropsch reaction with the formation 

of methane, thereby consuming hydrogen and producing 

methane in the cooling sill. Reaction equilibrium shifts to 

the right at 600°C at 100 MPa pressure. The persistence of a 

relic halo of hydrogen can be explained only if the hydrogen-rich fluid were also trapped in fluid inclusions and isolated from fluids in continuous fractures. It should be noted, 

however, that Komar and others (1988) detected only C02 

in fluid inclusions in rock samples from the Gravberg 1 well. 
120 THE FUTURE OF ENERGY GASES 

c 5 

~ I I ' ' '§ ' ' .... ' ' 15.4 

Zl 

' • ' ,, .... ,, 

"' 0.. " ,, 4-

0 

,, 

" ,, </) 

"0 3 c 

"' C"· </) 

::l 

0 

-5 

.5 2 

=· .s 

o:; 

b 

c 

<l.l 

() 

c 

0 

() 

"' O..ClmLn..n. Jill 1_ ...a_ .J n D- /". 

tJ.Io n _., I, .n' 0 0 .n... 

2.1 2.2 2.3 2.4 

A 

c 14 

~ '§ 

.... 12 <l.l 

0.. 

</) 

~ 10 0.. 

4-

0 

</) 

"0 8 c 

"' </) 

::l 

0 6 -5 

.5 

c 

0 4 -~ 

.... 

E 2 <l.l 

() 

c 

2.5 2.6 2.7 

Depth, in kilometers 

,"'\0 

' ' o,' ~ 

' ' ' ' 0 ' 

:• ' 

b 

• 

' 

D 

,, 

'' '' '' '' '' ' 

2.8 

' ' . ' ' ' ._ 

o..w ·,... ·~*~-~· !b 0 

u • ' * 

"' 0 o..o. tol....,..o.-~EJ---~--p: • * T ::r: 

2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8 

B Depth, in kilometers 

,, 

:o. 

'' ': 

' ' 

~'..Iun o '"'h.o 

2.9 

' o,'o 

' 

•• 

J 

2.9 

3.0 

,-, 

'' Ill• 

: 1;1 

' ' ' 

' ' ' 

•I* • 

3.1 

3.0 3.1 

Figure 10. Comparison of methane (A) and hydrogen (B) anomalies in fluids recovered from depths between 2,100 and 3,100 m during drilling of Gravberg 1 well, 

Sweden. Squares, fluids from canned headspace of outgoing fluid and cuttings; stars, 

outgoing drilling fluid; dots, fluids from dunk-tank vacutainers (see Jeffery and Kaplan, 1988, for further details). Solid bars· represent diabase (dolerite) sills, queried 

where presence is uncertain. Dashed lines bound interpreted envelope of maximum 

concentrations of gas. 

Verification of the release and entrapment of hydrogen, and the generation of methane within the diabase sill 

during cooling, might be established with more detailed 

studies of fluid inclusions and the mineralogy and petrography of the thermal alteration zones about the sills, and 

suitable modeling of the thermal history of a sill and adjacent granites subsequent to emplacement. 

ECONOMIC SIGNIFICANCE OF 

ABIOGENIC GASES IN THE 

EARTH'S CRUST 

Although there are numerous reports of methane and 

hydrogen of undoubted abiogenic origin, none can be described as of economic significance. The dilution of ther-
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 121 

mogenic natural-gas reservoirs by methane of mantle 

origin is in all cases trivial. Hydrogen generated by maficrock hydrolysis, by the radiolysis of water, or by cataclasis 

might have contributed to the maturation of petroleum and 

natural-gas resources, but its significance has not been established. Therefore, it remains to be determined whether 

energy gases of undoubted abiogenic origin might be concentrated in hitherto unexplored regions of the Earth's 

crust. 

The most promising sources of abiogenic energy gases 

are ultramafic, and to a lesser extent, mafic igneous rock 

masses that have undergone alteration in the presence of 

water. If we consider the most promising scenario, the alteration of a peridotite, we can determine the maximum 

potential of such rocks to produce methane or hydrogen 

through hydrolysis. 

By combining reactions 40 and 41, we get 

For a peridotite containing 8 weight percent FeO, 

about 27 cm3 of methane would be released per gram of 

rock. For I km3 of peridotite of density 3.3 g/cm3, about 

9xi010 m3 (3 Tcf) methane would be produced. 

Mafic rocks usually contain FeO in the range of 9 to I 0 

weight percent. Therefore, it would be expected that they, 

too, could produce similar amounts of methane upon hydrolysis. The alteration of large mafic bodies such as the Bushveld complex would have the potential of producing giant 

gas fields. Some gas wells in Kansas produce anomalously 

high quantities of hydrogen (Coveney and others, 1987), 

which appear to be related to deep-seated gabbroic intrusions associated with the Midcontinent Rift. But major gas 

accumulations associated with mafic rocks are unknown. 

Several explanations for the absence of significant resources can be advanced: 

I. Water must be transported into the interior of the 

ultramafic or mafic igneous rock body in order to permit 

hydrolysis. Most igneous bodies, although commonly 

heavily fractured, possess low fracture permeabilities and 

very low matrix permeabilities. Therefore water access is 

poor. Peridotites alter to hydrated magnesium silicates 

with larger molal volume than the primary minerals. This 

alteration decreases permeability around the margins of 

such bodies and inhibits further ingress of water. 

2. Although peridotite alteration can take place below 

100°C, reaction rates are slow. Extensive serpentinization 

or greenschist-facies metamorphism requires sustained 

temperatures between 200 and 500°C. Considerable burial 

depth is necessary to achieve such temperatures, together 

with sufficient access of water to permit alteration. Many 

exhumed mafic and ultramafic rocks show incomplete alteration, suggesting a lack of water access or inadequate 

burial. 

3. According to reaction 45, nearly 5 weight percent 

C02 must be present to generate methane. It is unlikely 

that such a large concentration of C02 is accessible to altering ultramafic or mafic rocks. During serpentinization, 

highly alkaline waters containing CaO are released, which 

would tend to precipitate C02 as calcite in veins and outside the body, limiting the access of C02 and retarding the 

inflow of water. Therefore, complete methanization of 

C02 would not be expected, and altering rocks would release both CH4 and H2, the ratio depending on the availability of carbon and the oxidation state. 

4. From· figure 5 it can be seen that any sulfate present 

or introduced during serpentinization must be reduced to 

hydrogen sulfide or metallic sulfides. Such reactions 

would interfere with methane and hydrogen generation 

and decrease the quantity of methane and hydrogen that 

could be produced. An environment favorable for the production of abiogenic methane must therefore be depleted 

in sulfate. Because seawater contains about 2,700 .ppm 

sulfate, its participation in the hydrothermal alteration of 

oceanic crust would cause the suppression of methane unless the sulfate were removed. Sulfate and calcium are 

readily precipitated as anhydrite during the albitization of 

plagioclase, and thus the concentration of sulfate in solution could be reduced to a low level in the descending 

limb of a hydrothermal convection cell. Removal of the 

bulk of the sulfate and reduction of the remainder to sulfides would ensure that sulfate-poor seawater would then 

be available to generate methane and hydrogen locally. 

Meteoric waters typically contain <20 ppm sulfate, so with 

such waters there would be little interference with hydrolytic methane and hydrogen generation. 

5. Alteration of ultramafic and mafic rocks usually occurs in tectonically active regions. These regions are subject to faulting, and atmospheric venting is possible. 

Regions where methane is most likely to be generated 

are also those where the resultant gases are unlikely to be 

trapped in suitable reservoir structures. This applies particularly to continental rifts, constructive plate margins, and 

flood-basalt accumulations. Even in accretionary wedges 

or in subducting oceanic crust, the potentially large overpressures generated by decarbonation and by methane and 

hydrogen formation could exceed overburden pressures 

and release gases along well-established thrust fault 

planes. Gas building up along transform plate margins, 

could also be released along the principal faults. It is 

therefore quite likely that Earthquake activity could be 

triggered by and lead to the transient release of flammable 

gases. Anecdotal documentation of lights and flames arising from surface ruptures during Earthquakes (Gold, 1987) 

could reflect the presence of abiogenic methane, hydrogen, 

and (or) hydrogen sulfide, particularly when faulting is in 

the vicinity of serpentinite bodies, as occurs along the San 

Andreas Fault in California. 
122 THE FUTURE OF ENERGY GASES 

Very large buried mafic igneous bodies-emplaced at 

relatively shallow depths but deep enough to undergo extensive alteration, in contact with an abundant supply of 

low-sulfate water, and overlain by sediments that could 

provide impervious structural traps-would constitute favorable environments for abiogenic gas accumulation. 

Such environments are relatively rare but might be found 

in and adjacent to infilled graben structures associated 

with failed continental rifts. 

Deep drilling of accretionary wedges might also locate 

high-pressure abiogenic methane resources, but thermogenic sources of methane may overwhelm abiogenic 

sources. As noted earlier, the little information on such environments is not encouraging. Difficult drilling conditions 

would be expected in active accretionary fronts, and the 

attendant cost may not be justified by the rewards. 

In summary, we recommend very selective targeting of 

favorable environments only after comprehensive geologic, 

geophysical, and geochemical evaluation to establish their 

potential. The opportunities for abiogenic gas recovery appear to be very limited, as borne out by the lack of evidence 

for commercial resources even though the generation of 

abiogenic methane and hydrogen in crustal environments is 

well documented. 

CONCLUSIONS 

Below, we summarize the most important conclusions 

of this paper. 

Abiogenic methane and hydrogen are derived largely 

from crustal sources, of which the most important is ultramafic and mafic igneous rocks hydrolyzing at temperatures 

below 500°C. 

Abiogenic methane and hydrogen are also found in 

significant quantities in mines in crystalline rocks in the 

Canadian and Fennoscandian shields. The gases were apparently generated by hydrolysis from meteoric waters circulating through fractures in mafic and graphitic igneous 

and metamorphic rocks. 

Hydrogen can also be generated by radiation- and cataclasis-induced hydrolysis. The significance of these processes has not been established. Hydrogen is relatively 

inert, but it might participate in the saturation of thermogenic hydrocarbons. 

There is no evidence that methane is present in the 

upper mantle in other than minor concentrations, because 

the oxidation state of the upper mantle is too high. 

No evidence has come to light indicating that volatiles 

are transported to the Earth's surface from the mantle by 

any means other than through the agency of magmas. 

The oxidized state of the upper mantle could be due to 

initial oxidation of a surficial molten layer early in the 

Earth's history, or to loss of hydrogen into the crust and 

atmosphere over geologic time through basaltic magmatism and formation of oceanic crust. 

Magma volatiles are dominated not by methane and 

hydrogen, but instead by C02+CO, H20, S02 and H2S. 

The proportions of these gases vary depending on the 

source of the magma and its history. No magmas contain 

significant concentrations of methane. 

Gases sourced in the mantle and released from magmas are readily identified by their 3He/4He ratios, because 

this ratio is up to 3,000 times higher in the mantle than in 

the continental crust. 

The lower continental crust is too oxidized top permit 

transit of reduced gases such as methane. Therefore, even 

were the upper mantle sufficiently reducing to stabilize 

methane, the methane could not penetrate into the upper 

crust without being oxidized. Nowhere is there any evidence that large volumes of methane have ever overwhelmed the oxidation capacity of the lower crust and 

migrated into the upper continental crust. 

Gases that leak from crystalline basement rocks into 

overlying sedimentary basins hosting natural-gas reservoirs do not contain significant concentrations of methane. 

They are distinguished by relatively high concentrations of 

radiogenic helium and nitrogen, which mix with natural 

gas. Basement gases therefore cannot be the primary 

source of natural gas in the reservoirs in these basins. 

Hence, any methane from the upper mantle does not enter 

such reservoirs through basement rocks. 

Some natural-gas reservoirs in sedimentary basins are 

enriched in 3

He where no magmatism is evident. However, this enrichment is not associated with gases emerging 

from the basement rocks underlying these reservoirs. 

Abiogenic methane and hydrogen, produced through 

hydrolysis by ultramafic and mafic rocks, are in structural 

environments where the generated gases are likely to be 

lost to the atmosphere. No commercial abiogenic gas reservoirs have ever been identified in structurally favorable 

areas. 

Careful a priori evaluation of sources is required before drilling targets for abiogenic methane and hydrogen 

because the likelihood of finding a commercial reservoir 

of these gases is small. 

ACKNOWLEDGMENTS 

We are indebted to R.C. Burruss, D.G. Howell, and 

M.D. Lewan of the U.S. Geological Survey; B.M. Kennedy, 

M.J. Lippmann, and H.A. Wollenberg, Jr., of the Lawrence 

Berkeley Laboratory; and I.S.E. Carmichael of the University of California, Berkeley, for their constructive reviews 

and helpful suggestions regarding this paper. We thank 

A.W.A. Jeffrey for providing (while at Global Geochemistry Corp.) data on the gas compositions in samples obtained during drilling of the Gravberg 1 well in Sweden. 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 123 

This work was supported in part by the Director, Office of Energy Research, Office of Basic Energy Sciences, 

Engineering Sciences Division of the U.S. Department of 

Energy under Contract No. DE-AC03-76SF00098. 

REFERENCES CITED 

Abe, Y., and Matsui, T., 1985, The formation of an impact generated H20 atmosphere and its implications for the early thermal history of the Earth, in Ryder, G., and Schubert, G., 

eds., Proceedings of the Fifteenth Lunar and Planetary Science Conference, Part 2: Journal of Geophysical Research, 

v. 90, Supplement, p. C545-C559. 

Abrajano, T.A., Sturchio, N.C., Bohlke, J.K., Lyon, G.L., Poreda, 

R.J., and Stevens, C.M., 1988, Methane-hydrogen gas seeps, 

Zambales ophiolite, Philippines-Deep or shallow origin?: 

Chemical Geology, v. 71, p. 211-222. 

Abrajano, T.A., Sturchio, N.C., Kennedy, B.M., Lyon, G.L., Muehlenbachs, K., and Bohlke, J.K., 1990, Geochemistry of reduced gas related to serpentinization of the Zambales ophiolite, 

Philippines: Applied Geochemistry, v. 5, p. 625-630. 

Afanas'yev, G.D., Karpushin, V.M., Kachurin, V.F., Knyazeva, 

D.N., Miller, A.D., and Ploshko, V.V., 1972, Halogens and 

carbon in ultramafic rocks of the Beden Pluton in the northern Caucasus: Doklady, Academy of Science of the USSR, 

Earth Science Section 202, no. 1-6, [English translation] 

p. 35-37. 

Aldrich, L.T., and Nier, A.D., 1948, Occurrence of He3 in natural 

sources of helium: Physical Review, v. 74, p. 1590-1594. 

Anderson, A.T., and Wright, T.L., 1972, Phenocrysts and glass 

inclusions and their bearing on oxidation and mixing of basaltic magmas, Kilauea volcano, Hawaii: American Mineralogist, v. 57, p. 188-216. 

Aoki, K., and Kanisawa, S., 1979, Fluorine contents of some hydrous minerals derived from the upper mantle and lower 

crust: Lithos, v. 12, p. 167-171. 

Apps, J.A., and Chang, G.H., 1992, Correlation of the Na!K ratio 

in geothermal well waters with the thermodynamic properties of low albite and potash feldspar, in Kharaka, Y.K., and 

Maest, A.S., eds., Water-rock interaction: Rotterdam, A.A. 

Balkema, p. 1437-1440. 

Arculus, R.J., and Delano, J.W., 1980, Implications for the primitive atmosphere of the oxidation state of Earth's upper mantle: Nature, v. 288, p. 72-74. 

Arnold, F., Buehrke, T., and Qiu, S., 1990, Evidence for stratospheric ozone-depleting heterogeneous chemistry on volcanic aerosols from El Chic6n: Nature, v. 348, p. 49-50. 

Bailey, D.K., 1989, Carbonatite melt from the mantle in the volcanoes of south-east Zambia: Nature, v. 338, p. 415-418. 

Bai, Q., and Kohlstedt, P.L., 1992, Substantial hydrogen solubility in olivine and implications for water storage in the mantle: Nature, v. 357, p. 672-674. 

Ballentine, C.J., 1991, He, Ne and Ar isotope~ as tracers in crustal fluids: Cambridge University, Ph.D. dissertation. 

BaUhaus, C.G., 1988, Potholes of the Merensky Reef at Brakspruit Shaft, Rustenburg platinum mines-Primary disturbances in the magmatic stratigraphy: Economic Geology, 

v. 83, p. 1140-1158. 

Barnes, I., Johnston, D.A., Evans, W.C., Presser, T.S., Mariner, 

R.H., and White, L.D., 1982, Properties of gases and waters 

of deep origin near Mount St. Helens, in Lipman, P. W., and 

Mullineaux, D.R., eds., The 1980 eruptions of Mount St. 

Helens, Washington: U.S. Geological Survey Professional 

Paper 1250, j'l. 233-237. 

Barnes, I., Kistler, R.W., Mariner, R.H., and Presser, T.S., 1981, 

Geochemical evidence on the nature of the basement rocks 

of the .Sierra Nevada, California: U.S. Geological Survey 

Water-Supply Paper 2181. 

Barnes, 1., and McCoy, G.A., 1979, Possible role of mantle-derived C02 in causing two "phreatic''' explosions in Alaska: 

Geology, v. 7, no. 9, p. 434-435. 

Beebe, B.W., and Curtis, B.F., 1968, Natural gases of North 

America-A Summary, in Beebe, B.W., and Curtis, B.F., 

eds., Natural gases of North America: American Association 

of Petroleum Geologists Memoir 9, p. 2245-2355. 

Bell, D.R., 1992, Water in mantle minerals: Nature, v. 357, 

p. 646-647. 

Bezrodnov, V.D., 1979, Subsurface chloride waters of the Kola 

Peninsula: International Geology Review, v. 24, no. 5, 

p. 533-540. 

Blundy, J.D., Broadholt, J.P., and Wood, B.J., 1991, Carbon-fluid 

equilibria and the oxidation state of the upper mantle: Nature, v. 349, p. 321-324. 

Bluth, G.J.S., Doiron, S.D., Schnetzler, C.C., Kreuger, A.J., and 

Walter, L.S., 1992, Global tracking of the S02 clouds from 

the June 1991 Mount Pinatubo eruptions: Geophysical Research Letters, v. 19, p. 151. 

Bosch, A., Bayer, R., Schlosser, P., Sana, Y., Wakita, H., and 

Mazor, E., 1989, Mantle helium detected in oil and gas reservoirs of Israel: Israel Geological Survey, Annual Meeting 

1989, p. 22-24. 

Bowen, N.L., and Tuttle, O.F., 1949, The system MgO-SiOr 

H20: Bulletin of the Geological Society of America, v. 60, 

p. 439--460. 

Bratus, M.D., Tatarintsev, V.I., and Sakhro, B.E., 1987, Fluidinclusion compositions in chilled particles from explosive 

ring structures and kimberlite pipes: Geochemistry International, p. 50-55. 

Broadhead, -R.F., 1985, Enhanced oil recovery with carbon dioxide flooding in New Mexico: New Mexico Geology, v. 7, 

no. 1, p. 10. 

---1987, Carbon Dioxide in Union and Harding Counties, in 

New Mexico Geological Society Guidebook, 38th Field 

Conference, p. 339-349. 

---1990, Bravo Dome carbon dioxide gas field, in Beaumont, E.A., and Foster, N.H., eds., Treatise of petroleum geology, atlas of oil and gas fields-Structural traps I, Tectonic 

fold traps: American Association of Petroleum Geologists, 

p. 213-232. 

Brown, K.M., 1990, The nature and hydrologic significance of 

mud diapirs and diatremes for accretionary systems: Journal 

of Geophysical Research, v. 95, no. B6, p. 8969-8982. 

Cady, W.M., Albee, A.L., and Chidester, A.H., 1963, Bedrock geology and asbestos deposits of the upper Mississquoi Valley 

and vicinity, Vermont: U.S. Geological Survey Bulletin 

1122-B, p. BI-B78. 

Casadevall, T.J ., and Greenland, L.P., 1982, The chemistry of 

gases emanating from Mount St. Helens, May-September 
124 THE FUTURE OF ENERGY GASES 

1980, in Lipman, P.W., and Mullineaux, D.R., eds., The 

1980 eruptions of Mount St. Helens, Washington: U.S. Geological Survey Professional Paper 1250, p. 221-226. 

Casey, T.A.L., 1983, Helium potential of the Four Comers Area, 

in Oil and gas fields of the Four Corners Area: Four Comers 

Geological Society, v. 3, p. 749-754. 

Carmichael, l.S.E., 1991, The redox states of basic and silicic 

magmas-A reflection of their source regions?: Contributions to Mineralogy and Petrology, v. 106, p. 129-141. 

Castano, J.R., 1990, Geochemistry of the Gravberg-1 well: Sector Report, Deep Gas Project, Vattensall RD&D Report 

U(G) 1990/61, 86 p. 

Chaigneau, M., 1975, Essai sur Ia composition des gaz magmatiques profonds: Bulletin Volcanologique, v. 39, no. 3, 

p. 407-419. 

Chaigneau, M., Tazieff, H., and Fabre, R., 1960, Composition 

des gaz volcaniques du lac de lave permanent de Nyiragongo (Congo Beige): Comptes Rendus de l'Academie des Sciences, Paris, Serie D., v. 250, p. 2482-2485. 

Chang, S., DesMarais, D., Mack, R., Miller, S.L., and Strathearn, 

G.F., 1983, Prebiotic organic syntheses and the origin of life, 

in Schopf, J.W., ed., Earth's earliest biosphere: Princeton, 

New Jersey, Princeton University Press, p. 53-92. 

Charlou, J.L., Bougault, H., Appriou, P., Jean-Baptiste, P., Etoubleau, J., and Birolleau, A., 1991a, Water column anomalies 

associated with hydrothermal activity between II· 40' and 

13•N on the East Pacific Rise-Discrepancies between tracers: Deep-Sea Research, v. 38, p. 569-596. 

Charlou, J.L., Bougault, H., Appriou, P., Nelsen, T., and Rona, P., 

199lb, Different TDM/CH4 hydrothermal plume signatures-TAG site at 26.N and serpentinized ultrabasic diapir 

at 15"05'N on the Mid-Atlantic Ridge: Geochimica et Cosmochimica Acta, v. 55, p. 3209-3222. 

Charlou, J.L., Bougault, H., and FARANAUT Scientific Party, 

1992, Intense CH4 plumes in seawater associated to ultramafic 

outcrops at 15"N on the Mid-Atlantic Ridge: American Geophysical Union [abstract], 1992 Fall Meeting Program, p. 585. 

Charlou, J.L., and Donval, J.P., In press, Hydrothermal methane 

venting between 12•N and 26•N along the Mid-Atlantic 

Ridge: Journal of Geophysical Research. 

Chivas, A.R., Barnes, 1., Evans, W.C., Lupton, J.E., and Stone, 

J .0., 1987, Liquid carbon dioxide of magmatic origin and its 

role in volcanic eruptions: Nature, v. 326, p. 587-589. 

Christensen, V.R., 1989, Models of mantle convection-One or 

several layers: Royal Society of London, Philosophical 

Transactions, Series A, v. 328, p. 417-424. 

Clarke, W.B., Beg, M.A., and Craig, H., 1969, Excess 3He in the 

sea-Evidence for terrestrial primordial helium: Earth and 

Planetary Science Letters, v. 6, p. 213-220. 

Coveney, R.M., Jr., Goebel, E.D., Zeller, E.J., Dreschhoff, 

G.A.M., and Angino, E.E., 1987, Serpentinization and the 

origin of hydrogen gas in Kansas: American Association of 

Petroleum Geologists Bulletin, v. 71, no. I, p. 39-48. 

Delaney, J.M., and Helgeson, H.C., 1978, Calculation of the thermodynamic consequences of dehydration in subducting oceanic crust to 100Kb and >8oo·c:· American Journal of 

Science, v. 278, p. 638-686. 

Deutsch, E.R., Rao, K.V., Laurent, R., and Sequin, M.K., 1977, 

New evidence and possible origin of native iron in ophiolites of eastern Canada: Nature, v. 269, p. 684-685. 

Dewars, T., and Ortoleva, P., 1988, The role of geochemical selforganization in the migration and trapping of hydrocarbons: 

Applied Geochemistry, v. 3, p. 287-316. 

Dobbin, C.E., 1935, Geology of natural gases rich in helium, nitrogen, carbon dioxide, and hydrogen sulfide, in Geology of 

natural gas: American Association of Petroleum Geologists, 

p. 1053-1072. 

Douglas, R.J.W., 1969, Geology and economic minerals of Canada: Ottawa, Geological Survey of Canada, Economic Geology Report No. I, 838 p. 

Dubessy, J., Pagel, M., Beny, J.M., Christensen, H., Hickel, B., 

Kosztolanyi, C., and Poty, B., 1988, Radiolysis evidenced 

by HrOrbearing fluid inclusions in three uranium deposits: 

Geochimica et Cosmochimica Acta, v. 52, p. 1155-1167. 

Dunai, T.J., Rouret, J.L., and Villa, l.M., 1992, Mantle derived 

helium in fluid inclusions of a 2.5 Ga old granulite, Nilgiri 

Hills, southern India, in Kharaka, Y.K., and Maest, J., eds., 

Water-rock interaction: Rotterdam, A.A. Balkema, p. 919-922. 

Dyar, M.D., McGuire, A.V., and Mackwell, S.J., 1992, Fe3+JH+ 

and D/H in kaersutites-Misleading indicators of mantle 

source fugacities: Geology, v. 20, p. 565-568. 

Echevarria-Rodriguez, G., Hernandez-Perez, G., Lopez-Quintero, 

J.O., Lopez-Rivera, J.G., Rodriguez-Hernandez, R., 

Sanchez-Arango, J.R., Socorro-Trujillo, R., Tenreyro-Perez, 

R., and Yparraguirre-Pena, J.L., 1991, Oil and gas exploration in Cuba: Journal of Petroleum Geology, v. 14, p. 259-

274. 

Eckstrand, O.R., 1975, The Dumont serpentinite-A model for 

control of nickeliferous opaque mineral assemblages by alteration reactions in ultramafic rocks: Economic Geology, 

v. 70, p. 183-20 I. 

Edmister, W.C., 1968, Corresponding state version of the Redlich 

Kwong equation: Hydrocarbon Processing, v. 47, p. 239. 

Edwards, A.C., Lovering, J.F., and Ferguson, J., 1979, High pressure basic inclusions from the Kayrunnera kimberlitic diatreme in New South Wales, Australia: Contribution to 

Mineralogy and Petrology, v. 69, no. 2, p. 185-192. 

Eisma, E., and Jurg, J.W., 1969, Fundamental aspects of the generation of petroleum, in Eglinton, G., and Murphy, M.T.J., 

eds., Organic Geochemistry-Methods and Results, Chapter 

28, p. 676-698. 

Elderfield, H., Kastner, M., and Martin, J.B., 1990, Compositions 

and sources of fluids in sediments of the Peru subduction 

zone: Journal of Geophysical Research, v. 95, no. B6, 

p. 8819-8827. 

Elliott, W.C., Grandstaff, D.E., Ulmer, G.C., Buntin, T., and 

Gold, D.P., 1982, An intrinsic oxygen fucacity study of platinum-carbon associations in layered intrusions: Economic 

Geology, v. 77, p. 1493-1510. 

Ernst, W.G., 1990, Thermobarometric and fluid expulsion history 

ofsubduction zones: Journal of Geophysical Research, v. 95, 

no. B6,p.9047-9053. 

Faber, E., and Whiticar, M.J., 1989, C- und H-isotope in leichtfluchige Kohlenwasserstoffen der KTB: KTB Report. 

Fanale, F.P., 1971, A case for catastrophic early degassing of the 

Earth: Chemical Geology, v. 8, p. 79-105. 

Fisher, D.M., and Brantley, S.L., 1992, Models of quartz overgrowths and vein formation-Deformation and episodic 

fluid flow in an ancient subduction zone: Journal of Geophysical Research, v. 97, no. Bl3, p. 20043-20061. 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 125 

Flowers, G.C., 1979, Correction of Holloway's 1977 adaptation 

of the modified Redlich-Kwong equation of state for calculation of the fugacities of molecular species in supercritical 

fluids of geologic interest: Contributions to Mineralogy and 

Petrology, v. 69, p. 315-318. 

Frape, S.K., Fritz, P., and McNutt, R.H., 1984, Water-rock interaction and chemistry of groundwaters from the Canadian 

Shield: Geochim. Cosmochim. Acta, v. 48, p. 1617-1627. 

- Fritz, P., Clark, I.D., Fontes, J.C., Whiticar, M.J., and Faber, E., 

1992, Deuterium and 13C evidence for low temperature production of hydrogen and methane in a highly alkaline 

groundwater environment in Oman, in Kharaka, Y.R., and 

Maest, J.S., eds., Water-rock interaction: Rotterdam, A.A., 

Balkema, p. 793-796. 

Fritz, P., and Frape, S.K., eds., 1987, Saline water and gases in 

crystalline rocks: Geological Association of Canada Special 

Paper 33, 259 p. 

Fritz, P., Frape, S.K., and Miles, M., 1987, Methane in the Crystalline rocks of the Canadian Shield, in Fritz, P., and Frape, 

S.K., eds., Saline water and gases in crystalline rocks: Geological Association of Canada Special Paper 33, p. 211-223. 

Fryer, P., Ambos, E.L., and Hussong, D.M., 1985, Origin and 

emplacement of Mariana forearc seamounts: Geology, v. 13, 

p. 774-777. 

Gabelman, J.W., 1977, Migration of uranium and thorium-Exploration significance, Studies in Geology No. 3: American 

Association of Petroleum Geologists, Tulsa, Oklahoma, 

168 p. 

Galimov, E.M., and Petersil'ye, I.A., 1967, Isotopic composition 

of carbon from hydrocarbon gases and C02 held in alkalic 

igneous rocks of the Khibiny, Lovozero, and Illimaussak 

plutons: Doklady Akademii Nauk SSSR, v. 176, p. 200-203. 

[English translation.] 

Gephart, R.E., Leonhard, L.S., Spane, F.A., Jr., and Strait, S.R., 

1979, Ch. III, Pasco Basin Hydrology, in Hydrologic Studies 

within the Columbia Plateau, Washington-An integration 

of current knowledge, RHO-BWI-ST-S: Rockwell Hanford 

Operations, Richland, Washington, 236 p. 

Gerlach, T.M., 1980, Chemical characteristics of the volcanic 

gases from Nyiragongo lava lake and the generation of CH4_ 

rich fluid inclusions in alkaline rocks. Journal of Volcanology and Geothermal Research, v. 8, p. 177-189. 

---1993, Oxygen buffering of Kilauea volcanic gases and 

the oxygen fugacity of Kilauea basalt: Geochimica et Cosmochimica Acta, v. 57, p. 795-814. 

Gerlach, T.M., and Nordlie, B.E., 1975a, The C-0-H-S gaseous 

system-Part I, Composition limits and trends in basaltic 

cases: American Journal of Science, v. 275, p. 353-376. 

---1975b, The C-0-H-S gaseous system-Part II, Temperature, atomic composition, and molecular equilibria in volcanic gases: American Journal of Science, v. 275, p. 377-394. 

---1975c, The C-0-H-S gaseous system-Part III, Magmatic 

gases compatible with oxides and sulfides in basaltic magmas: American Journal of Science, v. 275, p. 395-410. 

Giardini, A.A., and Melton, C.E., 1981, Experimentally-based arguments supporting large crustal accumulations of non-biogenic petroleum: Journal of Petroleum Geology, v. 4, no. 2, 

p. 187-190. 

Giardini, A.A., Melton, C.E., and Mitchell, R.S., 1982, The nature of the upper 400 km of the Earth and its potential as the 

source for non-biogenic petroleum: Journal of Petroleum 

Geology, v. 52, p. 173-190. 

Giardini, A.A., Subbarayudu, G.V., and Melton, C.E., 1976, The 

emission of occluded gas from rocks as a function of 

stress-Its possible use as a tool for predicting earthquakes: 

Geophysical Research Letters, v. 3, p. 355-358. 

Giggenbach, W.F., 1990, Water and gas chemistry of Lake Nyos 

and its bearing on the eruptive process: Journal of Volcanology and Geothermal Research, v. 42, p. 337-362. 

Glassley, W., 1982, Fluid evolution and graphite genesis in the 

deep continental crust: Nature, v. 295, p. 229-231. 

Gold, Thomas, 1978, Terrestrial sources of carbon and Earthquake outgassing, paper presented at International Scientific 

Forum on an Acceptable World Energy Future, University of 

Miami, Florida, Nov. 27-Dec. I, 1978. 

---1979a, Terrestrial sources of carbon and Earthquake outgassing: Journal of Petroleum Geology, v. 2, p. 3-19. 

---1979b, The Earthquake evidence for Earth gas, presented 

at Conference on Energy for Survival, Sydney, Australia, 

Aug. 27-Sept. 7: Pergamon Press, p. 65-78. 

---1980, Outgassing and the power source for plate tectonics, 

presented at the NATO advanced study institute on the mechanism of continental drift and plate tectonics, Newcastle on 

Tyne, United Kingdom, March 27-AprillO, 1979, p. 343-344. 

---1987, Power from the Earth-Deep Earth gas energy for 

the future: London, J.M. Dent and Sons, 197 p. 

Gold, T., and Held, M., 1987, Helium-nitrogen-methane systematics in natural gases of Texas and Kansas: Journal of Petroleum Technology, v. 10, p. 415-424. 

Gold, T., and Soter, S., 1980, The deep-Earth-gas hypothesis: 

Scientific American, v. 243, p. 154-170. 

Gol'dberg, l.S., and Chernikov, K.A., 1969, The nature of bitumens in the alkalic and ultramafic rocks of the northern part 

of the Siberian Platform: Geochemistry International, v. 5, 

p. 402-407. 

Goldstein, J.l., 1964, The growth of the Widmanstatten pattern in 

metallic meteorites: Cambridge, Mass., Massachusetts Institute of Technology, doctoral thesis, 122 p., plus appendix. 

Green, D. H., Falloon, T. J., and Taylor, W. R., 1987, Mantlederived magmas-Roles of variable source peridotite and 

variable C-H-0 fluid compositions, in Bysen, B.O., ed., 

Magmatic Processes: Physicochemical Principles, no. 1, 

p. 139-154. 

Green, D.H, Taylor, W.R., and Foley, S., 1990, The Earth's upper 

mantle as a source for volatiles, in Herbert, H.K., and Ho, 

S.E., eds., Stable isotopes and fluid processes in mineralization: Queensland, Geology Department and University Extension, University of Western Australia, v. 23, p. 17-34. 

Green, H.W., and Radcliffe, S.V., 1975, Fluid precipitates in 

rocks from the Earth's mantle: Bulletin of the Geological 

Society of America, v. 86, p. 846-852. 

Griesshaber, E., O'Nions, R.K., and Oxburgh, E.R., 1992, Helium and carbon isotope systematics in crustal fluids from the 

Eifel, the Rhine Graben and Black Forest, F.R.G.: Chemical 

Geology, v. 99, p. 213-235. 

Grudinin, M.l., and Sekerin, A.P., 1979, Native iron in ultramafic 

rocks of the Shamanskiy pluton: Doklady Akademia Nauk 

SSSR, v. 245, p. 160-162. [English translation.] 

Guha, J., and Kanwar, R., 1987, Vug brines-fluid inclusions-A 

key to the understanding of secondary gold enrichment 
126 THE FUTURE OF ENERGY GASES 

processes and the evolution of deep brines in the Canadian 

Shield, in Fritz, P., and Frape, S.K., eds., Saline water and 

gases in crystalline rocks: Geological Association of Canada, 

Special Paper 33, p. 89-95. 

Gurko, N.N., Marrero, M., and Principe, M., 1982, Influence of 

secondary factors on the light hydrocarbon composition of 

oils in the central depression of Cuba: International Geology 

Review, v. 24, no. 1, p. 99-104. 

Gwilliam, W.J., 1982, Subducted organic origin gas hypothesis 

for deep source methane, Chapter 3.9, in Deep-Source Gas 

Workshop Technical Proceedings, Morgantown Energy 

Technology Center: Morgantown, West Virginia, U.S. Department of Energy, Report DOE/METC/82-50, p. 140-161. 

Haggerty, J .A., 1991, Evidence from fluid seeps atop serpentine 

seamounts in the Mariana Forearc-Clues for emplacement 

of the seamounts and their relationship to forearc tectonics: 

Marine Geology, v. 102, p. 293-309. 

Haggerty, S.E., 1986, Diamond genesis in a multiply constrained 

model: Nature, v. 320, p. 34-38. 

---1987, Source regions of oxides, sulfides and metals in the 

upper mantle-Clues to the stability of diamonds, and the 

genesis of kimberlites, lamproites and carbonatites, in Fourth 

International Kimberlite Conference, Perth: Geological Society of Australia, Extended Abstracts, no. 16, p. 250-251. 

Hahn-Weinheimer, P., and Rost, F., 1961, Akzessorische Mmiperalen und Elemente in Serpentinit von Leupoldgrun 

(Munchberger Greissmasse), Ein Beitrag zur Geochimie ultabasischer Gesteine: Geochimica et Cosmochimica Acta, 

v.2l,p.l65-181. 

Harris, D.M., Sato, M., Casadevall, T.J., Rose, W.l., Jr., and 

Bornhorst, T.J., 1982, Emission rates of C02 from plume 

measurements, in Lipman, P.W., and Mullineaux, D.R., eds., 

The 1980 eruptions of Mount St. Helens, Washington: U.S. 

Geological Survey Professional Paper 1250, p. 201-207. 

Headlee, A.J.W., 1962, Carbon dioxide, nitrogen crucial to oil 

migration?: World Oil, October, p. 126-144. 

Hedberg, H., 1970, Continental margins from viewpoint of the 

petroleum geologist: Bulletin of the American Association of 

Petroleum Geologists, v. 54, p. 3-43. 

Henry, P., Le Pichon, X., Lallement, S., Foucher, J.P., Westbrook, 

G., and Hobart, M., 1990, Mud volcano field seaward of the 

Barbados accretionary complex-A deep-towed side scan 

sonar survey: Journal of Geophysical Research, v. 95, 

no. B6, p. 8917-8929. 

Hirono, M., and Shibata, T., 1983, Volcanic eruptions observed 

by laser radar, Bulletin of the Volcanological Society of 

Japan, v. 28, no. 4,p. 337-356. 

Hiyagon, H., and Kennedy, B.M., 1992, Noble gases in CH4-rich 

gas fields, Alberta, Canada: Geochimica et Cosmochimica 

Acta, v. 56, p. 1569-1589. 

Hofmann, A.W., 1989, Geochemistry and models of mantle circulation: Philosophical Transactions of the Royal Society of 

London,v.A328,p.425-439. 

Holland, H.D., 1978, The chemistry of the atmosphere and 

oceans: New York, Wiley. 

---1984, The chemical evolution of the atmosphere and 

oceans: Princeton, N.J., Princeton University Press, 582 p. 

Holloway, J .R., 1977, Fugacity and activity of molecular species 

of supercritical fluids, in Fraser, D.G., ed., Thermodynamics 

in geology: Reidel, p. 161-181. 

Hooker, P.J., O'Nions, R.K., and Oxburgh, E.R., 1985, Helium 

isotopes in North Sea gas fields and the Rhine rift: Nature, 

v. 318, p. 273-275. 

Hottman, C.E., Smith, J.A., and Purcell, W.R., 1979, Relationships among Earth stresses, pore pressure, and drilling problems offshore Gulf of Alaska: Journal of Petroleum 

Technology, v. 31, p. 1477-1484. 

Hunt, J .M., 1990, Generation and migration of petroleum from 

abnormally pressured fluid compartments: American Association of Petroleum Geologists Bulletin, v. 74, no. 1, p. 1-12. 

Ikorskiy, S.V, and Shugurova, N.A., 1975, Gas composition in 

Khibiny alkali-rock minerals: Geochemistry International, 

v. 11, no. 3, p. 671. 

Illies, J.H., Prodehl, C., Schmincke, H.U., and Semmel, A., 1979, 

The Quaternary uplift of the Rhenish Shield in Germany: 

Tectonophysics, v. 61, p. 197-225. 

Jean-Baptiste, P., Charlou, J.L., Stievenard, M., Donval, J.P., 

Bougault, H., and Mevel, C., 1991, Helium and methane 

measurements in hydrothermal fluids from the Mid-Atlantic 

Ridge-The Snake Pit site at 23"N: Earth and Planetary Science Letters, v. 106, p. 17-28. 

Jeanloz, R., and Knittle, E., 1989, Density and composition of 

the lower mantle: Philosophical Transactions, Royal Society 

of London, series A, v. 328, p. 377-389. 

Jeffrey, A.W.A., and Kaplan, I.R., 1988, Hydrocarbons and inorganic gases in the Gravberg-1 well, Siljan Ring, Sweden: 

Chemical Geology, v. 71, p. 237-255. 

Jeffrey, A.W.A., Kaplan, I.R., Poreda, R., and Craig, H., 1988, 

The origin of natural gases from convergent margins: Paper 

presented at V.M. Goldschmidt Conference, Geochemical 

Society, Baltimore, Maryland. · 

Jenden, P.O., Newell, K.D., Kaplan, I.R., and Watney, W.L., 

1988a, Composition and stable isotope geochemistry of natural gases from Kansas, Midcontinent, U.S.A.: Chemical 

Geology, v. 71, p. 117-147. 

Jenden, P.O., Kaplan, I.R., Poreda, R.J., and Craig, H., 1988b, 

Origin of natural gases in the California Great Valley-Evidence from helium, carbon and nitrogen isotope ratios: 

Geochimica et Cosmochimica Acta, v. 52, p. 851-861. 

Johan, Z., and LeBel, L., 1980, Genese des couches et podes de 

chromite dans les complexes ophiolitiques: International 

Geological Congress Abstracts, Resumes 26, v. 3, p. 950 

Johnson, J.W., Oelkers, E.H., and Helgeson, H.C., 1992, 

SUPCRT92-A software package for calculating the standard molal thermodynamic properties of minerals, gases, 

aqueous species, and reactions from 1 to 5000 bars and o· to 

I OOO"C: Computers and Geosciences. 

Kasting, J.F., and Ackerman, T.P., 1986, Climatic consequences 

of very high carbon dioxide levels in the Earth's early atmosphere: Science, v. 234, p. 1383-1385. 

Kennedy, B.M., Poths, J., and Hiyagon, H., 1992, Anomalous 

3He contents of CH4-rich gases in sedimentary basins, in 

Kharaka, Y.K., and Maest, J., eds., Water-Rock Interaction: 

Rotterdam, Balkema, p. 947-950. 

Kogarko, L.N., 1987, Alkaline rocks of the eastern part of the 

Baltic Shield (Kola Peninsula), in Fitton, J.G., and Upton, 

B.G.J., eds., Alkaline Igneous Rocks: Geological Society of 

London Special Publication No. 30, p. 531-544. 

Kogarko, L.N., and Romanchev, B.P., 1977, Temperature, pressure, redox conditions, and mineral equilibrium in agpaitic 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 127 

nepheline syenites and apatite-nepheline rocks: Geochemistry International, v. 14, p. 113-128. 

Komor, S.C., Valley, J.W., Brown, P.E., and Collini, B., 1988, 

Fluid inclusions in Granite from the Siljan Ring Impact 

Structure and surrounding regions, in Boden, A., and Eriksson, K.G., eds., Deep drilling in crystalline bedrock: Berlin, 

Springer-Verlag, p. 180-208. 

Konnerup-Madsen, J., Kreulen, R., and Rose-Hansen, J., 1988, 

Stable isotope characteristics of hydrocarbon gases in the alkaline Ilimaussaq complex, south Greenland: Bulletin of 

Mineralogy, v. Ill, p. 567-576. 

Konnerup-Madsen, J., Larsen, E., and Rose-Hansen, J., 1979, 

Hydrocarbon-rich fluid inclusions in minerals from the alkaline llimaussaq intrusion, South Greenland: Bulletin Mineralogique, v. 102, p. 642-653. 

Konnerup-Madsen, J., and Rose-Hansen, J., 1982, Volatiles associated with alkaline igneous rift activity-Fluid inclusions in 

the Ilimaussaq intrusion and the Gardar granitic complexes 

(South Greenland), in Kreulen, R., and Touret, J., eds., Current research on fluid inclusions: Chemical Geology, v. 37, 

p. 79-93. 

Kotra, J.P., Finnegan, D.L., and Zoller, W.H., 1983, El Chichon-Composition of plume gases and particles: Science, 

v. 222, p. 1018-1021. 

Kravtsov, A.l., Voytov, G.l., Fridman, A.l., Grechukhina, T.G., 

Linde, I.F., and Polyanskiy, M.N., 1967, Hydrogen content 

of gas streams in Khibiny: Doklady Akademii Nauk SSSR, 

v. 177, p. 1190-1192. [English translation.] 

Kravtsov, A.l., Voytov, G.I., Bobrov, A.P., Akimov, A.N., Ivanov, 

A.N., and Serdyukov, L.l., 1979, Composition and isotopes 

of gases in the Mir kimberlite pipe: Doklady Akademii 

Nauk SSSR, v. 2454, p. 950-953. 

Kravtsov, A.I., Voytov, G.l., Ivanov, V.A., and Kropotova, 0.1., 

I 976, Gases and bitumens in rocks of the Udachnaya pipe: 

Doklady Akademii Nauk SSSR, v. 228, p. 231-234. [English translation.] 

Kreulen, R., and Schuiling, R.D., 1982, NTCH4-C02 fluids during formation of the Dome de I' Agout, France: Geochimica 

et Cosmochimica Acta, v. 46, p. 193-203. 

Krishnarao, J.S.R., 1964, Native nickel-iron alloy-Its mode of 

occurrence, distribution and origin: Economic Geology, 

v. 59, p. 443-448. 

Krivanek, C.M., 1978, McElmo Field, in Fasset, J.E., and Thomaidis, N.D.; eds., Oil and gas fields of the Four Corners 

Area: Four Corners Geological Society, p. 148-151. 

Kulm, L.D., and Suess, E., 1990, Relationship between carbonate 

deposits and fluid venting-Oregon accretionary prism: Journal of Geophysical Research, v. 95, no. B6, p. 8899-8915. 

Kulm, L.D., Suess, E., Moore, J.C., Carson, B., Lewis, B.T., Ritger, S.D., Kadko, D.C., Thornburg, T.M., Embley, R.W., 

Rugh, W.D., Massoth, G.J., Langseth, M.G., Cochrane, 

G.R., and Scamman, R.L., 1986, Oregon subduction zoneVenting, fauna, and carbonates: Science, v. 231, p. 561-566. 

Kusakabe, M., Oshumi, T., and Aramaki, S., 1989, The Lake 

Nyos gas disaster-Chemical and isotopic evidence in waters and dissolved gases from three Cameroonian crater 

lakes, Nyos, Monoun, and Wum: Journal of Volcanology 

and Geothermal Research, v. 39, p. 167-185. 

K venvolden, K.A., and Field, M.E., 1981, Thermogenic hydrocarbons in unconsolidated sediment of Eel River Basin, offshore Northern California: Bulletin of the American 

Association of Petroleum Geologists, v. 65, p. 1642-1646. 

Lahermo, P.W., and Lampen, P.H., 1987, Brackish and saline 

groundwaters in Finland, in Fritz, P., and Frape, S.K., eds., 

Saline waters and gases in crystalline rocks: Geological Association of Canada Special Paper 33, p. 103-110. 

Langseth, M.G., Westbrook, G.K., and Hobart, M.A., 1988, Geophysical survey of a mud volcano seaward of the Barbados 

Ridge accretionary complex: Journal of Geophysical Research, v. 93, no. B2, p. 1049-1061. 

Larson, L.M., 1976, Clinopyroxene and coexisting mafic minerals from the alkaline Ilimaussaq intrusion, south Greenland: 

Journal of Petrology, v. 17, p. 258-290. 

Le Guern, F., Tazieff, H., and Faivre Pierret, R., 1982, An example of health hazard-People killed by gas during a phreatic 

eruption, Dieng Plateau (Java, Indonesia), February 20, 

1979: Bulletin Volcanologique, v. 45, p. 153-156. 

Le Pichon, X., Foucher, J.P., Boulegue, Henry, P., Lallement, S., 

Benedetti, M., Avedik, F., and Mariotti, A., 1990, Mud volcano field seaward of the Barbados accretionary complexA submersible survey: Journal of Geophysical Research, 

v.95, no. B6, p. 8931-8943. 

Leung, I., Guo, W., Friedman, 1., and Gleason, J., 1990, Natural 

occurrence of silicon carbide in a diamondiferous kimberlite 

from Fuxian: Nature, v. 346, p. 352-354. 

Lovering, J.F., and White, A.J.R., 1964, The significance of primary scapolite in granulitic inclusions from deep-seated 

pipes: Journal of Petrology, v. 5:2, p. 195-218. 

---1969, Granulitic and eclogitic inclusions from basic pipes 

at Delegate, Australia: Contributions to Mineralogy and Petrology, v. 21, no. I, p. 9-52. 

Lyon, G.L., and Hulston, J .R., 1984, Carbon and hydrogen isotopic compositions of New Zealand geothermal gases: 

Geochimica et Cosmochimica Acta, v. 48, p. I I 61-1171. 

Lutts, B.G., Petersil'ye, I.A., and Karzhavin, V.K., 1976, Composition of gases in rocks of the upper mantle: Doklady 

Akademii Nauk SSSR, v. 226, [English translation], p. 197-

200. 

MacDonald, G.J ., I 988, Major questions about deep continental 

structures, in Boden, A., and Eriksson, K.G., eds., Deep 

drilling in crystalline bedrock, Volume !-The Deep Gas 

Drilling in the Siljan Impact Structure, Sweden and Astroblemes: Berlin, Springer-Verlag, p. 28-48. 

Mack well, S.J ., 1991, Diffusion of hydrogen in enstatite-Implications for the presence of water in the mantle, [abstract]: 

Eos, American Geophysical Union Spring Meeting 1991, 

Program and Abstracts, April 23, 1991, p. 143. 

Mackwell, S.J., and Kohlstedt, D.L., 1990, Diffusion of hydrogen in olivine-Implications for water in the mantle: Journal 

of Geophysical Research, v. 95, no. B4, p. 5079-5088. 

Maksimov, S.N., Muller, E., Botneva, T.A., Goldbecher, K., 

Zor'kin, L.M., and Pankina, R.G., 1976, Origin of high-nitrogen gas pools: lntern·ational Geology Review, v. 18, 

p. 551-556. 

Mamyrin, B.A., and Tolstikhin, LN., 1984, Helium isotopes in 

nature, in Developments in geochemistry, v. 3: Amsterdam, 

Elsevier, 273 p. 

Marakushev, A.A., 1981, The fluid regime in the formation of 

diamond-containing rock: International Geology Review, 

v. 24, no. 11, p. 1241-1252. 
128 THE FUTURE OF ENERGY GASES 

Mareschal, M., Fyfe, W.S., Percival, J., and Chan, T., 1992, 

Grain boundary graphite in Kapuskasing gneisses and implications for lower crustal conductivity: Nature, v. 357, 

no. 6380, p. 674-fJ765. 

Marland, G., 1984, A workshop on the origin of natural gas, 

Gas Research Institute Report No. GRI-84/0166: Chicago, 

Ill., Gas Research Institute. 

Marty, B., 1989, On mantle carbon flux calculated: Eos, Transactions of the American Geophysical Union, v. 70, no. 1, p. I. 

Marty, B., and Jambon, A., 1987, cPHe in volatile fluxes from 

the solid Earth-Implications for carbon geodynamics: Earth 

and Planetary Science Letters, v. 83, p. 16-26. 

Mathews, J.F., 1972, The critical constants of inorganic substances: Chemical Reviews, v. 72, p. 71-1 00. 

Mathez, E.A., 1984, Influence of degassing on oxidation states of 

basaltic magmas: Nature, v. 310, p. 371-375. 

---1984, Influence of degassing on oxidation states of basaltic magmas: Nature, v. 310, p. 371-375. 

Mathez, E.A., Dietrich, V.J., Holloway, J.R., and Boudreau, A.E., 

1989, Carbon distribution in the Stillwater complex and evolution of vapor during crystallization of Stillwater and Bushveld magmas: Journal of Petrology, v. 30, p. 153-173. 

Matthews, A., Fouillac, C., Hill, R., O'Nions, R.K., and Oxburgh, E.R., 1987, Mantle-derived volatiles in the continental crust-The Massif Central of France: Earth and Planetary 

Science Letters, v. 85, p. 117-128. 

Matsui, T. and Abe, Y., 1986a, Evolution of an impact-induced 

atmosphere and magma ocean on the accreting Earth. Nature, v. 319, p. 303-305. 

---1986b, Impact-induced atmospheres and oceans on Earth 

and Venus: Nature, v. 322, p. 526-528. 

McCammon, C., 1993, Effect of pressure on the composition of 

the lower mantle end member Fe,O: Science, v. 259, p. 66-

68. 

McGetchin, T.R., and Besancon, J.R., 1983, Carbonate inclusions 

in mantle derived pyropes: Earth and Planetary Science Letters, v. 18, p. 408-410. 

McGetchin, T.R., Nikhanj, Y.S., and Chodos, A.A., 1973, Carbonatite-Kimberlite relations in the Cane Valley Diatreme, 

San Juan County, Utah: Journal of Geophysical Research, 

v. 78, p. 1854-1869. 

McGetchin, T.T., and Silver, L.T., 1970, Compositional relations 

in minerals from kimberlite and related rocks from the 

Moses Valley dike, San Juan County, Utah: American Mineralogist, v. 55, p. 1738-1771. 

McGetchin, T.R., and Ullrich, G.W., 1973, Xenoliths in maars 

and diatremes with inferences for the Moon, Mars, and 

Venus: Journal of Geophysical Research, v. 78, p. 1833-

1853. 

McKenny, J.W., and Masters, J.A., 1968, Dineh-bi-Keyah field, 

Apache County, Arizona: American Association of Petroleum Geologists Bulletin, v. 52, p. 2045-2057. 

Melchanov, V.I., 1967, Experimental synthesis of hydrocarbons 

by fine grinding of mineral matter in water: Doklady Akademii Nauk SSSR, v. 174, p. 194-196. [English translation.] 

Moore, J.C., Biju-Duval, B., Bergen, J.A., Blackington, G., Claypool, G.E., Cowan, D.S., Deunneiber, F., Guerra, R.T., Hemleben, C.H.J., Hussong, D., Marlow, M.S., Natland, J.S., 

Pudsey, C.J., Renz, G.W., Tardy, M., Willis, M.E., Wilson, 

D., and Wright, A.A., 1982, Offscraping and underthrusting 

of sediment at the deformation front of the Barbados Ridge: 

Deep Sea Drilling Project Leg 78A: Geological Society of 

America Bulletin, v. 93, p. 1065-1077. 

Moore, J.C., Orange, D., and Kulm, L.D., 1990, Interrelationship of 

fluid venting and structural evolution-Alvin observations 

from the frontal accretionary prism, Oregon: Journal of Geophysical Research, v. 95, no. B6, p. 8795-8808. 

Mueller, R.F., 1971, Oxidative capacity of magmatic components: 

American Journal of Science, v. 270, p. 236-243. 

Murck, B.W., Burruss, R.C., Hollister, L.S., 1978, Phase equilibria 

in fluid inclusions in ultramafic xenoliths: American Mineralogist, v. 63, p. 40-46. 

Myers, G., 1987, Fluid expulsion during underplating of the Kodiak 

Formation-A fluid inclusion study: M.S. thesis, University of 

California, Santa Cruz. 

Nash, J.T., Granger, H.C., and Adams, S.S., 1981, Geology and 

concepts of genesis of important types of uranium deposits, in 

Skinner, B.J., ed., Economic Geology 75th Anniversary Vol-· 

ume, 1905-1980, p. 63-116. 

Neal, C., and Stanger, G., 1983, Hydrogen generation from mantle 

source rocks in Oman: Earth and Planetary Science Letters, 

v. 66, p. 315-320. 

Neil, J .M., and Apps, J .A., 1981, Results of albite stability measurements as a function of temperature (125-350"C): Annual Report 1980, Earth Science Division, Lawrence Berkeley 

Laboratory Report LBL12100, p. 41-43. 

Nellis, W.J., Ree, F.H., van Thiel, M., and Mitchell, A.C., I98I, 

Shock compression of liquid carbon monoxide and methane to 

90 GPa (900 kbar): Journal of Chemical Physics, v. 76, 

p. 3055-3063. 

Nordlie, B.E., 1971, The composition of the magmatic gas of 

Kilauea and its behavior in the near surface environment: 

American Journal of Science, v. 27I, p. 417-463. 

Nordstrom, D.K., Plummer, L.N., Wigley, T.M.L., Wolery, T.J, Ball, 

J.W., Jenne, E.A., Bassett, R.L., Crerar, D.A., and Florence, 

T.M., I979, A comparison of computerized chemical models 

for equilibrium calculations in aqueous systems, in Jenne, 

E.D., ed., Chemical modelling in aqueous systems: American 

Chemical Society, ACS Symposium series 93, p. 857-892. 

Novikov, L.A., and Slobodskoy, R.M., I979. Mechanism of formation of diatremes. International Geology Review, v. 21, no. I 0, 

p. 1131-1139. 

Nurmi, P.A., Kukkonen,l.T., and Lahermo, P.W., I988, Geochemistry and origin of saline groundwaters in the Fennoscandian 

Shield: Appl. Geochem., v. 3, p. I85-203. 

Ohmoto, H., and Rye, R.O., I979, Isotopes of sulfur and carbon, Ch. 

I 0, in Barnes, H.L., ed., Geochemistry of hydrothermal ore 

deposits: New York, Wiley, p. 509-567. 

O'Nions, R.K., and Oxburgh, E.R., I988, Helium, volatiles and the 

continental crust: Earth and Planetary Science Letters, v. 90, 

p. 331-339. 

Oxburgh, E.R., O'Nions, R.K., and Hill, R.I., I986, Helium isotopes in sedimentary basins: Nature, v. 324, p. 632-fJ35. 

Pasteris, J.D., 1988, Secondary graphitization in mantle-derived 

rocks: Geology, v. 16, p. 804-807. 

Petersil'ye, LA., 1962, Origin of hydrocarbon gases and dispersed 

bitumens of the Khibina alkalic massif: Geochemistry, v. 1, 

p. 13-30. [English translation.] 

Petersil'ye, LA., Andreeva, E.D., and Sveshnikova, E.V., 1965, 

Organic matter in the rocks of some alkaline massifs of Si-
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 129 

beria: lsvestia Akademii Nauk SSSR, Geology Series, v. 6, 

p. 26-38. [In Russian.] 

Petersil'ye, I.A., Kozlov, Y.K., Belyayev, K.D., Sholokhnev, V.V., 

and Dokuchayeva, V.S., 1970, Nitrogen and hydrocarbon gases 

in ultramafic rocks of the Sopcha Stock of the Monchegorsk 

pluton, Kola peninsula: Doklady Akademii Nauk SSSR, v. 194, 

p. 200-203. [English translation.] 

Petersil'ye, I.A., and Pripachkin, V.A., 1979, Hydrogen, carbon, 

nitrogen and helium in gases from igneous rocks: Geochemistry International, v. 16, no. 4, p. 50-55. [English translation.] 

Petersil'ye, I.A., and Sorenson, H., 1970, Hydrocarbon gases and 

bituminous substances in rocks from the Ilimaussaq alkaline 

intrusion, South Greenland: Lithos, v. 3, p. 59-76. 

Peyronneau, J., and Poirier, J.P., 1989, Electrical conductivity of 

the Earth's lower mantle: Nature, v. 342, p. 537-539. 

Picard, M.D., 1960, Carbon dioxide, nitrogen and helium in Mississippian of Four Corners Region, preliminary statement, in 

Four Corners Geological Society Guidebook, Geology of the 

Paradox Basin fold and fault belt, Third Field Conference: 

Four Comers Geological Society, p. 138-140. 

---1962, Occurrence and origin of Mississippian gas in the 

Four Corners region: American Associati?n of Petroleum Geologists Bulletin, v. 46, p. 1681-1700. 

Pierce, A.P., Gott, G.B., and Mytton, J.W., 1964, Uranium and 

helium in the Panhandle gas field, Texas, and adjacent areas: 

U.S. Geological Survey Professional Paper 454-G, p. G 1-57. 

Pineau, F., Javoy, M., Behar, F., and Touret, J., 1981, La geochimie 

isotopique du facies granulite du Bamble Norvege et l'origine 

des ftuides carbones dans Ia croute profonde: Bulletin Mineralogique, v. 104, p. 630-641. 

Pohlmann, H.F., 1967, The Navajo indian nation and Dineh Bi 

Keyah, in Trauger, F.D., ed., Guidebook of the Defiance-ZuniMt. Taylor region, Arizona and New Mexico: N.M. Gcol. Soc., 

18th Field Conf., p. 63-69. 

Poreda, R.J., Jenden, P.O., Kaplan, l.R., and Craig, H., 1986, Mantle 

helium in Sacramento basin natural gas wells: Geochimica et 

Cosmochimica Acta, v. 50, p. 2847-2853. 

Puchelt, H., 1983, Carbon dioxide in the Rhenish Massif [abs.], in 

Fuchs, F., von Gehlen, K., Malzer, H., Murowski, H., and 

Semmel, A., cds., Plateau uplift, The Rhenish shield-A case 

history: Berlin, Springer-Verlag, p. 58. 

Ramdohr, P., 1952, Uber Josephinit, Awaruit, Souesit, ihre Eigenschaften, Entstehung und Paragenesis: Mineralogical Magazine, v. 29, p. 375-393. 

Ringwood, A.E., 1975, Composition and petrology of the Earth's 

mantle: New York, McGraw Hill, 618 p. 

---1979, Composition and origin of the Earth, in McElhinny, 

M.W., ed., The Earth-Its origin, structure and evolution: London, Academic Press, p. 1-58. 

Rockwell Hanford Operations, 1982, Site characterization report 

for the basalt waste isolation project, DOEIRL 82-3, v. 1, ch. 5, 

Hydrogeology, S.l Regional and Site Hydrologic Investigations, p. 5.1-1 to 5.1-203: Washington, D.C., U.S. Department 

of Energy. 

Roedder, E., 1965, Liquid C02 inclusions in olivine-bearing nodules 

and phenocrysts from basalts: American Mineralogist, v. 50, 

p. 1746-1782. 

---1972, Composition of fluid inclusions, in Fleischer, M., 

ed., Data of geochemistry (6th ed.): U.S. Geological Survey 

Professional Paper 440-JJ, 164 p. 

---1984. Upper mantle environments, Chapter 17, in Roedder, E., ed., Fluid Inclusions: Mineralogical Society of 

America, Reviews in Mineralogy, v. 12, p. 503-533. 

Rona, P.A., Bougault, H., Charlou, J.L., Appriou, P., Nelson, 

T.A., Trefry, J.H., Eberhart, G.L., Barone, A., and Needhan, 

H.D., 1992, Hydrothermal circulation, serpentinization, and 

degassing at a rift valley-fracture zone intersection-MidAtlantic Ridge near 15'N, 45"W: Geology, v. 20, p. 783-

786. 

Ross, J.E., and Aller, L.H., 1976, The chemical composition of 

the Sun: Science, v. 191, p. 1223-1229. 

Rutherford, M.J., 1993, Experimental petrology applied to volcanic processes, EOS, Transactions, American Geophysical 

Union, v. 74, no. 5, p. 49, 55. 

Rutherford, M.J., and Devine, J.D., 1988, The May 18, 1980 

eruption of Mt. St. Helens 3-Stability and chemistry of 

amphibole in the magma chamber: Journal of Geophysical 

Research, v. 93, p. 11949. 

Sakai, H., Casadevall, T.H. and Moore, J.G., 1982, Chemistry 

and isotope ratios of sulfur in basalts and volcanic gases at 

Kilauea Volcano, Hawaii. Geochimica et Cosmochimica 

Acta, v. 46, p. 729-738. 

Sakata, S., Takahashi, M., and Hoshiro, K., 1986, Geochemical 

study on genesis of natural gases accumulated in deep volcaniclastic rocks: Journal of the Japanese Association of Petroleum Technology, v. 51, p. 228-237. [In Japanese.] 

Sakata, S., Takahashi, M., Igari, S.l., and Suzuki, N., 1989, Origin of light hydrocarbons from volcanic rocks in the "green 

tuff'' region of Northeast Japan-Biogenic versus magmatic: 

Chemical Geology, v. 74, p. 241-248. 

Sano, Y., and Wakita, H., 1985, Geographical distribution of 3He/ 4

He ratios in Japan-Implications for arc tectonics and 

incipient magmatism: Journal of Geophysical Research, 

v.90, no. BlO,p. 8729-8741. 

Sano, Y., Wakita, H., and Giggenbach, W.F., 1987a, Island arc 

tectonics of New Zealand manifested in helium isotope ratios: Geochimica et Cosmochimica Acta, v. 51, p. 1855-

1860. 

Sano, Y., Wakita, H., Ohsumi, T., and Kusakabe, M., 1987b, Helium isotope evidence for magmatic gases in Lake Nyos, 

Cameroon: Geophysical Research Letters, v. 14, no. 10, 

p. 1039-1041. 

Sato, M., 1978a, Oxygen fugacity in basaltic magmas and the 

role of gascforming elements: Geophysical Research Letters, 

v. 5, p. 447-449. 

---1978b, A possible role of carbon in characterizing the oxidation state of a planetary interior and originating a metallic 

core: Lunar and Planetary Science, IX, p. 990-992. 

---1991, Oxygen fugacities of FeO mineral assemblages in 

relation to carbon oxidation in the Earth: American Geophysical Union Spring Meeting 1991, Program and Abstracts, April 23, 1991, p. 142. 

Sato, M., Sutton, A.J., and McGee, K.A., 1985, Anomalous hydrogen emissions from the San Andreas fault observed at the 

Cienega Winery, central California: Pageoph, v. 122, p. 376-

391. 

Sato, M., Sutton, A.J., McGee, K.A., and Russell-Robinson, S., 

1986, Monitoring of hydrogen along the San Andreas and 

Calaveras faults in Central California in 1980-1984: 1 ournal 

of Geophysical Research, v. 91, no. 812, p. 12315-12326. 
130 THE FUTURE OF ENERGY GASES 

Sato, M., and Valenza, M., 1980, Oxygen fugacities of the layered series of the Skaergaard intrusion, East Greenland: 

American Journal of Science, v. 280-A, p. 134-158. 

Saxena, S.K., 1989, Oxidation state of the mantle: Geochimica et 

Cosmochimica Acta, v. 53, p. 89-95. 

Saxena, S.K., and Fei, Y., 1988, Fluid mixtures in the C-H-0 

system at high pressure and temperature: Geochimica et 

Cosmochimica Acta, v. 52, p. 505-512. 

Scarfe, C.M., and Wyllie, P.J., 1967, Experimental redetermination of the upper stability limit of serpentine up to 3 kbar 

pressure: Eos, Transactions American Geophysical Union, 

v. 48, p. 225. 

Schiffries, C.M., 1982, The petrogenesis of a platiniferous dunite 

pipe in the Bushveld Complex-Infiltration metasomatism by 

a chloride solution: Economic Geology, v. 77, p. 1439-1453. 

Schoell, M., Tietze, K., and Schoberth, S.M., 1988, Origin of 

methane in Lake Kivu, (East-Central Africa): Chemical Geology, v. 71, p. 257-265. 

Sherwood, B., Fritz, P., Frape, S.K., Macko, S.A., Weise, S.M., 

and Welhan, J.A., 1988, Methane occurrences in the Canadian Shield: Chemical Geology, v. 71, p. 223-237. 

Sherwood-Lollar, B., Frape, S.K., Drimmie, R., Fritz, P., Weise, 

S.M., Macko, S.A., Welhan, J.A., Blomqvist, R., and Lahermo, P.W., 1989, Deep gases and brines of the Canadian and 

Fennoscandian Shields-A testing ground for the theory of 

abiotic methane generation, in Miles, D.L., ed., Sixth International Symposium on Water-Rock Interaction: Rotterdam, 

A.A. Balkema, p. 617-620. 

Shipley, T.H., Stoffa, P.L. and Dean, D.O., 1990, Underthrust 

sediments, fluid migration paths, and mud volcanoes associated with the accretionary wedge of Costa Rica, Middle 

America Trench: Journal of Geophysical Research, v. 95, 

p. B8743-B8752. 

Shteynberg, D.S., and Lagutina, M.V., 1978, Carbon balance in 

serpentinization of ultramafic rocks: Doklady Akademii 

Nauk SSSR, v. 243, p. 200-203. [English translation.] 

Silver, E.A., Breen, N.A. and Prasetyo, H., 1986, Multibeam 

study of the Flores baskar thrust belts, Indonesia: Journal of 

Geophysical Research, p. B3489-B3500. 

Sisson, V.B., Crawford, M.L., and Thompson, P.H., 1981, COT 

brine immiscibility at high temperatures, evidence from calcareous metasedimentary rocks: Contributions to Mineralogy 

and Petrology, v. 78, p. 371-378. 

Snyder, D., Carmichael, l.S.E., and Wiebe, K.A., 1993, Experimental study of liquid evolution in an Fe-rich, layered mafic 

intrusion; constraints of Fe-Ti oxide precipitation on the 

T-fo2 and T-P paths of tholeiitic magmas: Contributions to 

Mineralogy and Petrology, v. 113, no. 1, p. 73-86. 

Sobolev, V.S., Bazarova, T.Y., Kostyuk, V.P., 1974, Inclusions in 

the minerals in some types of alkaline rocks [with comments], in Alkaline rocks, conditions of formation: London, 

John Wiley and Sons, p. 389-401. 

Sobolev, V.S., Bazarova, T.Y., Shugurova, N.A., Bazarov, L.Sh., 

Dolgov, Yu.A., and Sorensen, H., 1970, A preliminary examination of fluid inclusions in nepheline, sorensenite, tugtupite and chkalovite from the Ilimaussaq intrusion, South 

Greenland: Medd. Gronland, v. 181(11), p. 1-32. 

Sobolev, V.S., and Stankovskiy, A. F., 1979, Carbonate inclusions 

in chrome spinellids from kimberlite sheets: Doklady Akademii Nauk SSSR, v. 251, no. 6, p. 1477-1478. 

Spera, F.J., 1974, A thermodynamic basis for predicting water 

solubilities in silicate melts and implications for the low velocity zone: Contributions to Mineralogy and Petrology, 

v. 45, p. 175-186. 

Spera, F.J., and Bergman, S.C., 1980, Carbon dioxide in igneous 

petrogenesis: I. Aspects of the dissolution of C02 in silicate 

liquids: Contributions to Mineralogy and Petrology, v. 74, 

p. 55-66. 

Spiess, F.N., and others, 1980, East Pacific rise-Hot springs and 

geophysical experiments: Science, v. 207, no. 4438, p. 1421-

1433. 

Spinks, J.W.T., and Woods, R.J., 1976, An introduction to radiation chemistry (2d ed.): John Wiley and Sons. 

Staudacher, T., 1987, Upper mantle origin for Harding County 

well gases: Nature, v. 325, p. 605-607. 

Stumpe!, E.F., and Rucklidge, J .C., 1982, The platiniferous dunite pipes of the eastern Bushveld: Economic Geology, v. 77, 

no. 6, p. 1419-1431. 

Sugisaki, R., ldo, M., Takeda, H., Isobe, Y., Hayashi, Y., Nakamura, N., Satake, H., and Mizutani, Y., 1983, Origin of hydrogen and carbon dioxide in fault gases and its relation to 

fault activity: The Journal of Geology, v. 91, p. 239-258. 

Tajika, E., and Matsui, T., 1992, Evolution of terrestrial protoC02 atmosphere coupled with thermal history of the Earth:· 

Earth and Planetary Science Letters, v. 113, p. 251-266. 

Taylor, B.E., 1986, Magmatic volatiles-Isotopic variation of C, 

H and S, in Valley, J.W., Taylor, H.P., and O'Neil, J.R., eds., 

Stable isotopes in high temperature geological processes: 

Mineralogical Society of America, Reviews in Mineralogy, 

v. 16, p. 185-225. 

Taylor, W.R., 1990, A reappraisal of the nature of fluids included 

by diamond-A window to deep-seated mantle fluids and 

redox conditions, in Herbert, H.K., and Ho, S.E., eds., Stable isotopes and fluid processes in mineralization: Queensland, Geology Department and University extension, 

University of Western Australia, v. 23, p. 17-34. 

Taylor, W.R., and Green, D.H., 1987, The petrogenetic role of 

methane-Effect on liquidus phase relations and the solubility mechanism of reduced C-H volatiles, in Mysen, B.O., 

ed., Magmatic processes-Physicochemical principles: The 

Geochemical Society, Special Publication No. 1, p. 121-138. 

---1989, The role of reduced C-0-H fluids in mantle partial 

melting, in Kimberlites and related rocks: Geological Society of Australia, Special Publication, v. 14, no. 1, p. 592-

602. 

Thayer, T.P., 1966, Serpentinization considered as a constant volume metasomatic process: American Mineralogist, v. 51, 

p. 685-710. 

Thurston, P.C., Williams, H.R., Sutcliffe, R.H., and Stott, G.M., 

1991, Geology of Ontario: Ontario Geological Survey Special Volume 4, parts 1 and 2, 1525 p. 

Tietze, K., Geyh, M., Miiller, H., Schroder, L., and Wehner, H., 

1980, The genesis of methane in Lake Kivu: Geologische 

Rundschau, v. 69, p. 452-472. 

Tingle, T.N., Green, H.W., Finnerty, A.A., 1988, Experiments 

and observations bearing on the solubility and diffusivity of 

carbon in olivine: Journal of Geophysical Research, v. 93, 

no. Bl2, p. 15289-15304. 

Tissot, B.P., and Welte, D.H., 1978, Petroleum formation and occurrence: Berlin, Springer-Verlag, 538 p. 
ENERGY GASES OF ABIOGENIC ORIGIN IN THE EARTH'S CRUST 131 

Tongish, C.A., 1980, Helium-Its relationship to geologic systems and its occurrence with the natural gases, nitrogen, carbon dioxide, and argon: U.S. Bureau of Mines, Report of 

Investigations 8444, 176 p. 

Touret, J., 1986, Fluid inclusions from the lower continental 

crust, in Dawson, J.B., Carswell, D.A., Hall, J., and Wedepohl, K.H., eds., The nature of the lower continental crust: 

Geological Society of London Special Publication No. 24, 

p. 161-172. 

Treiman, A.H., and Essene, E.J., 1984, A periclase-dolomite-calcite carbonatite from the Oka complex, Quebec, and its calculated volatile composition: Contributions to Mineralogy 

and Petrology, v. 85, p. 149-157. 

Tuttle, M.L., Briggs, P.H., Evans, W.C., Kling, G.W., and Lockwood, J.P., 1992, Influence of mafic minerals on water 

chemistry and water column stability of Lake Nyos, Cameroon, in Water-Rock Interaction: Rotterdam, Balkema, 

p.449--452. 

Underwood, M.B. and Laughland, M.M., 1990, Thermal evolution of "hot" accretionary prisms in California and Japan 

[abs.]: American Association of Petroleum Geologists Bulletin, v. 74, p. 783. 

Vdovykin, G.P., Bodunov, Ye.N., Izosimova, A.N., and others, 

1979, Bitumens in the Mir kimberlite pipe: Doklady Akademii Nauk SSSR, v. 2454, p. 941-946. 

Vinogradov, A.P., 1962, Average contents of chemical elements 

in the principal types of igneous rock of the Earth's crust: 

Geokhimiya, v. 7, p. 555-571. [English translation.] 

Von Huene, R., and Lee, H., 1983, The possible significance of 

pore fluid pressure vs. subduction zones, in Watkins, J.S., 

and Drake, C.L., eds., Studies in continental margin geophysics: American Association of Petroleum Geologists, 

Memoir 34, p. 781-791. 

Vovk, I.F., 1987, Radiolytic salt enrichment and brines in the 

crystalline basement of the East European Platform, in Fritz, 

P., and Frape, S.K., eds., Saline water and gases in crystalline rocks, Geological Association of Canada Special Paper 

33, p. 197-210. 

Voytov, V.I., Grechukhina, T.G., Levshvnova, V.P., and Polyanskiy, M.N., 1967, Chemical composition of plutonic gases as 

shown by data on the Aralsov abyssal well (Caspian depression): Doklady Akademii Nauk SSSR., v. 172, p. 192-195. 

[English ·translation.] 

Vrolijk, P., Fisher, A~. and Gieskes, J ., 1991, Geochemical evidence and geothermal evidence for fluid migrastion in the 

Barbados accretionary prism (ODP Leg 110): Geophysical 

Research Letters, v. 18, p. 947-950. 

Vrolijk, P., Myers, G., and Moore, J.C., 1988, Warm fluid migration along tectonic melanges in the Kodiak accretionary 

complex, Alaska: Journal of Geophysical Research, v. 93, 

no. B9, p. 10313-10324. 

Wainger, L., 1988, Mantle carbon flux calculated: EOS, Transactions, American Geophysical Union, v. 69, no. 12, p. 169. 

Wakita, H., Sano, Y., Urabe, A., and Nakamura, Y., 1990, Origin 

of methane-rich natural gas in Japan-Formation of gas 

fields due to large-scale submarine volcanism: Applied 

Geochemistry, v. 5, p. 263-278. 

Wallace, P., and Carmichael, I.S.E., 1992, Sulfur in basaltic magmas: Geochimica et Cosmochimica Acta, v. 56, p. 1863-

1874. 

Wang, C.Y., Shi, Y., Hwang, W.T., and Chen, H., 1990, Hydrogeologic processes in the Oregon-Washington accretionary 

complex: Journal of Geophysical Research, v. 95, no. B6, 

p.9009-9023. 

Wassail, H., 1956, The relationship of oil and serpentine in 

Cuba: 20th International Geological Congress, Mexico City, 

Section 3, p. 65-77. 

Welhan, J .A., 1987, Characteristics of abiotic methane in rocks, 

in Fritz, P., and Frape, S.K., eds., Saline water and gases in 

crystalline rocks: Geological Association of Canada Special 

Paper 33, p. 225-233. 

Welhan, J .A., 1988, Organics of methane in hydrothermal systems: Chemical Geology, v. 71, p. 183-198. 

Welhan, J.A., and Craig, H., 1979, Methane and hydrogen in 

East Pacific Rise hydrothermal fluids: Geophysical Research 

Letters, v. 6, p. 829-831. 

---1983, Methane, hydrogen, and helium in hydrothermal 

fluids at 21 'N on the East Pacific Rise, in Rona, P., and others, eds., Hydrothermal processes at seafloor spreading centers: New York, Plenum Press, p. 391--401. 

Welhan, J.A., and Lupton, J.E., 1987, Light hydrocarbon gases in 

Guaymas Basin hydrothermal fluids-Thermogenic versus 

abiogenic origin: American Association of Petroleum Geologists Bulletin, v. 71, p. 215-223. 

Wenner, D.B., and Taylor, H.P., 1971, Temperatures of serpentinization of ultramafic rocks based on 0 18/016 fractionation 

between coexisting serpentine and magnetite: Contributions 

to Mineralogy and Petrology, v. 32, p. 165-185. 

Weres, 0., Newton, A.S., and Tsao, L., 1988, Hydrous pyrolysis 

of alkanes, alkenes, alcohols and ethers: Organic Geochemistry, v. 13, p. 433--444. 

Westbrook, G.K., and Smith, M.J., 1983, Long decollements and 

mud volcanoes-Evidence from the Barbados Ridge Complex for the role of high pore-fluid pressure in the development of an accretionary complex: Geology, v. 11, p. 279-283. 

Whiticar, M.J., 1990, A geochemical perspective of natural gas 

and atmospheric methane: Organic Geochemistry, v. 16, 

p. 531-547. 

Wickham, S.M., Peters, M.T., Fricke, H.C., and O'Neil, J.R., 

1993, Identification of magmatic and meteoric fluid sources 

and upward- and downward-moving infiltration fronts in a 

metamorphic core complex: Geology, v. 21, p. 81-84. 

Willingham, T.O., Nagy, B., Nagy, L.N., Krinsley, D.H., and 

Mossman, D.J., 1985, Uranium-bearing stratiform organic 

matter in paleoplacers of the lower Huronian Supergroup, 

Elliot Lake-Blind River region, Canada: Canadian Journal of 

Earth Sciences, v. 22, p. 1930-1944. 

Wolery, T.J., and Sleep, N.J., 1976, Hydrothermal circulation and 

geochemical flux at mid-ocean ridges: Journal of Geology, 

v. 84, p. 249-275. 

Wood, B.J., and Nell, J., 1991, High-temperature electrical conductivity of the lower-mantle phase (Mg,Fe)O: Nature, v. 3, 

p. 309-311. 

Wyllie, P.J., 1980, The origin of kimberlite: Journal of Geophysical Research, v. 85, no. 12, p. 6902-6910. 

---1989, The genesis of kimberlites and some low-Si02, 

high-alkali magmas, in Kimberlites and related rocks: Special Publication-Geological Society of Australia (Div.ision 

of Geological and Planetary Sciences), v. 14, no. 1, p. 603-

615. 
132 THE FUTURE OF ENERGY GASES 

Wyllie, P.J., Baker, M.B., and White, B.S., 1990, Experimental 

boundaries for the original evolution of carbonatites: Lithos, 

v. 26, p. 3-19. 

Xu, Y-C., Shen, P., Sun, M-L., and Xu, S., 1990, Nonhydrocarbon 

and noble gas geochemistry in natural gas of Eastern China: 

Science in China (series B), v. 33, no. 12, p. 1494-1503. 

---1991, Non-hydrocarbon and noble gas geochemistry: Journal of Southeast Asian Earth Science, v. 5, no. 1-4, p. 327-332. 

Xu, Y., Wang, X., Wu, R., Shen, P., Wang, Y., and He, Y., 1982, 

Rare gas isotopic composition of natural gases: Geochemistry, v. 1, p. 218-232. 

Young, T.E., Green, H.W., and Hofmeister, A.M., 199i, OH solubility and sp-(Mg, Fe)z Si04 [abs.]: American Geophysical 

Union, Spring Meeting, 1991, Program and Abstracts, Supplement to EOS, April 23, 1991, p. 144. 

Zemann, J., Schwarz, H.P., Hoeffs, J., and Welte, D., 1969, Carbon, in K.H. Wedepohl, ed., Handbook of geochemistry, 

New York, Springer-Verlag, Till, Ch. 6. 

Zezin, R.B., and Sokolova, M.N., 1967, Macroscopic occurrences of carbonaceous matter in hydrothermal deposits of the 

Khibiny pluton: Doklady Akademii Nauk SSSR, v. 177, 

p. 217-221. [English translation.] 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Prospects for Commercial Abiogenic Gas Production: 

Implications from the Siljan Ring Area, Sweden 

By John R. Castafio1 

CONTENTS 

Abstract ......................................................................... 133 

Introduction ... .. . . .. . . ...... ... . .. .. ...... ... .. ... . ... .. . .. . .. . ... .. .. .. ... . .. 134 

Expectation Model ........................................................ 134 

Geologic Setting-Siljan Ring ..................................... 135 

Pre-1986 Investigations ..............•................................. 135 

Geology and Geochemistry ................................... 135 

Geophysics ............................................................. 137 

Choice of the Gravberg 1 Drill Site ...................... 138 

Operational Summary of the Gravberg 1 Well ............ 138 

Geologic Factors Related to Reservoir Development . 140 

Lithology ··················:············································· 140 

Alteration 140 

Fracturing ............................................................... 140 

Structure and Correlations ..................................... 140 

Fluid Geochemistry . . .. . . .. . . . .. .. . ... ... . .. .. . . .. ..... ...... ... .. .. ... . . 140 

Geochemical Sampling and Analysis .................... 140 

Factors Affecting Gas Readings ............................ 141 

Contamination ........................................................ 142 

Laboratory Experiments ........................................ 142 

Uncontaminated Samples ...................................... 142 

Synthesis-Background for Interpretation ................... 143 

Composition of Hydrocarbon Gases ..................... 143 

Isotopic Composition of Hydrocarbon Gases ....... 143 

Inorganic Gases .. .. . ... . .. .. .. . .. . .. . . .. .. . . .. ..... ...... ... . . .. ... . . 146 

Key Elements for Hydrocarbon Entrapment ................ 146 

Synthesis-Interpreting Shows .................................... 147 

Shows in Dolerite and Granite .............................. 147 

Drill-stem Tests 1 Through 4 ................................. 148 

Drill-stem Test 5 and Pump Testing in 1990 ........ 148 

Gas Geochemistry ....... ... . . ....... .. .. .. .. ... ... .. . ..... .. 148 

Water Geochemistry ... .. .. ... .. . . .. ... ........... .. .. ... .. . 149 

1

DGSI, 8701 New Trails Drive, The Woodlands, TX 77381. 

Interpreting Fluid Geochemical Data ... .. .. .. . ... .. ... . .... ..... 149 

Discussion ............................................................... 149 

Summary-No Source ............................................ 150 

Interpreting Reservoir Data ........................................... 150 

Interpreting Seal Properties ........................................... 150 

Epilogue-The Stenberg 1 Well ................................... 152 

Conclusions ................................................................... 152 

References Cited ........................................................... 153 

ABSTRACT 

The Siljan Ring structure in central Sweden is a 360-Ma 

meteorite impact crater with an excavated diameter of 

45 km. The Gravberg 1 well, just outside the excavated 

region on the northeast rim, was drilled as a commercial 

venture to explore for abiogenic gas of mantle origin. The 

well reached a true vertical depth of 6, 779 m, penetrating 

only Precambrian granite porphyry, granite, quartz monzonite, and diabase (dolerite) sills. The sills correspond to 

prominent, low-dipping, high-amplitude seismic reflectors 

that afford the only good correlative horizons. 

Key points for evaluation include reservoir, cap rock, 

and source. Porosity in the granite is related to macrofractures, microfractures, and mineral alteration. On the basis of 

well data, the influence of the impact drops off dramatically 

below 2,000 m and is absent below 4,000 m. Fracture intensity is highly variable, but generally decreases with depth. 

Below 3,000 m, fracture zones are caused by regional tectonics. No continuous reservoir units were detected. Originally, 

calcite-cemented granite was expected to act as an impervious seal. Stable isotope studies of calcite show that mantle 

methane is not involved in any of the fractionation equilibria 

for these cements; instead there is equilibration with modern 

meteoric water. At depth, magmatic C02 is the likely carbon 

source for the heaviest carbon isotopes measured. On the 

133 
I34 THE FUTURE OF ENERGY GASES 

basis of leak-off and drill-stem tests, no caprocks were penetrated by the Gravberg I well. The pore-pressure gradient is 

essentially hydrostatic; the expectation model had predicted 

pressures approaching lithostatic. Hydraulic conductivity 

ranges from 0.07 to 7.5xio-10 m/s. Evidence points to deep 

(6 km) circulation of fresh, meteoric water below which lies 

stagnant, high-salinity water (150,000 ppm total dissolved 

solids). 

Contrary to expectations, no free gas was found. 

Water recovered from the most reliable drill-stem test is 

undersaturated with gas; gas concentration is 0.25 liter of 

gas per liter of fluid at standard temperature and pressure 

(STP). Average gas composition was 45 percent He, 2.5 

percent H2, 2 percent Ar, 0.3 percent 0 2, I 50 ppm CH4, 

and traces of C02 and Ne. The remainder is N2. He (with 

c3He/4He)sampJd(3He/4He)atmosphere=O.OI7), Ar, and Ne are 

radiogenic, originating from the breakdown of radioactive 

minerals in the crystalline rocks. 

Samples of hydrocarbon gases from diabases and granite are distinctly different. Trace amounts (less than I,OOO 

ppm) of CH4 in the diabases are abiogenic (b13C=-I5 permil relative to PDB standard). Hydrocarbon gases in the 

diabases consist dominantly of methane (95 percent); unsaturated hydrocarbons are rare. Methane encountered in 

the granite is thermogenic, artificial (caused by drilling abrasion and (or) contamination), and possibly of abiogenic 

origin (b13C=-23 to -55 permil). Hydrocarbon gases in the 

granite are present in much smaller amounts than in the 

diabases. As opposed to gases in the diabases, those in the 

granite contain a large amount of C2+ (30 to 50 percent), 

including a large proportion of unsaturated hydrocarbons. 

Unsaturated hydrocarbons such as the alkenes are rare in 

natur~; they could be formed in a Fischer-Tropsch reaction 

between C02 and H2 catalyzed by magnetite or produced 

by a spark discharge induced during tectonic rock shearing. 

It is also possible that the unsaturated hydrocarbons are 

drilling artifacts. 

There is no credible evidence of a dominant mantle 

source for hydrocarbons at Siljan, and very little hope for the 

development of any commercial gas fields in this setting. 

INTRODUCTION 

In 1982, Vattenfall (the Swedish State Power Board) 

began investigations in the Siljan Ring area as part of the 

broad search for alternative energy sources in Sweden. 

Their objective was to discover commercial abiogenic gas 

deposits in Europe's second largest impact crater. These 

wide-ranging studies were prompted by discussions with 

Thomas Gold, who championed the abiogenic methane gas 

hypothesis that implied an enormous new potential resource (see Gold, this volume). Except for oil production 

amounting to a few hundred barrels per day from the island 

of Gotland, Sweden has no oil, gas, or coal. Because Sweden had passed a referendum to phase out nuclear power 

beginning in 1995, there was great incentive to replace the 

50 percent of electrical power generated by nuclear plants. 

These are mostly operated by Vattenfall. The Siljan project 

has been highly controversial, because of the premises 

which led to the drilling and because of the great differences in the way the results have been interpreted. 

During I984 and I985 Vattenfall carried out an extensive series of investigations in the Siljan Ring structure. The 

research included geological and geochemical studies including surface mapping, core drilling, soil surveys, and 

analysis of lake waters. Geophysical work included seismic, 

magnetotelluric, and gravity surveys. Although a group of 

independent experts judged that the project had very little 

promise of commercial success (Anonymous, 1984), Vattenfall determined that the undertaking was worth continuing and drilled the deep exploratory hole, Gravberg I, 

starting in July I986. 

In I985 the Gas Research Institute (GRI) contributed 

funding for the deep well to test Gold's hypothesis, in order 

to provide reliable documentation and analyses on gases, 

fluids, drill cuttings, and cores, and on both surface and 

downhole geophysical measurements. About the same time 

Vattenfall sold shares in the venture to public entities and 

private investors in Sweden, setting up an operating company, Dala Djupgas Provborrningar KB. Vattenfall kept a majority interest and directed the project. In I990 Vattenfall 

sold its remaining shares to private Swedish investors who 

own the successor company, Dala Djupgas Produktions AB 

(DDP), which drilled the second deep well in the Siljan 

area, Stenberg 1, in I991-I992. I worked as the Chief Scientific Officer for GRI mainly at the well site, and served as 

a consultant for DDP from I990 to 1991. 

Preliminary results of the investigations were reported 

by Boden and Eriksson (1988), but the most up-to-date and 

complete evaluations are included in a series of internal 

reports issued by Vattenfall in I990-1991 which have a very 

limited distribution. (These reports are available from Vattenfall Utveckling AB, Dokumentationscentralen, S-81070, 

Alvkarlesby, Sweden.) This report is an updated summary 

of many aspects of these studies. 

EXPECTATION MODEL 

The basic premises of the deep-gas hypothesis as proposed by Thomas Gold (1979, I987, this volume) are as 

follows: 

1. Hydrocarbons were incorporated in the upper mantle as the earth accreted during the formation of the solar 

system. These hydrocarbons have outgassed as methane ·at 

a constant rate throughout geologic time. 

2. The mantle-derived methane is a major contributor 

to all hydrocarbon and coal deposits. 

3. Mantle outgassing occurs along rifts and faults and 

through solid rock. 
PROSPECTS FOR COMMERCIAL ABIOGENIC GAS PRODUCTION 135 

4. Fractures caused by the meteorite impact allowed 

mantle methane to migrate into the Siljan Ring structure. 

5. Calcite formed by interaction with ascending methane helps create seals that will trap methane. 

6. Methane gas collects in stacked domains below critical layers; pore pressure in these reservoirs approaches 

lithostatic pressure. The critical layers are characterized by 

lower pore pressures and porosity that has been reduced 

by weight of the overburden. When gas accumulations 

reach a particular concentration, lithostatic pressures are 

exceeded by pore pressures, fractures break through the 

critical layer, and gas migrates through the critical layer 

until it reaches the next critical layer or the surface of the 

earth. The first critical layer is expected to be present at a 

depth between 3 and 6 km. 

Although Gold is widely known for his views on the 

abiogenic origin of hydrocarbons, Russian scientists also 

have been very active proponents of the inorganic origin 

of petroleum (Kropotkin, I985). 

GEOLOGIC SETTING-SILJAN RING 

The geologic map of the Siljan area shows a concentric distribution of Ordovician and Silurian sedimentary 

rocks surrounding the central cupola that contains the Jarna 

and Siljan Granites (age about I, 700 Ma) that are intruded 

by late Precambrian diabases (dolerites) (age about 900 

Ma) (fig. I). Instead of being continuous, the Paleozoic 

ring is largely a megabreccia made up of meter- to kilometer-sized blocks. On the basis of seismic data, the Paleozoic section is up to 350 m thick. 

The Siljan Ring impact structure has a diameter of 

about 52 km and is the second largest impact structure in 

Europe (Grieve, I988). The characteristic ring configuration and the presence of shatter cones, breccias, impact 

melts, and microscopic planar features in the granites show 

that the Siljan structure is an impact structure (Svensson, 

I973; Thorslund and Auton, I975; Tamminen and Wickman, I980; Wickman, I980; Vlierboom and others, I986). 

An estimated I-2 km of section has been eroded. Impact 

melts have been dated at 359 to 362 Ma (Bottomley and 

others, I978; Lee and others, 1988). 

In the formation of complex impact structures such as 

Siljan, the transient cavity floor is uplifted and the rim 

area collapses. At Siljan, the granites represent the eroded 

remnant of the cavity floor. Paleozoic sedimentary rocks 

along the rim were preserved as the result of downfaulting 

which accompanied the collapse of the rim of the transient 

cavity. The impact of a meteor 2-3 km in diameter would 

have melted and vaporized some 250 km3 of rock (Grieve, 

1988). The resultant annular melt sheet about 200 m thick 

would have had an initial temperature of about 2,200°C 

(Grieve, 1988) and extended beyond the area of Paleozoic 

sedimentary rocks. This impact melt would have taken 

some 1,000-2,000 years to crystallize, and perhaps 10,000 

years to cool off. 

Fracturing associated with the impact was extensive, 

perhaps extending to 50 km beyond the original rim of the 

crater (Anonymous, 1991 ). Initially, it was postulated that 

structural disturbances in the center of the crater would have 

extended to depths of 7 to 10 km, with the potential for 

fractures penetrating to the lower crust. Moreover, erosion 

of I to 2 km of cover could have relieved the compressive 

stresses and increased fracture porosity. These speculations 

fit with the work of Donofrio (1981), who concluded that 

impact craters in crystalline rocks could have significant 

reservoir potential. 

PRE-1986 INVESTIGATIONS 

A broad range of geoscientific investigations led to the 

drilling of the Gravberg I well. In order to be concise, 

discussion of the geophysical findings for the entire span 

of the project have been consolidated in this section. 

GEOLOGY AND GEOCHEMISTRY 

Prior to the drilling of the deep exploratory hole, 

Gravberg I, nine coreholes were drilled in the area (fig. 1). 

Ranging in depth from 100-700 m, they were continuously 

cored with almost I 00-percent recovery. In granite, high 

fracture porosity was associated with shear zones, microbreccias, and mylonites. However, hydrological tests 

showed that fracture permeability was very low, particularly in the center of the impact structure. 

Interest in the area was heightened by shows of oil and 

gas, which included some well-documented accounts dating back to the 18th century (Hedberg, 1988). Occurrences 

of biodegraded heavy oil, seeps, oil shows, and solid bitumen are confined to Ordovician limestones in the Solberga-Boda area on the east side of the Siljan Ring (fig. I). 

These oils have been correlated with closely associated 

source rocks in the Ordovician Tretaspis Shale (Vlierboom 

and others, 1986). The oils result from the maturation of 

source rocks heated by the impact event. The impact set up 

a convection system that circulated through a circular terrain about 52 km wide and at least 1.2 km thick (Komor 

and Valley, 1990). 

Hydrocarbons from surface and shallow subsurface occurrences in the Siljan area fall into two general groups. The 

first group comprises microbial gases, composed almost entirely of methane, usually in trace amounts, with a very light 

isotopic signature; 12 samples average a o13C value of -60.7 

perrnil relative to the PDB standard (Castano, 1990). Higher 

methane concentrations in surface waters are present in the 

central area of the ring: here there are large, rather flat areas 

with peat soils and small lakes that favor biological methane 

production. The highest methane shows occur within the 
136 THE FUTURE OF ENERGY GASES 

Paleozoic sedimentary ring, possibly because of better reservoir conditions. The second group is made up of thermogenic gases that have heavier isotopic values and are 

associated with biodegraded oil in Ordovician reef limestones (tPC=-45 permil; fig. 1 ). 

Helium isotope analysis of gases from Fasas, Solberga, 

and Vastana yielded R!Ra ((3

He/ 4He)sample/eHe/4He)atmoi 

N EXPLANATION 

sphere) of 0.015 to 0.11 . These values indicate that the helium is dominantly 4He and that it is more than 98 percent 

crustal in origin (Castano, 1990). 

Hydrogen is generally absent from surface and water 

wells, but it is much more abundant than methane in most 

samples obtained from the deeper exploratory boreholes. 

However, hydrogen is absent in two drill-stem tests made 

• 

0 5 10 km ~ Gas seep ' Oil seep 

/:<:<:/ Orsa Sandstone (Upper Silurian?) 

~ Limestones and shales (Silurian and Ordovician) 

/< <) i I Jam a and Siljan Granites (Precambrian) 

• 

Volcanic and sedimentary rocks (Precambrian) 

- Predate Jama and Siljan Granites 

Road 

Borehole Sweden 

Figure 1. Bedrock map of central part of Siljan ring structure showing location of major oil and gas seeps 

and nine shallow boreholes. Deep well and borehole at Gravberg have same location. Gas seeps at Kalkhohen (K) and Gullerasen (G) are identified. Towns of Mora, Orsa, and Riittvik are shown. Unpatterned areas 

within ring structure are bodies of water. Map area is box in central Sweden. 
PROSPECTS FOR COMMERCIAL ABIOGENIC GAS PRODUCTION 137 

between packers. As will be shown later, the presence of 

hydrogen in the deep Gravberg well (Gravberg 1) is undisputed, but the manner of occurrence of hydrogen in the 

shallow subsurface does not permit us to make a definite 

statement as to its origin. 

GEOPHYSICS 

A series of seismic lines were shot in the Siljan Ring 

area in 1985 (fig. 2); the stacked seismic section from the 

north-south line 5 is shown on figure 3. In 1985 the lowdipping reflections (R1-R4) were considered to be fracture 

zones, zones of mineralization or gas entrapment, or perhaps diabase sills. The results of the Gravberg J well convincingly showed that these zones are diabase (dolerite) 

sills (Juhlin and Pedersen, 1987). All four reflectors are 

\ 

'\ 

\ 

\ 

\ 

BOREHOLE 

\ 

~E 5 

\ 

\ 

40 

continuous along the northern end of line 5 in the vicinity 

of the Gravberg J well, but to the south in the central part 

of the crater, the deeper reflectors are more coherent whereas the shallow ones disappear quickly south of Gravberg 

(fig. 3). These data demonstrate clearly the effect of the 

meteorite impact on the rocks of the area: the center of the 

crater is highly fractured and broken up and the reflectors 

are largely missing, and the shallower units are more highly 

affected by the impact. 

Surface gravity studies showed a strong residual negative anomaly of 15 milligals with a diameter of 40 km along 

the northern edge of the crater's rim. It was realized that 

some of the density contrast was due to differences in lithology of the granite bodies, but some of the contrast could 

have been caused by increased porosity within 6 km of the 

surface (Anonymous, 1991 ). On the basis of surface and 

downhole surveys, it was found that the gravity anomaly is 

0 5KM 

Sweden 

\ \ LINE 

\\ 

160 \ 

8 0 \ 

\ 

Figure 2. Location of seismic lines acquired in 1985 in Siljan 

Ring area. Heavy dashed lines are trends of steeply dipping dolerite intrusions. Dashed-line pattern indicates Silurian and Ordovician sedimentary rocks; dot pattern, the boundary between the 

older Svecofennian rocks and the Siljan and Hirna Granites; unpatterned area in center of ring structure, Precambrian granite. 

\ 

' ' \ ~ 

Dots along seismic lines are shot points; numbers beside selected 

dots indicate shot point numbers, with shot point numbers for line 

5 in parentheses where it overlaps with line 7. Line 6 divides line 

7 from line 5. Note position of line 5; the stacked section is shown 

as figure 3. BOREHOLE refers to Gravberg 1 well. Map area is 

box in central Sweden. From Anonymous ( 1991 ). 
138 THE FUTURE OF ENERGY GASES 

0 

:r h:9 

w 

Cl 

s 

80 

l 1KM 

DEEP 

WELL 

!

480 

l. N 

cno 

z 

0 

() 

w 

e 

w 

:::!: 

~ 

...J 

w 

> 

< 

0:: 

f0 

3: 

fFigure 3. Stacked seismic section from line 5 (see fig . 2 for location). Depth scale on left assumes average velocity of 6 km/s. 

Modified from Anonymous (1991). DEEP WELL shows location of Gravberg I; numbers 80 and 480 indicate shot points. Rl through 

R4 are reflections caused by diabase (dolerite) sills. 

related mainly to the low-density Siljan granite (2,600 to 

2,650 kg/m3) present in much of the upper 5,000 m in the 

Gravberg 1 well. In addition, the gravity data indicate the 

presence of additional low-density rock below the total 

depth of the well, 6,763 m true vertical depth (TVD) (Anonymous, 1991 ); the low density of this rock is presumed to 

be caused by lithology or porosity characteristics. 

Magnetotelluric data showed a low-resistivity anomaly 

that is restricted mainly to the center of the Siljan structure. 

Before the Gravberg I well was drilled, the resistivity low 

was interpreted as the result of the upward migration of 

deep crustal fluids, thereby suggesting the possibility of a 

pathway for gas migration from great depths (Anonymous, 

1985). 

CHOICE OF THE GRAVBERG 1 DRILL SITE 

Two potential drilling locations were selected: in the 

center of the crater and near the village of Gravberg. The 

central location was favored because microfracturing was 

expected to be more intense in the center of the crater. In 

addition, the shallow core holes at Stajsas and Hattberg 

(fig. I) showed exceptionally low permeabilities in the granite, suggesting the presence of adequate caprock. Surface 

geochemical surveys and magnetotelluric data also supported a central location, whereas gravity and seismic studies 

supported a northern location. The strong high-amplitude 

anomalies seen on the seismic records could have represented either caprocks or porous zones. Furthermore, velocity 

analyses suggested the presence of a low-velocity, possibly 

more porous zone between the R3 and R4 reflectors. Greater 

weight was placed on the geophysical data, as these data 

were considered to be the most reliable, and the northern 

site at Gravberg was chosen as the site for the deep well. 

OPERATIONAL SUMMARY OF THE 

GRAVBERG 1 WELL 

The Gravberg 1 well was spudded on July 1, 1986, 

and operations ended July 3, 1990. The several segments 

of the well history are subdivided as follows: 

1. Original hole (OH). After 265 days, a measured 

depth of 6,081 m was reached, corresponding to a true vertical depth (TVD) of 5,985 m (fig. 4). Drilling proceeded 

quickly to a depth of 3,931 m; it then took six weeks to 

reach 4,167 m. Fresh water was used as the drilling fluid to 

3,932 m. At this depth a polymer mud was used in an 

attempt to overcome breakouts (hole enlargements due to 
PROSPECTS FOR COMMERCIAL ABIOGENIC GAS PRODUCTION 139 

anisotropic rock stresses) and hole-deviation problems. 

Hole deviation became pronounced starting just below the 

R-3 reflector (fig. 4). At 6,047 m all of the fluid in the well, 

some 150m3 of a heavy mud (1.62 g/cc), was lost into the 

formation as the result of hydraulic fracturing. Mud weight 

was then reduced, and drilling was resumed. The drill pipe 

twisted off at 4,700 m and was not recovered. 

:::c 

to.. 

u.J 

0 

2. Sidetrack 1 (ST-1 ). ST-1 started on day 267 at 

4,650 m and was drilled with fresh water and later with a 

polymer mud to a measured depth of 6,636 m (TVD of 

6,324 m). Once again the drill pipe twisted off, and ST-1 was 

abandoned. 

3. Sidetrack 2 (ST-2). ST-2 started on day 378 at 

6,054 m, and was drilled with an oil-based mud made up of 

R4 

u.J 

::::E 

t-

--1 

u.J 

::> 

< 

0:::: 

t-

>-

< :II: I 

0 

:II: 

tFigure 4. Borehole trajectories of the original hole and the three sidetracks of the Gravberg I well 

superimposed on seismic line 5 (see figs. 2, 3). TD, total depth; RI-R4, reflections caused by diabase 

(dolerite) sills. Depth scale on left is keyed to well depth. Modified from Anonymous (1991). 
140 THE FUTURE OF ENERGY GASES 

80 percent diesel and 20 percent water. ST-2 reached a 

measured depth of 6,600 m (TVD, 6,337 m) on September 1, 

1987, when operations were suspended to acquire additional 

funding. Drilling resumed in July 1988, but problems 

cropped up again, and ST-2 was abandoned at a measured 

depth of 6,674 m (TVD, 6394 m). 

4. Sidetrack 3 (ST-3). ST-3 started on day 480 at 

5,850 m and used the same oil-based mud used in ST-2. 

However, hole instability due to highly anisotropic rock 

stresses led to another fishing job, and the drill string 

twisted off (top of the fish is at 6,332 m). ST-3 has a total 

measured depth of 6,957 m (TVD, 6,792 m). 

5. Hydrofracturing, water injection, and testing took 

place from day 725 to day 824. The hydrofracturing operation was designed to fracture the formation downward; this 

operation was important because with the fish in the hole 

from 6,332 to 6,957 m, it was not possible to perform a 

conventional test at the bottom of the well (Castano and 

others, 1990). Some 260 m3 of oil-based heavy fracture 

fluid was injected into the formation. The data suggest that 

the stimulation grew downward, perhaps by up to a kilometer or more, and reached the R4 reflector. Later, 410 m3 

of water was injected into the formation in order to displace the oil-based fracture fluid deep into the rock and to 

leave the near-borehole fractures filled with fresh water 

and bauxite proppant (a granular material used to keep 

fractures open as fluid is withdrawn). Testing began by airlifting and bailing out 877 m3 of water. Then a conventional drill-stem test was run on the open hole below 5,453 m. 

6. Pump testing occurred from May 8 to July 3, 1990, 

when operations were finally halted. 

GEOLOGIC FACTORS RELATED TO 

RESERVOIR DEVELOPMENT 

LITHOLOGY 

The section penetrated by the Gravberg 1 well consists 

entirely of Precambrian crystalline rocks (fig. 5). The sequence is composed of granite porphyry (1,635 Ma) in the 

shallow subsurface, and deeper Siljan and Jlirna Granites 

(1,760-1,670 Ma). These rocks are in tum intruded by 

younger quartz monzonites (1 ,450 Ma) and dolerite sills 

(970-900 Ma). The dolerite sills found in the well are the 

main seismic reflectors and are designated Rl, R2, R3, 

and R4. The relatively ductile sills are less fractured and 

impede movement of fluids, whereas the brittle, fractured 

granites are, relatively speaking, the aquifers. The finegrained quartz monzonites are much more radioactive than 

the older, medium-grained Siljan and Jarna Granites. 

ALTERATION 

Evidence from petrographic and binocular microscope 

study shows that alteration is most intense above 2,000 m, 

decreases from 2,000-4,000 m, and is minor below 

4,000 m. Alkali feldspars are significantly altered in the 

upper part of the well: they are brick red to light red down 

to about 1,500 m. Below the Rl dolerite these feldspars are 

light red to pink, and they become progressively lighter in 

color to about 4,000 m; below this depth the feldspars are 

dominantly white and gray. Hematite is common down to 

2,000 m, magnetite dominates below 4,000 m, and 2,000-

4,000 m is a transitional zone. A!Dahan (1990) ascribed the 

alteration to extensive infiltration of meteoric fluids through 

fractures and to the generation of hydrothermal convection 

generated by the heat of the meteorite impact; his interpretations are supported by fluid inclusion studies by Komar 

and others ( 1988). 

FRACTURING 

The most altered zones down to 2,000 m are extensively fractured, and planar features are observed in quartz. 

Rock in the transitional interval from 2,000-4,000 m is 

less fractured, and there is no evidence of planar, shockinduced lamellae in quartz below 3,000 m. Below 4,000 m 

fracturing is slight and alteration is evident only in extensively fractured zones occurring at dolerite and quartz 

monzonite contacts and at regional tectonic zones, such as 

the Granan-Styggforsen fault zone. 

STRUCTURE AND CORRELATIONS 

The main structural features in the vicinity of the 

Gravberg I well are the low-dipping dolerite sills. Highly 

fractured granites are associated with the sills, but the lateral extent of the fractured granitic zones is undetermined 

(Castano and others, 1990). The original hole and the several sidetracks allow correlation of fracture zones within 

the granite itself. Highly radioactive intrusions of quartz 

monzonite and the related fracture zones dip 20°-60° 

south. These intrusions are not planar, but they most likely 

interfinger with one another and may end abruptly. 

FLUID GEOCHEMISTRY 

GEOCHEMICAL SAMPLING AND ANALYSIS 

A comprehensive series of geochemical measurements 

were made at the well site (Castano, 1988) and were coordinated with analyses carried out at off-site laboratories. 

The monitoring system was designed to analyze light hydrocarbons up to c5, and certain inorganic gases, such as 

hydrogen, helium, argon, radon, oxygen, and nitrogen, but 

not heavier hydrocarbons. Gas concentrations presented in 

this paper are in weight percent or ppm by weight. 

Progressive changes in drilling-fluid properties created 

interpretation problems. Proper interpretation required con-
m I MD} 

A 

PROSPECTS FOR COMMERCIAL ABIOGENIC GAS PRODUCTION 

Granite 

porphyry 

Dolerite 

R 1 Dolerite 

Dolerite 

R 2 Dolerite 

Dolerite 

Dolerite 

R 3 Dolerite 

Dolerite 

0 

c 

0 3: 

0 ,... :::> 

,... 

3 0 0 \D 

~ 0 0 :::> 

:::> 

;; " 

01 

0 ::: 

?.a· 

;;::> 

I 

I '-

o: 

~ 

::> 

0 

0 

0 

:::> 

'-

o: 

:::> 

0 

0 

0 

:::> 

;; 

m(TVD) 

1000 

2000 

3000 

4000 

' . . . ~ . 

5000 -r,-..,-.' ' < • 

. ' " 

6000 

. . . < • " X )( X~ 

·.·.·.t~ ' > X 

' . ' ' . . . . ' X It X X)( o(l . . " X X X ••• L ' . . X X x . . . < X X 

" x X X < X < > X 

X X x 

. " ' 

7 000 __._ __ ~ 

8 

Rl 

Granite 

porphyry 

Dolerite 

Dolerite 

Dolerite 

R2 Dolerite 

Dolerite 

R 3 Dolerite 

Dolerite 

0 

c 

0 

3 

0 

:::> 

,... 

0 

:::> 

;; 

3: 

0 

:;:1 

,... 

0 

\D 

0 

:::> 

;; 

'-

o: 

~ 

:;:1 

0 

0 

:;:1 

;; 

I 

j 

f 

V> 

0 

:::> 0 

;; :;:1 

'-

0: 

~ 

:;:1 

0 

Figure 5. Lithologic column in Gravberg well, presented according to (A) measured 

depth (MD) and (B) true vertical depth (TVD). Dolerite sills are indicated by horizontal 

lines across columns; Rl-R3 are dolerite sills that produced prominent reflections on 

seismic records (see figs. 3, 4). Quartz monzonite intrusions are indicated by ticks to 

right of columns. Modified from Anonymous (1991). 

FACTORS AFFECTING GAS READINGS 

141 

sidering contamination and the different retentive properties of the drilling fluids used: fresh water, and bentonitebarite, polymer, and oil-based muds. Fortunately, because 

the well was sidetracked three times and because the same 

sections were redrilled using different drilling muds, it 

was possible to compare gas readings from correlative 

sections. 

Many factors affect gas readings.- Each gas has a different solubility in water, controlled mainly by temperature 

and pressure and to a lesser extent by salinity (McAuliffe, 

1966; Price, 1979). Methane is much more soluble in water 

than ethane; hydrocarbons of progressively higher molecular 
142 THE FUTURE OF ENERGY GASES 

weight are progressively less soluble. The composition of 

headspace gas was affected greatly by drilling conditions; 

gas concentration varied inversely with the pH of the drilling fluid. When the drilling fluid was changed from a 

slightly acidic fresh water to an alkaline mud at 3,030 m, 

headspace gas concentration dropped by an order of magnitude (Laier, 1990; Jeffrey and Kaplan, 1988). Because the 

drilling fluid was aerated, N2 and 0 2 data were of no value. 

In addition, because, 0 2 is scavenged by the drill pipe, the 

drilling fluid, and the cuttings, N2/02 ratios could not be 

used to detect indigenous nitrogen. 

A significant effect of the use of the oil-based mud (80-

percent diesel, 20-percent water) in ST-2 and ST-3 is that 

light hydrocarbons are very soluble in diesel. Because dissolved gases tend to remain in circulation in the oil-based 

mud, the monitoring system records higher background values. Higher mud weights of the oil-based drilling fluid 

(compared with weights of water used in the original hole 

and ST-1) may have suppressed gas readings because the 

system was strongly overbalanced (that is, because fluid 

pressure in the mud column was greater than the formation 

pressure). The same was true for the bentonite-barite mud 

used in the original hole. 

CONTAMINATION 

Contaminants were a source of great concern because 

the total amount of light hydrocarbons was below 1,000 

ppm. We considered the possibility that hydrocarbons and 

hydrogen could be created artificially in the borehole ("bit 

metamorphism"). We also monitored and catalogued the 

types and amounts of additives and lubricants and the incidence of abnormal amounts of metal, rust, rubber, and 

other materials in the borehole. 

Some of the organic additives are directly implicated 

in the generation of hydrocarbons. For example, while 

drilling was conducted in granite just below 5,000 to 

5,671 m in the original hole, increases in the quantity of 

butene (up to 2,234 ppm) and propene (as high as 388 

ppm) and high methane values coincided with the addition 

of Idlube. Idlube, used to prevent drill-pipe sticking, contains a vegetable oil that is a mixture of polyunsaturated 

esters, called rape oil. If the increased butene, propene, 

and methane were derived from Idlube, they were the result of pyrolytic breakdown because rape oil contains only 

traces of volatile hydrocarbons. The corresponding interval 

in ST-1 contained only a few ppm of butene. 

In ST-1 use of the lubricant "torque trim" below 5,500 

m coincided with greatly increased shows of pentane (up 

to 445 ppm) and a drop in the C/C2 ratio from 25-42 to 

1.5-6. "Torque trim" contains a small but significant 

amount of light hydrocarbons in proportions that can account for the shows in this interval. Again, the equivalent 

interval in the original hole lacked these shows, a lack 

which leads to the conclusion that much of the hydrocarbons encountered in this interval were artifacts. 

LABORATORY EXPERIMENTS 

Three laboratories conducted a number of experiments 

to investigate the origin of the gases in the Siljan area. 

The chemical and isotopic composition of gas obtained 

from headspace was compared with that of gas released by 

acid treatment (desorbed gas) and that of gas released 

from the samples by ball-mill crushing. The core and cuttings samples were carefully prepared so as to remove 

traces of contamination, such as iron from the drill string. 

(See section "Synthesis-Interpreting Shows" for additional details.) 

The chemical or isotopic composition of gas in the 

dolerites was unaffected by acid treatment or ball-mill 

crushing. Included in this set was gas from a dolerite core 

at a depth of 97 m from the Htsas corehole; the gas recovered by acid treatment of this dolerite core had the same 

chemical composition as the gases recovered from cuttings 

samples of dolerite from the Gravberg 1 well. The gas 

from the Fasas core also has an isotopically very heavy 

methane: &13C of -10.7 permil. 

Most of the hydrocarbons released by acid treatment of 

the granite were associated with the magnetic fraction of 

the rock. An average of 5,800 microliter/kg was measured 

in the magnetite-rich fraction, and only 60 microliter/kg in 

the nonmagnetic fraction (Laier, 1990). The gases are rich 

in C2+ hydrocarbons, and the proportion of alkenes is 

high. In the dolerite, the nonmagnetic fraction has the 

higher gas concentration, although the difference is only a 

factor of 5 in the dolerite, in contrast to a factor of 97 in 

the granite. 

Ball-mill crushing of granite and dolerite cuttings 

samples produced gases with compositions similar to those 

obtained in acid treatment, but the yields were significantly lower. 

UNCONTAMINATED SAMPLES 

After well stimulation in 1989, the drilling manager 

noticed that gas was bubbling out of the top of the drill 

pipe as the drill string was being pulled out during a wet 

trip. (Normally, the drill string is removed from the borehole dry, without fluids. In special cases, the base of the 

drill string is plugged in order to recover fluids; this is 

classed as a wet trip.) Special sampling devices were built 

to sample this gas. A sampling line equipped with valves 

and a pressure gauge was attached to a short piece of drill 

pipe with a threaded connection to the top of the drill 

string. Because gas pressure at the top of the drill pipe 

was usually 1 to 2 bars, there was sufficient positive pres-
PROSPECTS FOR COMMERCIAL ABIOGENIC GAS PRODUCTION I43 

sure for gas to displace air contained in the sampling system, and the samples were collected in evacuated steel 

cylinders as usual. These samples contained little air, and 

for the first time, good-quality high-volume gas samples 

were collected. During pump testing in 1990, samples that 

were collected from a modified gas separator were relatively free of contamination, and they also provided goodquality high-volume samples. 

SYNTHESIS-BACKGROUND FOR 

INTERPRETATION 

COMPOSITION OF HYDROCARBON GASES 

The Earth's mantle is degassed along midoceanic ridges, and rehydration and possibly recarbonation occur along 

subduction zones (Wood and others, 1990). Measurement 

of oxygen fugacity in mantle xenoliths by Bryndzia and 

Wood (1990) and Wood and others (1990) shows that C02 

and H20 are the main fluids in the asthenosphere. Methane 

is comparatively rare in the mantle and would be found 

mainly at mantle hot spots. In Thomas Gold's (1979, 1987) 

expectation model, reduced carbon in the form of methane 

streaming up from anywhere in the mantle would provide 

the hydrocarbon charge for crustal structures. However, the 

model is not supported by the experimental work cited 

above and by the studies of Bath and others (1986), nor (as 

will be shown later) by the information gained from th~ 

Gravberg I well. 

Fluid inclusions in igneous rocks and gases recovered 

from igneous rocks by grinding and heating contain unsaturated hydrocarbons in varying proportions (Freund and 

others, 1982; Konnerup-Madsen and others, 1988; Ferguson, 1987). The presence of some unsaturated hydrocarbons in undisputed free gases in the East Pacific Rise, in 

Yellowstone National Park (United States), in the Zambales ophiolite (Philippines), and in fluid inclusions show 

that unsaturated hydrocarbons can be stable over long periods of time. Traces of unsaturated hydrocarbons, such as 

the alkenes ethylene and propylene, occur in gases of bacterial origin (Burke and others, 1981; Zhizhchenko, 1978), 

but they are otherwise rare in biogenic or thermogenic 

gases. The high proportion of alkenes noted in igneous 

rocks is characteristic of a catalytic reaction, such as the 

Fischer-Tropsch reaction (Biloen and Sachtler, 1981 ). In 

this reaction, carbon monoxide and hydrogen combine in 

the presence of a suitable catalyst, such as magnetite, to 

form hydrocarbons and water. Because carbon dioxide and 

hydrogen equilibrate with carbon monoxide and water with 

a magnetite catalyst at lower temperatures, the concentration of carbon monoxide need not be high (Laier, 1988). 

Unsaturated hydrocarbons are compounds in which some 

carbon atoms are held together by double bonds and hence 

are not completely saturated with respect to hydrogen; they 

have the general formula CnHzn· The Jwo main groups of 

unsaturated hydrocarbons are the aromatics (closed ring 

compounds) and the alkenes (open chain compounds). The 

alkenes (also called olefins) are more reactive than saturated hydrocarbons. Saturated hydrocarbons are compounds 

that are saturated with respect to hydrogen. In this paper, 

references to unsaturated hydrocarbons refer only to the 

alkenes. In the Ilfmaussaq alkaline igneous rocks of Greenland, Konnerup-Madsen and Rose-Hansen (1982) and 

Konnerup-Madsen and others (1988) found that condensation or polymerization reactions have led to the formation 

of a number of saturated hydrocarbons up to pentane. 

ISOTOPIC COMPOSITION OF 

HYDROCARBON GASES 

The carbon isotopic composition of methane is closely 

tied to process of gas generation, type of source rock, maturation history, migration, and fractionation (Schoell, 1984; 

Fuex, 1977; MacDonald, 1983). Three principal classes of 

hydrocarbon gases are known: microbial, thermogenic, and 

abiogenic. Microbial and thermogenic gases can generally 

be identified by their methane 6 13C signature. Thermogenic gases are formed by the breakdown of organic matter; 

their 613C values are usually heavier (less negative) than 

-50 permil, whereas microbial (bacterial) gases, formed 

only at temperatures less than 75°C, generally have 613C 

values lighter than -60 permil. Thermogenic gases become 

isotopically heavier with increased thermal maturity, and 

the 613C value for methane will approach that of the 

source carbon at high maturity. 

Whereas liquid petroleum compounds have 6 13C values 

similar to those of the organic carbon source, hydrocarbon 

gases usually display a strong fractionation in comparison 

with the source carbon (Fuex, 1977). Primary fractionation 

of carbon isotopes takes place as a source carbon is transformed into a· hydrocarbon product; this fractionation is 

measured as the ratio of 6 13c of the source to 6 13C of the 

product ((6 13Csource+1000)/(6 13Cproduct +1000)). Two factors dominate the fractionation process: maturity and organic-matter type. Derivation of methane from lipid organic 

matter will produce a fractionation that can lighten the 6 13c 

values of methane by as much as -30 permil, whereas derivation from coal and humic matter produces a much smaller 

fractionation, about -10 permil (Fuex, 1977). With increasing thermal maturity, the fractionation decreases, and the 

613C value for methane approaches that of the source carbon, which normally ranges from -20 to -30 permil. The 

variation in fractionation between lipid and humic kerogen 

is probably related to differences in the structure of the 

organic matter and to the way 13c is distributed in the 

kerogen (Fuex, 1977). 

Migration fractionation (fractionation of carbon isotopes in the hydrocarbon after it has left the source rock) 

is probably not a major factor in establishing the methane 
144 THE l<LJTURE OF ENERGY GASES 

carbon isotopic compositiOn of major gas deposits, but 

fractionation effects can be significant in very dilute gas 

samples obtained from surface samples or from minor gas 

shows obtained while drilling (Fuex,. 1977). 

The isotopic composition (o13C) of primordial carbon 

is generally assumed to be around -4 to -8 permil (Konnerup-Madsen and others, 1988), and abiogenic methane 

from a deep source should approach this range. Gases from 

the East Pacific Rise have a o13C for C1 of -17 permil 

(Welhan, 1988). Abranjo and others ( 1988) measured a 

o13C value of -7 permil for methane in the Zambales ophiolite in the Philippines. Even heavier methane was extracted from fluid inclusions in the llfmaussaq alkaline complex 

in Greenland; 6 13C in this methane ranges from -1 to -7 

permil (Konnerup-Madsen and others, 1988). 

GRAVBERG 1 WELL: 

Granite * Dolerite ~ 

Desorbed gas * -50 0 

DST no. 5 * 

E 

,_ 

® Q) 

a. 

~ 

"' I -30 ,__.. 

0 @ 

* 

@\ ARTIFICIAL 0 ® "' A@ I 00 A 

I 

-10 

I ' 

-700 -500 

Fuex and Baker (1973) studied the noncarbonate (combustion) carbon in a group of igneous rocks and found that 

o13c of the carbon in granites ranged from -19.7 to -26.6 

permil; in mafic and ultramafic rocks the range was -22.2 to 

-27.1 permit. These results imply that a simple mantle outgassing model for carbon is not likely. Instead, carbon has 

been incorporated in igneous rocks through partial melting 

of subducted sediments. On the basis of the work ofFuex and 

Baker (1973), the isotopic composition of methane derived 

from such rocks would have a o13C of -20 to -27 permit. 

The deuterium isotopic composition of hydrocarbon 

gases is very useful in establishing the genesis of natural 

gases (Schoell, 1984) and in detecting artificial gases 

(Faber and others, 1988). A useful plot is oD versus o 13c 

of methane (fig. 6). Abiogenic gases from Ilfmaussaq 

\ I \. . fermentatio~ ~o, Reduct1on . Bacterial ......._ 

M \ I -- \ / /\ '-......... -~~ / 

~/ \ 

/ ~ / ~~ \ (?& ®" ""-. z ~ (;1 \ "-''t_~ 

® "-... * *' \ 

"'-* ®® * ~D \ \ E~ 

~@~ 

4 ~ 4 ~ 

p 

-300 -100 

80 (CH4}, permil 

Figure 6. Plot of oD versus o 13C for methane, classification modified after Faber and others (1988). Gases from Gravberg 1 well 

plotted according to legend on figure; desorbed gas is gas released 

by acid treatment; DST no. 5 refers to drill-stem test 5 and includes 

gas recovered during the drill-stem test and also during later pump 

testing. Other symbols are as follows: A, artificial gases; D, diabase, 

Massachusetts, USA (Jeffrey and Kaplan, 1988); E, East Pacific 

Rise (Welhan, 1988); I, Ilfmaussaq, Greenland (Konnerup-Madsen 

and others, 1988); M, Matagami, Quebec, Canada (Fritz and others, 

1987); P, Zambales ophiolite, Philippines (Abranjo and others, 

1988); Z, Zinkgruvan, Sweden (Castano, 1990). Siljan locality not 

plotted (off scale): yastana, oD=-238 permil, o13C=-67.8 permil. 
PROSPECTS FOR COMMERCIAL ABIOGENIC GAS PRODUCTION 145 

(Greenland) and the Zambales ophiolite (Philippines) are 

distinct from other gases in the figure, as is the gas from 

the East Pacific Rise, which comes out of basalt and is 

accompanied by helium with a mantle signature (Welhan, 

1988). Faber and others (1988) identified artificial gases as 

those gases with extremely light oD values (less than -600 

permil) that were found mainly while drilling in granite. 

These gases are formed by an unknown mechanism, although Faber and others ( 1988) favored a Fischer-Tropsch 

reaction, with the carbon source being derived from the 

drill pipe, the lubricants, or the granite. 

Another useful approach for identifying abiogenic hydrocarbons is comparison of the carbon isotopic compositions of the light hydrocarbons (fig. 7). James (1983) and 

Sofer (1985) showed that in typical thermogenic gases, the 

isotopic composition of the higher hydrocarbons becomes 

-10 

-30 ·-E 

.... 

Q) 

Q. 

(.,) 

M 

'o 

-50 

-70 

A 

GAS INCLUSIONS IN 

IGNEOUS ROCKS (0) 

VENEZUELA -----(j] __ --- --1!) 

@. 

I 

I 

~I C, I 

~I 

~I 

~/ I 

I 

r;{ 

1 

I 

2 3 4 

GASEOUS HYDROCARBONS, BY 

NUMBER OF CARBON ATOMS IN 

COMPOUND 

5 

Figure 7. Isotopic composition of gaseous hydrocarbons. A, Note 

that trends for diabase (dolerite) and granite (both from Gravberg 

I well) (Castano, I990) are similar to those for abiogenic gases 

(Philippines (Sofer, 1985) and gas inclusions in igneous rocks), 

whereas trend for DST 5 (drill-stem test 5 on Gravberg I well) is 

similar to those for thermogenic gases (lines labeled Venezuela, 

Wyoming, and North Sea (Fuex, 1977)). Line labeled Quebec is 

for an oxidized thermogenic gas (Fuex, 1977). B, Isotopic. trend 

progressively heavier (Venezuela, Wyoming, and the North 

Sea). In co~trast, gases which are known or suspected to 

be of abiogenic origin have a characteristic trend: gas inclusions in igneous rocks and gas samples of suspected 

abiogenic origin obtained from drill-stem tests in a well 

from the Philippines ·become isotopically lighter with increasing carbon number. The example from Quebec shown 

on figure 7A is a case in which the methane isotopic composition has become lighter due to oxidation, but ethane 

and propane have not been not affected (Fuex, 1977). 

Des Marais and others (1981) studied hydrothermal 

gases; their isotopic curves (not shown) are very similar to 

the thermogenic gas profiles shown on figure 7A and to 

results from their experiments on the thermal decomposition of hexane (see line labeled "Thermal decomposition of 

hexane" on fig. 7B). They concluded that the hydrocarbons 

-10 

-30 

....... 

·e ,_ 

Cll 

E: 

0 

"' 'io 

-50 

-70 

B 

vel' 

;-;,# ~fli' 

German coal gas -# Thermal *--

*-

• rr< 

1 

----*- decomposition 

* .. ·D 

.o··· of hexane 

o· Zinkgruvan --* 

.. Spark synthesis 

. ·• ~ . ..... 

2 3 4 

GASEOUS HYDROCARBONS, BY 

NUMBER OF CARBON ATOMS IN 

COMPOUND 

5 

for spark synthesis (Des Marais and others, 1981) is similar to 

that for abiogenic gases (gas inclusions in alkaline igneous rocks 

from Greenland (Konnerup-Madsen and others (1988)), whereas 

trends for thermal decomposition of hexane (Des Marais and others, 1981), metasedimentary rocks in the (former) USSR (Petersil'ye and Pavlova, 1975), and Zinkgruvan, Sweden (Castano, 

1990), are similar to those for thermogenic gases (compare with 

fig. 7A). 
146 THE FUTURE OF ENERGY GASES 

they studied were produced largely by the thermal breakdown of organic matter in hydrothermal gases. Their experiments with the formation of hydrocarbons from 

methane in a spark discharge produced an isotopic profile 

analogous to abiogenic profiles (see line labelled "Spark 

synthesis" on fig. 7 B). Welhan (1988) concluded that there 

is no firm evidence for abiogenic production of methane at 

hydrothermal temperatures, but that in hydrothermal systems dominated by high-temperature rocks, such as in midoceanic-ridge settings, abiogenesis represents the main 

process of methane generation. 

INORGANIC GASES 

The nature of the noble gases, mainly helium but also 

argon and neon, is significant in establishing their origin. 

There is a marked difference between isotopic compositions 

of noble gases in the asthenosphere and those that result 

from various processes in the Earth's crust and biosphere. 

For example, the isotope 3He is produced mainly in stellar 

reactions and was contributed to the Earth as primordial 

helium during accretion and planetary formation (Jeffrey 

and Kaplan, 1988). Although 3He has degassed considerably from the Earth's crust, it is still present in high concentrations in the Earth's mantle, and in fact increases in 

concentration with depth in the Earth's interior. In contrast, 

4He is formed as the result of radioactive decay of uraniumand thorium-bearing minerals in the crust. The variation in 

the isotopic ratios of helium in various environments is 

shown on figure 8; helium ratios (R=eHe/4He)sampJe) are 

typically presented in comparison with atmospheric helium 

ratios (Ra=eHe/ 4

He)atmosphere)· High R/Ra ratios (indicative of mantle gases) were measured in some of the localities where isotopically very heavy methane (also indicative 

of mantle gases) was found, such as the midocean-ridge 

basalts (MORB) and the Zambales ophiolite. Natural-gas 

deposits associated with active continental margins contain 

a significant mantle helium component (Poreda and others, 

I 988). Therefore if hydrocarbon gases (with enriched 613C 

signatures) are associated with primordial 3He, there is reason to believe a mantle source .. 

Hydrogen is rarely found in sedimentary basins, although it is reported at a number of localities in igneous 

rocks (Coveney and others, 1987; Neal and Stanger, 1983; 

Konnerup-Madsen and others, 1988). Neal and Stanger 

(1983) described gases, containing mostly hydrogen, that 

emanate from serpentinized ultramafic rocks in Oman; 

these gases also include up to 5 percent methane and small 

(ppm) quantities of light hydrocarbons. In the T!<1nder wells 

in Denmark, tests of gases from the Zechstein Formation 

measured up to 16 percent hydrogen; the remainder was 

chiefly nitrogen with small amounts of hydrocarbons (Geological Survey of Denmark, written commun., 1988). 

Hydrogen can be formed in nature by the serpentinization of ultramafic rocks, redox processes involving mafic 

minerals, shearing reactions in igneous rocks, and direct 

outgassing of the mantle. Isotopic analysis of hydrogen 

(determination of 6D) often is not very revealing, as the 

isotopic composition of hydrogen reequilibrates very rapidly with water, and any indication of a deeper, higher 

temperature source can thereby be erased. 

KEY ELEMENTS FOR HYDROCARBON 

ENTRAPMENT 

Several key elements are crucial for hydrocarbon entrapment: (1) a seal, (2) a reservoir, and (3) a source of 

hydrocarbons. 

A seal must be configured to trap and retain oil or gas. 

The physical behavior of a seal depends on the hydraulic 

conductivity of the rock together with the water content of 

the void space. It is estimated that a caprock with a hydraulic conductivity of w-IS rn/s could retain a 100-m gas 

column (Anonymous, 199 I). However, substantial losses 

due to diffusion can occur over a period of several million 

years; the amount of diffusion depends on seal character 

and time (Leythaeuser and others, 1982). 

3

He/'He R/Ra 

10-3 

100 

10-4 

10 

10-5 

10-6 

0.1 

10-7 

0.01 

[ 

[ 

~ 

ENVIRONMENT 

SOLAR 

PLANETARY 

PLUMES (HOT SPOTS) 

MID-OCEAN RIDGES 

ISLAND ARCS 

ATMOSPHERE 

CONTINENTAL 

ROCKS 

CRUSTAL 

GASES 

Figure 8. Variation in 3He/ 4He and R!Ra ratios in various environments. R1Ra=CHe/ 4

He)sampleiCHefHe )atmosphere• normalized to the atmospheric value (Ra) of 

1.40x w-6 from Mamyrin and others (1970). The star 

symbol represents the mean R!Ra ratio of 0.015 to 0.018 

obtained from the Gravberg 1 well. Modified from Jeffrey and Kaplan (1988). 
PROSPECTS FOR COMMERCIAL ABIOGENIC GAS PRODUCTION 147 

The best seals have low hydraulic conductivity, wide 

lateral distribution, and uniform lithology, and are relatively ductile. In a brittle rock such as granite, the formation of 

effective seals and traps would be much more complicated 

because fractures would tend to stay open. Gold's original 

expectation model called for calcite produced from the oxidation of mantle methane combined with other minerals to 

form a seal. A subsequently modified model proposed by 

Gold contended that mineral-healed fractures accompanied 

by closure of the remaining very thin water-filled fractures 

would be the sealing mechanism (Anonymous, 1991 ). 

Conventional reservoirs have a much more homogenous porosity and permeability distribution than unweathered crystalline bedrock, such as the Jarna and Siljan 

Granites and associated dolerites. In order to have a viable 

commercial reservoir at Siljan, porosities would have to be 

at least an order of magnitude higher than in typical Swedish granites, in the 1-5 percent range. Although typical 

tight gas sandstone reservoirs have porosities of 8 to 10 

percent, fractured shale and carbonate reservoirs have porosities as low as 3 percent (R.M. Sneider, oral commun., 

1987). Fractures in the crystalline rocks would have to be 

open and interconnected, with higher than normal hydraulic conductivity (I o-9 to w- 11 m/s). 

The concepts of generation and entrapment are so very 

well known that they will not be reviewed here (Hunt, 

1979; Tissot and Welte, 1984). The association of worldclass source rocks with major oil and gas accumulations is 

well documented (for example, Demaison and Murris, 

1984; Ulmishek and Klemme, 1990; Magoon and Dow, in 

press). Although commercial hydrocarbon deposits have 

been developed in igneous and metamorphic rocks 

throughout the world, these deposits have been correlated 

with organic-rich source rocks. Bath and others (1986) 

made a detailed study of oil and bitumen shows in crystalline rocks in the United Kingdom; they concluded that in 

all cases the hydrocarbon source was organic. Source rocks 

are present in Silurian and Ordovician sedimentary rocks 

on the periphery of the Siljan Ring (Vlierboom and others 

1986); these rocks could contribute trace organic compounds within the crystalline rocks within the impact structure. A possible mechanism for the movement of organic 

compounds could be deglaciation. Deglaciation would 

have the effect of rejuvenating open fractures and allow the 

deep penetration of meteoric waters, which could carry 

with them dissolved organic compounds plus oil and gas. 

SYNTHESIS-INTERPRETING SHOWS 

SHOWS IN DOLERITE AND GRANITE 

The dolerite intrusions have considerably higher hydrocarbon gas concentrations than the granite. The R3 dolerite was analyzed at closely spaced intervals in ST-1; 

there is far more methane in the R3 dolerite (200 to I ,000 

ppm) than is typically found in the granite (I 0 to 80 ppm) 

(fig. 9). High concentrations of methane in the granite between and immediately below the two dolerite layers may 

reflect a contribution from the dolerite. Hydrogen content 

Figure 9. Geochemical 

data in vicinity of R3 dolerite, sidetrack I (ST-1) 

of Gravberg I well. Horizontal scales are linear, 

except methane content 

(in ppm) which is logarithmic. Methane content 

in ppm is the measured 

methane content in headspace gas; methane content in percent is the 

percentage of methane 

with respect to the total of 

all hydrocarbons. Note 

contrast between the topmost granite and the dolerite in all data sets 

except bD; data from the 

two lower granite units 

may be influenced by 

contribution from the 

dolerite. 

METHANE 

(ppm) 

MErnANE 

(percent) 

c5D (perm ill 

1 

4700 - ~ 

E ~ J:: 

..... 

c. 

Cll 

c 

-

4750 

100 1000 80 100 -10 -20 -30 

gr 

** I ~ dol ~ * ~ * ** ~ ~ 

$<~ - * * gr 

- dol * ~ ~ 

~ 

~ *~ * 

* ~ 

gr ~ 

~ 

~ ~ ~ 

EXPLANATION 

.. dunk-tank gas 

~ headspace gas 

gr granite 

dol dolerite 

-100 -300 

~ 

~ * 

~ 

~ 

~* 

~ 

~ 
I48 THE FUTURE OF ENERGY GASES 

is much the same in both rock types. Shows in the various 

dolerites are similar: they have a very high proportion of 

methane (:2:95 percent is typical). Unsaturated hydrocarbons are rare. 

The R3 dolerite exhibits a very heavy isotopic composition: o13C for cl ranges from -IO to -21 permil, whereas 

methane in the granite immediately overlying the dolerite 

has a o13C of -29.5 permil (fig. 9). Several of the granitederived gas samples below the main dolerite have a dolerite 

isotopic signature, which may due to the following explanations: (I) Diffusion of gas out of the dolerite can contribute to the total gas. (2) The gas could come from the thin 

dolerite below the main body. (3) Headspace gas samples 

below 4,750 m contain some dolerite cuttings, which would 

yield a heavy gas. 

The gas in the dolerites has a very consistent molecular and isotopic signature, regardless of the method of analysis (headspace gas, gas released by acid treatment, or gas 

released by crushing in a ball mill (Laier, 1990). The headspace gas from a core taken from the RI dolerite from a 

depth of 1,477 m yielded a o13c for methane of -I5.9 permil, a value which is similar to that of headspace gases 

from cuttings. The Danish Geological Survey obtained a 

o 13c of -10.5 permil at I ,59 I m from gas released from 

dolerite cuttings by acid treatment. The Danish Geological 

Survey also used the same technique on a dolerite core 

from Hisas; 613C of methane was -10.5 permil. Laier 

(1988, 1990, 1992) reports the presence of abundant tiny 

fluid inclusions in the dolerites, but they were too small to 

analyze. He believes that the gas in the dolerite comes 

from these inclusions. 

A sample from the R2 dolerite provided the only reliable helium data from dolerites in the well: according to 

Hilton and Craig (I989) a sample from 2,59I m had 539 

ppm He with an R!Ra value of 0.075, which indicates a 

mixture of crustal and atmospheric helium. Any primordial 

helium in the dolerite would be overshadowed by radiogenic helium formed in the last 900 m.y. 

Gases in the dolerites are abundant, are rich in methane, and lack unsaturated hydrocarbons. Gases in the granite are present in much lower concentrations, contain about 

50-70 percent methane, and contain high percentages of 

ethane and propane (C1/C2 ratio is 8 to IO). Granite gases 

are also rich in unsaturated hydrocarbons: ethane/ethene 

and propane/propene ratios are both about one. The granite 

gases have a very high proportion of ethene and propene in 

comparison with other natural gases, but they are similar in 

that regard to gases manufactured by the Fischer-Tropsch 

reaction. 

Gases in the granites fall into two groups: one is dominated by saturated hydrocarbons and the other by unsaturated hydrocarbons. The saturated hydrocarbon group is 

more closely associated with fracture zones. These could 

be indigenous gases generated abiogenically, or they could 

be derived mainly from sedimentary organic matter carried 

deep into the granite along fracture zones by meteoric 

water or as a result of the impact. The unsaturated hydrocarbon group does not have a clear association with any 

particular setting within the granite. These are abiogenic 

gases formed by a Fischer-Tropsch catalytic reaction between C02 and H2; magnetite is the likely catalyst (Laier, 

1988). The processes described in this paragraph take place 

at relatively low temperatures in the crust, not the mantle. 

Hydrogen is present in quantities exceeding methane 

usually by at least one order of magnitude. In ST-3, H2 

content averaged over 4,000 ppm in two zones: from 

6,705-6,751 m and 6,873-6,895 m. Helium was noted sporadically throughout the well: where helium was present, 

concentrations were generally 50 ppm or less, except below 

6, I 50 m where helium concentrations averaged 500 ppm. 

DRILL-STEM TESTS 1 THROUGH 4 

No hydrocarbons above background values were recovered from drill-stem tests (DST's) I through 4. Background values typically were I 0 to 20 ppm, far below the 

background gas readings normally found in producing basins (where background gas readings often are 1,000 ppm 

or more). In DST 3, the fluids collected from the interval 

between I ,963.5-I ,990 m had radon values of 78 to I85 

counts per minute (cpm), whereas the mud tested during 

drilling through this interval had radon values of less than 

I cpm. The presence of elevated radon levels in the fluid 

recovered from the test indicates that formation fluid was 

recovered. The water has less than 500 ppm total dissolved 

solids, it is dominated by sodium bicarbonate, and, on the 

basis of a 6180 value of -Il.3 permil and a 6D value of -86 

permil (both relative to standard mean ocean water 

(SMOW)), it falls directly on the meteoric water line. 

DRILL-STEM TEST 5 AND 

PUMP TESTING IN 1990 

GAS GEOCHEMISTRY 

DST 5 tested the entire open-hole section of ST-3 

from the base of the 7 3/4 inch liner at 5,453 m to total 

measured depth at 6,957 m, although the effective base of 

the tested interval may actually have been around 6,300 m 

because of uncertainties concerning the effectiveness of 

well stimulation. After a hiatus of 8 months, the same interval was pump tested from May to early July 1990. 

During testing, the gas samples differed remarkably 

from those collected while drilling through the same interval. Because of improved sampling methods, the oxygen 

content (a measure of atmospheric contamination) of DST 

samples was less than I percent, and pump-test samples 

contained I-2 percent instead of the 8-I5 percent meas-
PROSPECTS FOR COMMERCIAL ABIOGENIC GAS PRODUCTION 149 

ured while drilling. Much higher levels of i-butene were 

recorded during pump testing (an average of 62 ppm) than 

during DST 5 (less than 20 ppm). As i-butene is not a 

natural product, the increase in concentration shows that it 

is being formed in the borehole or the formation. Typical 

DST 5 gas composition was 2. 7 weight percent hydrogen, 

54 percent helium, 2.1 percent argon, 0.2 percent oxygen, 

41 percent nitrogen, and 150 ppm methane. Before testing 

and fracturing, hydrogen was the dominant gas and helium 

was next in abundance but in much smaller concentrations. Methane content was usually 100-500 ppm. After 

fracturing, helium became the dominant gas. 

Water collected during DST 5 was undersaturated with 

gas; the volume of gas per unit volume of water was 

0.25 m3!m3. For comparison, if formation water at about 

6,000 m were saturated with gas, one would expect to measure an approximate saturation level for methane of 5 m3

/m3

, 

and for helium of about 3 m3/m3. During the pump-test 

period, gas saturation was measured at 0.3 m3

!m3 of water 

from the gas separator. However, the separator was not operating very efficiently, and the saturation could have been 

as high as 1.0 m3

!m3. The formation water throughout the 

entire well was similarly undersaturated with gas; therefore, gas in the formation was strictly in solution and no 

gas was present as a separate phase. 

The isotopic composition of the hydrocarbon gases 

obtained after fracturing was different from that measured 

while drilling; the postfracturing gases had a 613c for cl 

of -44.8 to -56.9 permil, 613C for C2 of -32 permil, and 

613c for c3 of -29.1 permil. 6D for methane was -470 

permil (fig. 6). 

Helium c3HefHe) ratios yielded an R/Ra of 0.016 to 

0.022; these values plus argon (

40 ArP6 Ar) ratios and neon 

isotopic data show that all these gases originated in the 

crust as by-products of the breakdown of radioactive minerals in granite. Hydrogen typically constituted 1 to 3 percent of the total gas; there seems little doubt that it is 

indigenous to the granite, but the precise mode of its origin remains uncertain. 

WATER GEOCHEMISTRY 

Although large volumes of fresh water were pumped 

into the formation as part of the hydrofracturing operation, 

the recovery of bona fide formation water was verified by 

the use of tritium analyses, conducted by Dr. R. Saxena of 

Uppsala University, Sweden. The injection water has a tritium content of 22 tritium units (TU), showing that it is a 

mixture of pre- and post-1952 water. At the end of the test 

period the recovered water had a tritium content of 5 to 7 

TU; it is a mixture of formation water (around 0.5 TU) and 

injection water. The formation water is highly saline, with 

more than 150,000 ppm total dissolved solids, and has a 

Ca/Na ratio of 2.9 to 3.2. The 173.67 m3 of water recovered during pump testing was similar in composition. 

INTERPRETING FLUID 

GEOCHEMICAL DATA 

DISCUSSION 

The relationship of 613C to 6D in C1 in samples from 

this project together with data from the literature are 

shown in figure 6. The dolerite gases group tightly together regardless of sample type, and they are unlike any other 

major group of natural gases; they are considered to be 

abiogenic in origin. In contrast, the gases from the granite 

show a great spread. Several granite gas samples fit fairly 

close to the dolerite grouping; they may have dolerite affinities. The other free gas samples collected from the 

granite fit in the thermogenic field, while the acid-treated 

(desorbed) gases are scattered over a wide area, which is 

unusual. Faber and others (1988) would consider these desorbed gas samples to be dominantly artificial, an interpretation which agrees well with the experiments of Laier 

(1990) and Jeffrey and Kaplan (1988). 

Two gas samples from pump testing and DST 5 plot 

apart from samples obtained from the well during drilling 

(fig. 6). These gases have a 613C for methane of -44.8 to 

-56.9 permil, 613c for ethane of -32 permil, and 613C for 

propane of -29.1 permil. It is possible that the light hydrocarbon gases represent isotopically very light gas of bacterial origin as a contaminant mixed with gas with a 613c 

for methane of -29 to -38 permil (as measured on six samples obtained before the well was stimulated). 

Three isotopic profiles are shown for Gravberg 1 on 

figure 7A: granite, diabase (dolerite), and DST 5. The isotopic profiles for granite and dolerite display abiogenic 

characteristics. However, these data do not reveal where 

the gas originated (crust or mantle) or by what process. 

Possible processes are a catalytic reaction such as the Fischer-Tropsch reaction, or spark discharge during tectonic 

shearing of igneous rocks. DST 5 has a thermogenic isotopic profile, which also holds for samples collected during the drilling of ST-3. Oil-based mud may be an 

important influence on this distribution. In the test gases, 

the methane may represent a mixture of very light gas of 

bacterial origin as a contaminant and heavier methane produced by one of the crustal processes cited above. 

Helium from Gravberg 1 is predominantly of crustal 

origin with an upper limit for mantle helium contribution 

of just 0.15 percent (Hilton and Craig, 1989). Its occurrence strongly correlates with the presence of high uranium and thorium content in quartz monzonites. 

The stable isotope ratios of hydrogen in the gases at 

Gravberg 1 are consistent with a low-temperature origin 

(about 80°C). This origin can be explained by one of the 

three following mechanisms: (1) Hydrogen is formed locally in the granite, most likely by the reduction of formation water by ferrous minerals. (2) Hydrogen is formed in 

a deeper, high-temperature setting, and is reequilibrated 
150 THE FUTURE OF ENERGY GASES 

with water at formation temperature. (3) Hydrogen is 

formed by spark discharge during shearing. 

SUMMARY -NO SOURCE 

The evidence at hand shows that trace quantities of 

hydrocarbon gases in the dolerites are abiogenic, and they 

may be trapped in tiny fluid inclusions, adsorbed on mineral grains, or dissolved in the pore water. Because of the 

very low gas saturation in the formation water, there is no 

free gas in either the dolerites or the granites. The highest 

concentrations of hydrocarbon gases in the dolerites are 

less than 1 ,000 ppm. 

Hydrocarbon gases in the granite are present in much 

lower concentrations than in the dolerites, and these gases 

contain a high percentage of ethane and propane and their 

unsaturated analogues. The unsaturated compounds are 

rarely found in nature, and they could be formed through 

catalytic reactions such as the Fischer-Tropsch reaction. 

They could also be formed by a spark discharge reaction 

which can cause condensation or polymerization (Des Marais and others, 1981; Enomoto and Hashimoto, 1990; 

Martelli and others, 1989). Another possibility is that many 

of the hydrocarbons in the granite are drilling artifacts. Although the processes discussed here are abiogenic, they 

take place in the crust or in the borehole, and they do not 

constitute a viable source of commercial hydrocarbons. 

INTERPRETING RESERVOIR DATA 

Prospective reservoir zones in fractured intervals were 

identified by integrating data from studies of cuttings with 

drilling parameters and wireline log data (Castano and 

others, 1988, 1990). · 

Fracture zones are recognized using the following criteria: (1) no breakouts, hole remains in gauge (that is, the 

hole is only slightly larger than the diameter of the drill 

bit), (2) high rate of penetration, (3) increase in sonic transit time, (4) decrease in deep-resistivity-log readings, (5) 

increase in occurrence of fracture-zone minerals, and (6) 

observations of fractures in cuttings. 

The criteria used to recognize fractured intervals in 

crystalline rock are similar to those used to recognize intervals of sedimentary rock. In the granites in Gravberg I, 

porosity is developed chiefly in altered feldspar, in authigenic epidote, and in mylonite. 

Porosity and permeability data from cores and sidewall samples are shown in table 1. Porosity and permeability are very low, although porosity in altered rock and 

in the shallow core holes is in the range of that in tight 

gas sandstone reservoir rocks. Correlation of sonic porosity and measured porosity is very good, and the zones that 

looked most porous on the sonic log were not cored. 

Table 1. Porosity and permeability of samples from the Siljan 

Ring area, Sweden. 

[All data are from Gravberg 1 well except as noted. Porosity of average Swedish 

granite shown for comparison (Stenberg, 1986). -·-,not determined] 

Number of Porosity Permeability 

samples (percent) (microdarcies) 

Granite------------------------- 26 0.88 18 

Quartz monzonite ------------ .9 

Dolerite ------------------------ 6 .75 II 

Altered rock------------------- 2 2.35 

Shallow core holes----------- 40 2.0 

Average Swedish granite---- .25 

The relationship of sonic porosity with depth (fig. 10) 

shows that porosity decreases rapidly with depth. In the 

shallow subsurface, porosity is conclusively related to the 

meteorite impact. Deeper in the well, higher porosities 

correlate with the incidence of fracture zones that are unrelated to the impact. 

Breakouts (hole enlargements due to anisotropic rock 

stresses) caused the hole to be out of gauge and ovalized, 

which in turn induced large hole deviations, many fishing 

jobs, and several sidetracked holes. The main reason for this 

situation is that the magnitude of stress is low in fractured 

zones and higher in intervals where the rock is unfractured 

(Stephansson and others, 1990; Anonymous, 1991 ). In unfractured zones, spalling is the most common mechanism of 

failure. Stephansson and others ( 1990) showed that the horizontal stress is highly anisotropic and the minimum horizontal stress is close to 0.68 times the vertical stress. 

In summary, porosity is marginal in rocks penetrated 

by the Gravberg 1 well. Porous units are discontinuous, 

and permeability is very low. Pore pressures close to lithostatic, predicted by the expectation model, do not exist. 

INTERPRETJNG SEAL PROPERTIES 

Leak-off tests and DST data provide valuable clues 

about pressures, permeability, and hydraulic conductivity. 

These data are summarized on figure 11, which also includes information about formation-water salinity. Permeability is very low, especially below the Rl dolerite, and it 

is comparable to the permeabilities measured on cores. Although data are sparse, pore pressures throughout the well 

are less than or equal to hydrostatic. There are not enough 

data to determine if there are extensive rock units with 

conductivities low enough to qualify as a seal. 

On the basis of resistivity logs and DST data, formation waters are quite fresh down to 4,000 m, and below 

6,000 m the water is highly saline, containing around 

150,000 ppm total dissolved solids. Rissler-Akesson (1990) 

found that pore-fluid resistivity decreased below 4,000 m, 
PROSPECTS FOR COMMERCIAL ABIOGENIC GAS PRODUCTION 151 

500 

1000 

1500 

2000 

~ 3000 c.. 

i:o.l 

Q 

3500 

4000 

4500 

5000 

POROSITY, 

IN PERCENT 

0 10 

Figure 10. Sonic-log porosity trends in Gravberg I 

well. Not logged below 

5,400 m; interval 5,000-

5,400 m not shown. 

with resistivities of 5 ohms corresponding to salinities of 

2,000 ppm down to 5,660 m (fig. 11 ). Deep penetration of 

surface waters below 2,000 m (where pervasive feldspar 

alteration begins to taper off) is through fracture zones that 

contain altered granite (Komor and Valley, 1990). 

Gold's expectation model calls upon calcite formed 

from the oxidation of ascending mantle methane to help 

form a seal in critical layers and trap methane in stacked 

domains. Stable isotope fractionation curves from carbon 

and oxygen isotopes of calcite, bicarbonate, carbon dioxide, 

and methane show that all but 6 of the 167 samples from the 

0 

2 

~ 

"' L.. 3 Q) 

..... 

Q) 

E 

.2 

~ 4 

~ 

..... 

c. 

Q) 

0 

6 

7 

0 

{BHJ 

'I 

DST 5 

p 

50 100 

Permeabi I ity 

(microdarcies) 

150 

Fresh, modern water 

200 ppm ± 

t 

Transitional salinity 

l2000 ppm 

t 

High salinity 

150,000 ppm 

SALINITY PROFILE 

Figure 11. Permeability measurements obtained from leak-off 

tests and drill-stem test (DST) 5 in Gravberg I well. Data labeled 

BH3 are from leak-off test in borehole 3 (Filsas; see fig. 1). Salinity measurements (to right of graph) were obtained from DST 

and wircline-log data; arrows indicate approximate depth ranges 

for fresh, transitional, and high-salinity waters. Pressure in the 

well was hydrostatic to slightly subhydrostatic with reference to 

a fresh-water gradient. 

core holes and the Gravberg 1 well fall in the equilibrium 

field delimited by meteoric water, atmospheric C02, and 

soil bicarbonate (Anonymous, 1991 ). Two of the six other 

samples fall directly on the magmatic C02 line; they are 

from the chilled margins of the mineralogically unaltered 

Rl dolerite. The calcite carbon is derived from groundwater 

bicarbonate, limestone, and C02 originating from magmatic 

sources. Particularly below the R1 dolerite, calcite oxygen 

becomes isotopically heavier with depth, reflecting an increased prevalence of magmatic C02. If the source of calcite were oxidized mantle methane (o13C of -7 permil), 

calcite o13C values would be greater than +40 permil. As an 

alternative, a Raleigh distillation process (Faure, 1986) resulting from continuous calcite precipitation from mantlederived methane would result in isotopic values between 

+40 and <0 permil. Because such trends are not observed, 

mantle methane cannot be considered as a source for calcite 

(Valley and others, 1988; Komor and Valley, 1990). 

In summary, all seal properties are related to geochemical effects that act from the Earth's surface downward, and 

there is no evidence for the influence of ascending fluids. 

The presence of altered minerals in the granite as deep as 
I 52 THE FUTURE OF ENERGY GASES 

4,000 m, the evidence from stable isotope studies of calcite 

cements, and the existence of fresh formation water down 

to almost 6,000 m support this conclusion. 

EPILOGUE-THE STENBERG 1 WELL 

DDP drilled the Stenberg I well in 199I-92; the site is 

near Hattberg in the central part of the Siljan Ring (fig. I). 

From the scant data available, breakout problems were encountered in this well, as they had been in Gravberg I. 

Drilling rates improved, largely because of the experience 

gained at Gravberg. Methane with a mantle isotopic signature is present in the dolerites penetrated by Stenberg I, 

and shows in the dolerites are much higher than in the 

granites (T. Gold, o:al commun., I992). Only a small 

amount of free gas has been recovered in drill-stem tests, 

and the flow rate diminishes with time. 

CONCLUSIONS 

Data from the Gravberg I well have added conclusive 

evidence that the meteorite impact that created the large 

circular structure in the Siljan Ring greatly fractured and 

altered the underlying rocks. The heat created by the impact was sufficient to generate barely mature hydrocarbons 

in Ordovician source rocks on the perimeter of the ring. 

The influence of the impact drops off dramatically below 

2,000 m and is entirely absent below 4,000 m. Fracture 

zones at depth are related to regional tectonics and not to 

the impact. The low-dipping, high-amplitude seismic reflectors are dolerite sills. 

Under the stress conditions identified in the Gravberg I 

well, pore pressures close to lithostatic cannot exist. Fracture 

zones are discontinuities in the stress field and bound large 

blocks several hundred meters across. Lithologic units and 

fracture zones are very irregular and discontinuous, except 

for the dolerites, which are not part of the porous units. 

All available evidence points to a very deep circulation 

of meteoric water in the Siljan Ring area. The whole circulation system is driven by the present-day topography. 

Below 6,000 m, stagnant water is present; it is highly saline 

with I50,000 ppm total dissolved solids. The pore-pressure 

gradient is essentially hydrostatic to slightly subhydrostatic, 

and permeabilities are very low, especially below I ,500 m. 

Despite the low conductivities, effective seals were not recognized. Stable isotope studies of calcite show that mantle 

methane is not involved in any of the fractionation equilibria; instead, equilibration exists with modem meteoric 

water. At depth, magmatic C02 is the likely carbon source 

for the heaviest carbon isotopes measured. 

Because of the very low gas saturation in the water, 

about 0.25 m3 gas/m3 water, there is no free gas in the 

formation. The gas may be in solution, it may be adsorbed 

on mineral grains, or it may be present in fluid inclusions. 

Methane in surface seepages and in the shallow core holes 

is of microbial origin, and the associated helium is of 

crustal origin. 

The dolerites yield the principal gas shows, which are 

generally less than 1,000 ppm. Dolerite gases are characterized by 95 percent methane with a very heavy isotopic 

composition (613C of about -15 permil). The methane/ 

ethane ratio of these gases ranges from 20 to 45, with 

minor unsaturated hydrocarbons present. These gases are 

abiogenic, but it is not certain whether the gases have a 

crustal or mantle origin. 

Gases from the granite have a wide range of methane 

isotopic compositions, generally falling within a c13c 

range of -20 to -35 permii during drilling and -42 to -56 

permil during testing. Granite gases contain 50-70 percent 

methane, with a methane/ethane ratio between 8 and 10. 

Hydrocarbon gases in the dolerite and the granite in the 

original hole display abiogenic isotopic signatures. Gas 

with a thermogenic profile was found during drilling of 

ST-3, DST 5, and pump testing; granite and quartz monzonite are the main rock units in which such gas was found. 

Interaction with the oil-based drilling mud is probably responsible for the differences between isotopic compositions 

measured during drilling and those measured during testing. Gases in the granites fall into two types: one rich in 

saturates, the other rich in unsaturated hydrocarbons. The 

saturated hydrocarbon group is more commonly found in 

fracture zones; it could be an indigenous group generated 

abiogenically, or it could be derived mainly from sedimentary organic matter driven deep into the granite. Unsaturated hydrocarbons are rare in nature, but they could be 

formed through catalytic reactions such as the FischerTropsch reaction or spark discharge reactions caused by 

tectonic rock shearing. The likely reaction in the granite is a 

Fischer-Tropsch reaction between C02 and H2 with magnetite as the catalyst. Most of the gas in the granite is probably artificial. The effect of deglaciation in the rejuvenation 

of the deep penetration of meteoric waters carrying with 

them dissolved organic compounds (plus oil and gas) must 

be considered as a source of hydrocarbons. 

Both hydrogen and helium have been found in greater 

abundance than expected, particularly below 6 km. The association of helium and hydrogen in rather high concentrations strongly suggests that these gases are present in the 

formation. Hydrogen probably has been formed in the crust 

at fairly low temperatures, possibly by spark discharge reactions or fluid-rock reactions. Helium and the other noble 

gases argon and neon have a crustal origin. More than 99 

percent of the helium can be accounted for by radioactive 

decay of uranium- and thorium-bearing minerals over a period of time much shorter than the age of the rocks. 

There is no credible evidence for a mantle flux of 

methane or helium at Gravberg, and none of the basic premises for the deep-gas hypothesis (Gold, I979, 1987) 

predicated for the Siljan Ring have been realized. 
PROSPECTS FOR COMMERCIAL ABIOGENIC GAS PRODUCTION 153 

REFERENCES CITED 

Abranjo, T.A., Sturchio, N.C., Bohlke, J.K., Lyon, G.L., Poreda, 

R.J., and Stevens, C.M., 1988, Methane-hydrogen gas seeps, 

Zambales ophiolite, Philippines-Deep or shallow origin?: 

Chemical Geology, v. 71, p. 211-222. 

A!Dahan, A.A., 1990, Petrology and mineral alterations of granitic rocks from Gravberg-1 well, Siljan impact structure, 

central Sweden: Sector Report, Deep Gas Project, Vattenfall 

RD&D Report U(G) 1990/50, 63 p. 

Anonymous, 1984, The Siljan ring project-Independent expert 

evaluation, Deep Gas Swedish Premises: Vattenfall unnumbered report, 63 p. 

---1985, Deep gas, Swedish Premises, the Siljan ring structure-Investigations and evaluations: Vattenfall RD&D report, Gas Project G.2 report no. 4. 

---1991, Scientific summary report of the deep gas drilling 

project in the Siljan Ring impact structure: Vattenfall.RD&D 

Report U(G) 1991114, 278 p. 

Bath, A.H., Brassell, S.C., Eglinton, G., Hill, R.I., Hooker, P.J., 

O'Nions, R.K., Oxburgh, E.R., Parnell, J., Robinson, N., and 

Spiro, B., 1986, Deep source gases and hydrocarbons in the 

U.K. crust: British Geological Survey Report FLPU 86-2, 

129 p. 

Biloen, P., and Sachtler W.M.H., 1981, Mechanism of hydrocarbon synthesis over Fischer-Tropsch catalysts: Advances in 

Catalysis, v. 30, p. 165-215. 

Boden, A., and Eriksson, K.G., eds., 1988, Deep drilling in crystalline bedrock, volume 1-The deep gas drilling in the Siljan impact structure, Sweden and astroblemes: Berlin, 

Springer-Verlag, 364 p. 

Bottomley, R.J., York, D., Grieve, R.A.F., 1978, 40Ar-39Ar ages 

of Scandinavian impact structures: I Mien and Siljan: Contributions to Mineralogy and Petrology, v. 68, p. 79-84. 

Bryndzia, L.T., and Wood, B.J., 1990, Oxygen thermobarometry 

of abyssal spinel peridotites-The redox state and C-D-H 

volatile composition of the Earth's sub-oceanic upper mantle: American Journal of Science, v. 290, p. 1093-1116. 

Burke, R.A., Jr., Brooks, J.M., and Sackett, W.H., 1981, Light 

hydrocarbons in Red Sea brines and sediments: Geochimica 

Cosmochimica Acta, v. 45, p. 627-634. 

Castano, J.R., 1988, Geochemical studies, Gravberg-1 well, Sweden-Integration of well site and external laboratory analyses, in Deep drilling in crystalline bedrock, v. 1-The deep 

gas drilling in the Siljan impact structure, Sweden and astroblemes: Boden, A., Eriksson, K.G., eds., Berlin, SpringerVerlag, 364 p. 

---1990, Geochemistry of the Gravberg-1 well: Sector Report, Deep Gas Project, Vattenfall RD&D Report U(G) 

1990161, 86 p. 

Castano, J.R., Sneider, R.M., and Bolger, G.W., 1988, Characterization of lithology and reservoir rock for deep gas drilling in Siljan impact structure, Sweden [abs.]: American 

Association of Petroleum Geologists Bulletin, v. 72, p. 169-

170. 

Castano, J.R., Juhlin, C., Rissler-Akesson, G., 1990, Reservoir 

evaluation: Sector Report, Deep Gas Project, Vattenfall 

RD&D Report U(G) 1990/49, 92 p. 

Coveney, R.M., Jr., Goebel, E.D., Zeller, E.J., Dreschhoff, 

G.A.M., and Angino, E.A., 1987, Serpentinization and the 

origin of hydrogen gas in Kansas: American Association of 

Petroleum Geologists Bulletin, v. 71, p. 39-48. 

Demaison, Gerard, and Murris, Roelof 1., eds., 1984, Petroleum 

geochemistry and basin evaluation: American Association of 

Petroleum Geologists Memoir 35, 426 p. 

Des Marais, D.J., Douchin, J.H., Nehring, N.L., and Truesdale, 

A.L., 1981, Molecular carbon isotopic evidence for the origin of geothermal hydrocarbons: Nature, v. 292, p. 826-828. 

Donofrio, R.R., 1981, Impact craters-Implications for basement 

hydrocarbon production: Journal of Petroleum Geology, v. 3, 

p. 279-302. 

Enomoto, Y., and Hashimoto, H., 1990, Emission of charged particles from indentation fracture of rocks: Nature, v. 346, p. 641-

643. 

Faber, E., Gerling, P., and Dumke, I., 1988, Gaseous hydrocarbons 

of unknown origin found while drilling, in Advances in organic 

geochemistry 1987: Organic Geochemistry, v. 13, p. 875-879. 

Faure, G., 1986, Principles of isotope geology (2nd ed.): New 

York, John Wiley and Sons, 589 p. 

Ferguson, 1 . .1987, A possible role for light hydrocarbons in Pb/ 

Zn mineral exploration: Mineralogical Magazine, v. 51, 

p. 527-533. 

Freund, F., Knobel, F., Wengeler, H., Kathrein, K., Oberheuser, 

G., and Schaeffer, R., 1982, Organic compounds in the early 

atmosphere formed abiotically from atomic carbon: Geologische Rundschau, v. 71, p. 1-21. 

Fritz, P., Frape, S.K., and Miles, M., 1987, Methane in the crystalline rocks of the Canadian shield, in Fritz, P., and Frape, 

S.K., eds., Saline waters and gases in crystalline rocks: Geological Association of Canada Special Paper 33, p. 211-223. 

Fuex, A.N., 1977, The use of stable carbon isotopes in hydrocarbon exploration: Journal of Geochemical Exploration, v. 7, 

p. 155-188. 

Fuex, A.N., and Baker, D.R., 1973, Stable carbon isotopes in selected granitic, mafic, and ultramafic igneous rocks: Geochimica Cosmochimica Acta, v. 37, p. 2509-2521. 

Gold, T., 1979, Terrestrial sources of carbon and earthquake outgassing: Journal of Petroleum Geology, v. 1, p. 3-19. 

---1987, Power from the earth: London, J M Dent & Sons, 

208 p. 

Grieve, R.A.F., 1988, The formation of large impact structures 

and constraints on the nature of Siljan, in Deep drilling in 

crystalline bedrock, v. 1-The deep gas drilling in the Siljan 

impact structure, Sweden and astroblemes: Boden, A., Eriksson, K.G., eds., Berlin, Springer-Verlag, 364 p. 

Hedberg, H.D., 1988, The 1740 description by Daniel Tilas of 

stratigraphy and petroleum occurrence at Osmundberg in the 

Siljan region of central Sweden: Tulsa, Okla., American Association of Petroleum Geologists, 96 p. 

Hilton, D.R., and Craig, H., 1989, The Siljan Deep Well-Helium isotope results: Geochimica Cosmochimica Acta; v. 53, 

p. 3311-3316. 

Hunt, J.M., 1979, Petroleum geochemistry and geology: San 

Francisco, W.H. Freeman, 617 p. 

James, A.T., 1983, Correlation of natural gas by use of carbon 

isotopic distribution between hydrocarbon components: 

American Association of Petroleum Geologists Bulletin, 

v. 67, p. 1176-1191. 

Jeffrey, Alan, and Kaplan, I.R., 1988, Geochemistry of gases in 

the Gravberg-1 well: Vattenfall unnumbered report. 
154 THE FUTURE OF ENERGY GASES 

Juhlin, C., and Pedersen, L.B., 1987, Reflection seismic investigations of the Siljan impact structure, Sweden: Journal of 

Geophysical Research, v. 92, p. 14.113-14.122. 

Komor, S.C., and Valley, J.W., 1990, Deep drilling at the Siljan 

ring impact structure-Oxygen-isotope geochemistry of 

granite: Contributions to Mineralogy and Petrology, p. 1-17. 

Komor, S.C., Valley, J.W., and Brown, P.E., 1988, Fluid inclusion evidence for impact heating at the Siljan Ring, Sweden: 

Geology, v. 16, p. 711-715. 

Konnerup-Madsen, J., Kreulen, R., and Rose-Hansen, J., 1988, 

Stable carbon characteristics of hydrocarbon gases in the alkaline Ilfmaussaq complex, south Greenland: Bulletin 

Mineralogique, v. 102, p. 642-653. 

Konnerup-Madsen, J., and Rose-Hansen, J., 1982, Volatiles associated with alkaline igneous rift activity-Fluid inclusions in 

the Ilfmaussaq intrusion and the Gardar granitic complexes 

(south Greenland): Chemical Geology, v. 37, p. 79-93. 

Kropotkin, P.N., 1985, Degassing of the earth and the origin of 

hydrocarbons: International Geology Review, v. 27, 1261-

1275. 

Laier, Troels, 1988, Hydrocarbon gases in the crystalline rocks of 

the Gravberg-1 well, Swedish deep gas project: Marine and 

Petroleum Geology, v. 5, p. 370-377. 

---1990, Light hydrocarbon analyses on cuttings from 

Gravberg-1 well: Sector Report, Deep Gas Project, Vattenfall RD&D report U(G) 1990/45, 78 p. 

---1992, Hydrocarbon gases from canned cuttings from the 

Gravberg-1 well: Geologiska Foreningens i Stockholm 

Forhandlingar, v. 114, p. 161-163. 

Lee, J.K.W, Onstott, T.C., Henne, R., Krough, T.E., Castano, 

J.R., 1988, 40ArP9Ar laser microprobe and U-Pb geochronology of Siljan Ring samples [abs.]: Geological Society of 

America Annual Meeting, p. A24. 

Leythaeuser, D., Schaefer, R., and Yukler, A., 1982, Role of diffusion in primary migration of hydrocarbons: American Association of Petroleum Geologists Bulletin, v. 66, p. 408-429. 

MacDonald, G., 1983, The many origins of natural gas: Journal 

of Petroleum Geology, v. 5, p. 341-362. 

Magoon, L.B., and Dow, W.G., eds., in press, The petroleum system-From source to trap: American Association of Petroleum Geologists. 

Mamyrin, B.A., and Tolstikhin, L.N., 1970, Helium isotopes in 

nature: Amsterdam, Elsevier. 

Martelli, G., Smith, P.N., and Woodward, A.J., 1989, Light, radiofrequency emission and ionization effects associated with rock 

fracture: Geophysical Journal International, v. 98, p. 397-401. 

McAuliffe, C., 1966, Solubility in water of paraffin, cycloparaffin, olefin, acetylene, cycloolefin, and aromatic hydrocarbons: Journal of Physical Chemistry, v. 70, p. 1267-1275. 

Neal, C., and Stanger, G., 1983, Hydrogen generation from mantle source rocks i~ Oman: Earth and Planetary Science Letters, v. 66, p. 315-320. 

Petersil'ye, I.A., and Pavlova, M.A., 1975, Organic compounds 

. in volcanic and metamorphic rocks: International Geology 

Review, v. 20, p. 139-144. 

Poreda, R.J., Jeffrey, A.W.A., Kaplan, I.R., and Craig, H., 1988, 

Magmatic helium in subduction-zone natural gases: Chemical 

Geology, v. 71, p. 199-210. 

Price, . L.C., 1979, Aqueous solubility of methane at elevated 

pressures and temperatures: American Association of Petroleum Geologists Bulletin, v. 63, p. 213-244. 

Rissler-Akesson, G., 1990, Wireline logging in the Gravberg-1 

well; Sector Report, Deep Gas Project, Vattenfall RD&D 

Report U(G) 1990/52, 86 p. 

Schoell, M., 1984, The hydrogen and carbon isotopic compositions of methane from natural gases of various origins: 

Geochimica Cosmochimica Acta, v. 44, p. 649-661. 

Sofer, Z., 1985, An unusual occurrence of light hydrocarbon 

gases in a well offshore northeast Palawan island, The Philippines: Precambrian Research, v. 30, p. 179-188. 

Stenberg, L., 1986, Geophysical laboratory investigations on 

core samples from the Klipperas study site: Swedish Nuclear Fuel and Waste Management (SKB) Technical Report 

86-09. 

Stephansson, Ove, Bjarnason, Bjami, and Savilahti, Tomas, 

1990, Rock mechanics of the Gravberg-1 well: Vattenfall 

RD&D Report (U)G 1990/46, 58 p. 

Svensson, N.-B., 1973, Shatter cones from the Siljan structure, 

central Sweden: Geologiska Foreningens i Stockholm 

Forhandlingar, v. 95, p. 139-143. 

Tamminen, J., and Wickman, F.S., 1980, Shock effects in pegmatitic quartz from the Siljan ring structure, central Sweden: 

Geologiska Foreningens i Stockholm Forhandlingar, v. 102, 

p. 275-278. 

Thorslund, P., and Auton, C., 1975, Evidence of meteorite impact 

in the Siljan structure, central Sweden: Bulletin of the Geological Institutions of the University of Uppsala, v. 6, p. 69-

72. 

Tissot, B., and Welte, D., 1984, Petroleum formation and occurrence, (2nd ed.): New York, Springer-Verlag, 699 p. 

Ulmishek, G.F., and Klemme, H.D., 1990, Depositional controls, 

distribution, and effectiveness of world's petroleum source 

rocks: U.S. Geological Survey Bulletin 1931,59 p. 

Val.ley, J.W., Komor, S.C., Baker, K., Jeffrey, A.W.A., Kaplan, 

I.R., and Raheim, A., 1988, Calcite crack cements in granite 

from the Siljan Ring, Sweden-Stable isotopic results, in 

Deep drilling in crystalline bedrock, v. !-The deep gas 

drilling in the Siljan impact structure, Sweden and astroblemes: Boden, A., Eriksson, K.G., eds., Berlin, Springer-Verlag, p. 156-179. 

Vlierboom, F.W., Collini, B., Zumberge, J.E., 1986, The occurrence of petroleum in sedimentary rocks of the meteor impact 

crater at Lake Siljan, Sweden: Organic Geochemistry, v. 10, 

p. 153-161. 

Welhan, J.A., 1988, Methane and hydrogen in mid-ocean-ridge 

basalt glasses-Analysis by vacuum crushing: Canadian 

Journal of Earth Science, v. 25, p. 38-48. 

Wickman, F.S., 1980, The impact center of the Siljan structure, 

central Sweden: Geologiska Foreningens i Stockholm Forhandlingar, v. 102, pt. 2, p. 105-109. 

Wood, B.J., Bryndizia, L.T., and Johnson, K.E., 1990, Mantle 

oxidation state and its relationship to tectonic environment 

and fluid speciation: Science, v. 248, p. 337-345. 

Zhizhchenko, B.P., 1978, Generation of hydrocarbon gases in recent sediments: International Geology Review, v. 21, p. 481-

490. 
Natural-gas resources accumulate in numerous geologic 

settings. Gas is fundamentally different from oil, both in 

physical properties and in origin, and it is found in some 

settings where oil is not. Nonetheless, in most oil accumulations, gas is dissolved in oil or is present as a cap to the 

oil reservoir. These types of gas accumulations are known 

as conventional resources. 

Unconventional natural-gas resources are those that are 

found in unusual geologic settings, including settings where 

extraction is difficult. Economically viable extraction of 

•these resources usually requires more research and (or) 

more advanced technology. Because gas is more stable at 

higher temperatures and pressures than oil, gas occurrences increase with depth. Therefore, gas may be present 

. in the deepest part of a sedimentary basin, at depths greater 

than 15,000 feet (4,600 meters), where oil is absent; such 

gas is called deep gas. Gas may be present in rocks with 

extremely small pore spaces. Such accumulations are 

referred to as tight-gas accumulations, which typically 

involve either an organic-rich shale where the gas originated or a sandstone where gas has accumulated over long 

periods of time. In Arctic regions and other cold environments, in particular permafrost regions and the cold layer 

130 to 2,000 meters below the sea floor, gas can occur in 

cage-like structures in the molecular lattice of ice. Such gas 

accumulations are called gas hydrates. Gas is also found in 

association with coal, adsorbed onto the surfaces of coal 

molecules. This type of gas is referred to as coalbed methane. Gas may also be dissolved in water in some aquifers. 

Finally, gas is trapped beneath the clay seals of many 

municipal landfills. 

HABITATS OF GAS ACCUMULATION 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Conventional Gas Resources of the Gulf of Mexico 

Outer Continental Shelf-Past Experience, Current Activities, 

Future Potential 

By Gary L. Lore 1 

CONTENTS 

Abstract ......................................................................... 157 

Introduction ................................................................... 158 

Historical Exploration and Discovery Patterns ............ 158 

Distribution of Fields and Original Recoverable 

Proved Gas Reserves .. .... ... . ... ..... .. .... .. .... ........ ...... .. ... ... 163 

Geographic Distribution ......................................... I 63 

Water Depth Distribution ....................................... 164 

Recent Events and Emerging Plays .............................. 164 

Norphlet Gas Play .................................................. 166 

Flexure Trend and Upper Slope ............................. 166 

Shallow Miocene Bright Spot Play ....................... 167 

Seagull Play ............................................................ 167 

Influences of Economics on Exploration, Lease 

Acquisition, Exploitation, and Potential Resources ..... 168 

Conclusions ................................................................... 169 

References Cited . .. . .. .......... ... . . . .. .. .. ... . .. .. .. . ... . .. .•..... ....... 170 

ABSTRACT 

Original recoverable proved reserves of hydrocarbons 

in the 819 fields discovered through 1991 on the Gulf of 

1

Minerals Management Service, Gulf of Mexico OCS Region, Office of Resource Evaluation, MS 5100, 1201 Elmwood Park Blvd., New 

Orleans, LA 70123-2394. 

Mexico. Federal Outer Contine-ntal Shelf (GOM OCS) are 

estimated to be 10.74 billion barrels of oil (Bbo) and 

130.5 trillion cubic feet of natural gas (Tcfg). Eighty-one 

of these fields have been depleted and abandoned. Remaining reserves recoverable from the 738 active fields 

have been estimated to be 2.33 Bbo and 32.0 Tcfg. An 

additional 70 active fields have not been sufficiently developed to warrant consideration as proved. 

The GOM OCS is primarily a gas-prone province. Of 

the 819 proved fields, 676 are classified as gas fields. Cumulative production through 1991 was 8.41 Bbo and 98.5 

Tcfg. On an energy-equivalent basis this production 

equates to nearly 68 percent natural gas. In recent years 

the area has contributed about 10 percent of the Nation's 

total domestic oil production and 22 to 25 percent of the 

gas. Even though three-quarters of the estimated original 

recoverable proved gas reserves have been produced, the 

GOM OCS, as the Nation's premier natural-gas-producing 

province, will continue to have a pivotal role in determining our future gas supply. 

Historically, oil and gas exploration and development 

have gradually progressed seaward into the deeper waters 

of the Gulf of Mexico. The average size of fields discovered has decreased steadily over time, and the exploration 

effort required for each incremental reserve addition has 

increased. 

Numerous significant discoveries in the deep Norphlet 

play and the deep-water Flexure Trend and upper slope 

areas are exceptionally large when compared to other 

GOM OCS discoveries of the past 15 years. However, the 

inordinately high development costs and technological advancements required to bring these resources to market 

cloud their commercial viability. 

157 
158 THE FUTURE OF ENERGY GASES 

Although not as promising as the Norphlet play or the 

Flexture Trend, the mature, well-explored areas of the 

shallow-water GOM OCS offer numerous opportunities to 

develop attractive prospects in today's economic climate. 

The keys to successful development in these areas are to 

be willing to take a fresh look, to employ modem and 

(or) novel integrated exploration concepts, and to use the 

latest technology such as the three-dimensional seismic 

data that are becoming increasingly available. 

Assessments of potential undiscovered, economically 

recoverable conventional hydrocarbon resources on the 

GOM OCS are highly sensitive to assumptions concerning 

future cost-price relationships. These assessments suggest 

that as much gas may still be undiscovered as has already 

been discovered on the GOM OCS. 

INTRODUCTION 

The first field was discovered on the Gulf of Mexico 

Outer Continental Shelf (GOM OCS) in 1947. Through 

the end of 1991, 819 proved oil and gas fields have been 

established (fig. I). Another 70 fields were active for 

which decisions concerning commercial viability had yet 

to be made. In the Minerals Management Service (MMS) 

reserves classification scheme, these 70 fields and their reserves are referred to as unproved. A detailed explanation 

of this reserves-classification system and a comparison 

with the Society of Petroleum Engineers definitions can be 

found in Melancon and others (1992). 

Original recoverable proved reserves 1 of hydrocarbons 

are estimated to be 10.74 Bbo2 (billion barrels of oil) and 

130.5 Tcfg (trillion cubic feet of gas). Eighty-one of these 

fields have been depleted and abandoned. Cumulative production is 8.41 Bbo and 98.5 Tcfg. Remaining proved reserves recoverable from the 738 active proved fields are 

2.33 Bbo and 32.0 Tcfg. Eighty-three percent (676 fields) 

of the proved fields are gas fields3. The original recoverable 

proved reserves were present in 16,881 reservoirs, of which 

9,473 were gas, 6,010 were oil, and 1,398 were combination reservoirs (table 1). 

Annual total gas production in the GOM OCS has fluctuated between 4 and 5 Tcf since 1978, peaking initially in 

1 Estimates of proved reserves for liquids are expressed in barrels at 

60°F and I atmosphere and for gas in standard cubic feet at 60oF and 

15.025 psia. These are the commonly used GOM OCS reference conditions. To convert the gas volumes reported in this text to reference standard conditions of 60°F and I atmosphere (14.696 psia), multiply by 

1.022. 2The term "oil" as used in this paper includes crude oil and condensate. The cumulative product mix in the GOM OCS is approximately 90 

percent oil and I 0 percent condensate. 3Gas fields are defined as those fields having more than 50 percent 

of the estimated proved original recoverable hydrocarbon reserves on a 

Btu basis in the form of nonassociated gas. 

1981 and again in 1990 at 4.9 Tcf and averaging about 4.5 

Tcf (fig. 2). At the 1991 annual production rate of 4.7 Tcfg, 

the ratio of remaining proved reserves to production is 6.8 

years. Throughout the 1980's and into the 1990's, the GOM 

OCS contributed about 22 percent of the total annual United States domestic gas production. In 1991 the GOM OCS 

gas production was nearly 26 percent of the national total. 

Clearly, this natural-gas-producing province is of national 

importance in the consideration of both current and prospective domestic supplies. 

This report reviews the results of past exploration and 

production activities and presents current information related to the distribution of remaining proved reserves and 

potential undiscovered resources. All estimates of reserves, 

production and potential undiscovered resources were current as of December 31, 1991. 

HISTORICAL EXPLORATION AND 

DISCOVERY PATTERNS 

Lore ( 1992) reviewed the discovery and exploration 

history of the GOM OCS during the period 1947-1989. 

The analysis of the empirical discovery record showed that 

during each ensuing decade the number of proved fields 

discovered increased. However, this increase was accomplished only through a significant increase in the number of 

exploratory wells drilled, which was accompanied in turn 

by a decline in the observed annual exploration success 

rate. The initial success rate of more than 80 percent early 

in this period dropped to less than 10 percent recently. Coincident with the increased maturity of the GOM OCS was 

a marked decrease in the average size of new field discoveries.4 Meisner and Demiren (1981) applied the term 

"creaming" to this phenomenon. During exploration of a 

play or basin, prospects become increasingly smaller, increasingly more difficult to identify, and more expensive on 

a unit-recovery basis to exploit. This change is evident 

from table 2, which updates the previous analysis to include 

more recent reserve estimates and show further details by 

field type. Considering all fields on a barrel-of-oil-equivalent (boe) basis, even with the inclusion of an additional 49 

4

Caution should be used when considering both the number of 

proved fields and the quantity of reserves discovered in recent years. 

These estimates should be considered conservative because there are 70 

active unproved fields that, if operators decide to develop them, will be 

classified as proved and credited to the appropriate discovery year. Initial 

estimates of proved reserves in fields typically exhibit significant appreciation with time. Preliminary analysis reported by Drew and Lore 

(1992) revealed that historically as a result of this field-growth phenomenon, MMS's initial estimates of proved reserves grew on average by a 

factor of 4.5. All estimates in this text, unless otherwise noted, are 

proved reserves as of year end 1991 and do not incorporate future reserves appreciation. 
gf' Ulf' 

+ + 

Texas 

+ 

BA. BRAZOS 

B.S. BfETON SOUND 

B.M. BAY MARCI-WoD 

CA. ~DEL£~ 

C. C. CORPUS CKliSTI 

E.C. EAST CAMERON 

M.l. MATAGOFO\ ISLANJ 

MU. MUSTANG ISLANJ 

MO. MOBILE 

PL SOVIH PELTO 

P.l. PORT ISABEL 

ALAMINOS CANYON 

E. I. EUGEIIE ISLAND 

EW. EWING BANK 

~ GALVESTON 

G.L GAANliSL£ 

H. I. HGH ISLANJ 

M.P. MAIN PASS 

P.N. NORTH PADRE ISLANJ 

P.S. SOUTH PADRE ISI»>> 

SA. SABINE PASS (LOUISIA~ 

S.M. SOUTH MARSH ISI»>> 

S.S. SHIP SHOAL 

Louisiafia 

gaO 112" 

+ + 

KEATH.£Y CANYON 

S.P. SOUTH PASS 

S.T. SOUTH TIMBAUER 

SX. SABINE PASS (TEXAS) 

V.K. VIOSCA KNOLL 

VR VERMILION 

W.C WEST CAMERON 

W.O. WESTDELTA 

GREEN CANYON 

WALKER RIDGE 

LEGEND 

• OILFIELD 

[] GASFIELD 

SCALE 

0 20 40 60 

STA1UTEMII.ES 

Figure 1. Location of proved oil and gas fields on the Gulf of Mexico Outer Continental Shelf. 

DESTIN DOME 

DESOTO eN-lYON 

U.OYD 

AlWATER 

U.UND HENDERSON 

MAP AREA 

(") 

0 

z 

< m 

z 

::l 

0 

z 

>- r 

Cl 

>- (/) 

:::0 

m 

(/) 

0 

c::: 

:::0 

(") 

m 

(/) 
160 THE FUTURE OF ENERGY GASES 

Table 1. Number of proved fields and reservoirs, original recoverable proved reserves, cumulative production, and remaining 

proved reserves arranged by field and reservoir type. 

[MMbbl. million barrels; Bcf, billion cubic feet; boe, barrels of oil equivalent] 

Field type 

Oil Gas 

Proved origiaal recoverable 

oil reserves (MMbbl) 8,876 1,862 

Proved origiaal recoverable 

gas reserves (Bcf) 27,872 102,625 

Proved origiaal recoverable 

boe reserves (MMbbl) 13,835 20,123 

Number of 

proved fields or reservoirs 

witll proved original 

recoverable reserves 143 676 

Cumulative oil 

productioa (MMbbl) 7,080 1,326 

Cumulative gas 

productioa {Bcf) 21,276 77,235 

Cumulative boe 

productioa (MMbbl) 10,865 15,069 

Number of 

proved fields or reservoirs 

wit II 

cumvlative productiou 139 635 

Proved remaiaiag recoverable 

oil reserves {MMbbl) 1,796 536 

Proved remaiaiag recoverable 

gas reserves {Bcf) 6,596 25,390 

Proved remaiaiag recoverable 

boe reserves (MMbbl) 2,970 5,054 

Number of 

proved fields or reservoirs 

with proved remaining 

recoverable reserves 134 600 

fields (43 of which were discovered during the 1980's) and 

two additional years of growth in the estimates for the previously established fields, the conclusions remain unchanged and are typical of experiences worldwide in 

mature hydrocarbon basins. The average size of fields discovered during the 1960's was 55 percent of those discovered between 1947 and 1959. Fields discovered during the 

1970's were on average also 55 percent of the size of fields 

discovered during the 1960's. This rate of decrease, however, changed with the fields discovered during the 1980's, 

which were only a third· the size of discoveries in the previous decade. Obviously, the fields discovered during the 

1980's have had less opportunity to experience reserves 

appreciation than the older fields. On the other hand, these 

Reservoir type 

All Oil Combination Gas All 

10,738 6,841 2,806 1,091 10,738 

130,497 9,180 10,487 110,830 130,497 

33,958 8,474 4,672 20,812 33,958 

819 6,010 1,398 9,473 16,881 

8,405 5,291 2,279 836 8,405 

98,511 6,783 7,435 84,293 98,511 

25,934 6,498 3,602 15,834 25,934 

774 5,539 1,311 8,148 14,998 

2,333 1,550 527 256 2,333 

31,986 2,397 3,052 26,537 31,986 

8,024 1,976 1,070 4,978 8,024 

734 2,688 906 4,980 8,574 

fields are the product of modem seismic technology and 

exploration concepts and may show significantly different 

reserves-appreciation characteristics than older fields. 

An interesting observation can be made when the same 

data are segregated by field type (oil versus gas fields). Oil 

fields discovered during each of the first three decades. of 

exploration were, on a boe basis, on average, about twice 

the size of gas fields discovered during the same time period. During the 1980's, however, this ratio increased to 

about 3 to 1. This increase may be partly explained by the 

shift in a significant portion of the exploration activity in 

the late 1980's to low-risk, low-cost, relatively modest potential, shallow-water gas prospects easily targeted by new 

seismic techniques. These were principal objectives of the 
CONVENTIONAL GAS RESOURCES, GULF OF MEXICO OUTER CONTINENTAL SHELF I61 

exploratory wells that were being drilled by independent 

operators in increasing proportions. This theory is supported by the observation that the average offshore water depth 

of new proved gas fields discovered decreased from 179 ft 

to 136 ft from the 1970's to the 1980's. At the same time 

the average water depth of oil field discoveries _more than 

doubled, from 249 ft to 548 ft (table 2). This change reflects the emphasis of the major companies during the 

1980's on exploring the high-potential, oil-prone prospects 

of the deeper water areas. Overall, the mean size for proved 

oil fields is 97 million barrels of oil equivalent (MMboe) 

and for gas fields, 3 I MMboe. 

Until the latter part of the 1970's, exploration on the 

GOM OCS focused primarily on discovering large oil 

fields. Significant gas reserves were also discovered and 

developed, but principally as a byproduct of the search for 

oil fields. The initial giant oil field discoveries generally 

contained substantial quantities of associated gas reserves 

(fig. 2). Exploration activity directed toward the discovery 

of gas fields was stymied by price controls, the economic 

hurdles presented both by deep drilling and deep water, as 

well as the generally high cost of GOM OCS operations. 

The passage of the Natural Gas Policy Act in 1978 and the 

prevailing optimism concerning higher anticipated future 

prices, coupled with the continued decrease in the size of 

oil fields being discovered and the development of new 

seismic tools, fueled a surge in exploration activity aimed 

at discovering substantial gas reserves (Lore, 1992). 

12 

The number of gas fields discovered annually has 

been steadily increasing, while the number of oil fields 

discovered has varied, never exceeding 10 and averaging 

about 3.5 per year. Through 1959, 38 percent of all fields 

discovered were oil. This percentage declined steadily; 

only I 0 percent of the fields discovered during the 1980's 

were oil fields. The hydrocarbons discovered in each time 

period also became progressively more gas prone, swelling from nearly 59 percent natural gas in the 1947-1959 

time frame to 78 percent during the 1980's. 

Eventhough 50 percent of the total number of proved 

gas fields have been discovered since 1979, they contain 

only 15 percent of the original recoverable proved gas 

reserves. Exploration statistics define a trend of continuously diminishing returns. Lore (1992) demonstrated consistent and dramatic annual decreases in the boe 

discovered per foot of exploratory drilling. From 1949 

through the early 1980's, the proved reserves discovered 

per foot of exploratory drilling decreased I 00-fold, from 

20,000 boe to about 150 boe per foot. 

The quantity of proved gas reserves discovered each 

year and its distribution between oil and gas fields are 

shown in figure 2. Nearly 80 percent of the 130.5 Tcfg of 

original recoverable proved reserves are in gas fields 

(table 1 ). Discoveries during 5 specific years out of the 

entire 45-year history of the GOM OCS (1949, 1956, 

1971, 1973 and 1974) account for 41.2 Tcfg, or 31 percent of the total proved gas reserves discovered. There 

500 

Original recoverable gas Original recoverable gas Average field Annual gas 

tiJ 10 

w 

LL 

() 

Ill 8 

::J 

() 

z 

0 6 

_j 

_j 

a: 

I- 4 

z 

~ 0 2 

0 

from fields from oil fields water depth production 

1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 

YEAR 

400 

tiJ 

w 

LL 

300 z 

I 

Ia_ 

w 

200 0 

a: 

w 

~ 

~ 100 

0 

Figure 2. Annual gas production and original recoverable proved gas reserves and average water depth by field discovery year. 
162 THE FUTURE OF ENERGY GASES 

Table 2. Number and type of wells drilled and proved fields, original recoverable proved ~eservcs, average field size, and 

average water depth arranged by discovery decade 

[MMbbl, million barrels, Bcf, billion cubic feet; boc, barrels of oil equivalenlj 

Time period 1947-1959 1960-1969 1970-1979 1980-1989 Total 

Namber of exploratory wells 442 

Total ••mber of wells 1,325 

Namber of 

proved fields 27 

Proved original recoverable 

0 oil reserves (MMbbl) 3,556 

Proved original recoverable 

I gas reserves (Bcf) 9,188 

Proved original recoverable 

F L boe reserves (MMbbl) 5,191 

Average 

I field size boe (MMbbl) 192 

Average 

E water dept II (feet) 63 

Number of 

L proved fields 43 

Proved original recoverable 

D G oil reserves (MMbbl) 459 

Proved origi•al recoverable 

A gas reserves (Bcf) 21,974 

Proved origiAal recoverable 

s boe reserves (MMbbl) 4,369 

Average 

field size boe (MMbbl) 102 

Average 

T water deptll (feet) 43 

Number of 

y proved fields 70 

Proved original recoverable 

p A oil reserves (MMbbl) 4,015 

Proved original recoverable 

E L gas reserves (Bcf) 31,162 

Proved original recoverable 

L boe reserves (MMbbl) 9,560 

Average 

field size boe (MMbbl) 137 

Average 

water depth (feet) 51 

were 120 fields discovered during these years. Fifty percent of the original recoverable proved gas reserves were 

contained in the 197 fields discovered prior to 1970. 

Since 1976, 407 oil and gas fields, nearly 50 percent of 

all proved fields, have been discovered, yet they contain 

2,377 3,356 4,356 10,531 

6,779 9,288 10,222 27,614 

32 49 35 143 

2,552 1,991 776 8,875 

8,131 8,361 2,192 27,872 

3,999 3,479 1,166 13,835 

125 71 33 97 

156 249 548 266 

87 216 299 645 

501 612 286 1,858 

24,916 37,730 17,476 102,096 

4,934 7,326 3,396 20,025 

57 34 11 31 

104 179 136 140 

119 265 334 788 

3,053 2,603 1,062 10,733 

33,047 46,091 19,668 129,968 

8,933 10,804 4,562 33,859 

75 41 14 43 

118 192 179 163 

only 19 percent of the original recoverable proved gas reserves and 11 percent of the proved oil reserves. 

Meisner and Demiren (1981) partially attributed this 

creaming effect to declining success rates as the exploration process proceeded. They argued that exploratory sue-
CONVENTIONAL GAS RESOURCES, GULF OF MEXICO OUTER CONTINENTAL SHELF 163 

cess rates reflect depletion of a potentially productive 

volume of sediment. As additional wells are drilled within 

a particular area and volume of sediment, the chance of 

discovering a field of any given size is decreased; the resource potential is exhausted. Thus, initially, the probability of finding large fields and then successively smaller 

accumulations decreases as additional exploratory wells 

are drilled. If success is defined as the number of fields 

discovered per exploratory well drilled, then the long-term 

success rate on the GOM OCS during the period 1947-

1959 was I 6 percent (table 2). This rate decreased to 5 

percent during the 1960's and remained at 8 percent during both the I 970's and 1980's. 

Another measure of exploration performance is the 

ability to discover sufficient volumes of reserves to replace 

production. Not since 1977 has GOM OCS exploration 

consistently discovered sufficient quantities of natural gas 

to equal or exceed the yearly production. If gas reserves are 

credited to the field discovery year, then there has been an 

annual shortage (production minus new reserves discovered) in gas discoveries every year since 1977 (fig. 3). The 

cumulative shortfall during this period was 40.5 Tcfg. If the 

measure of choice for crediting gas discoveries is the reservoir discovery date, then industry performance in replacing 

reserves is slightly improved (fig. 4). In this case reserves 

discovered exceeded production in every year through 

I 978. There was an annual shortfall during 1979-1981, but 

surpluses in 1982- I 984. The deficit has remained intact 

every year since and has totaled about 24 Tcfg. The 32 Tcf 

of proved gas reserves estimated to remain at year end 199 I 

12 

tu 10 

w 

u.. 

(.) 

Cl) 

:J 

(.) 

z 

0 

:J 

a: 

1-

z 

8 

6 

4 

0 

Non-associated 

gas reservoirs 

1>., I 

Combination 

reservoirs 

:>:::::::::::::::::::::::::::1 

are the lowest since MMS began reporting reserves in 1975 

(Melancon and others, 1992). 

DISTRIBUTION OF FIELDS AND 

ORIGINAL RECOVERABLE PROVED 

GAS RESERVES 

GEOGRAPHIC DISTRIBUTION 

The 130.5 Tcf of original recoverable proved gas reserves on the GOM OCS are not as evenly distributed 

geographically as may appear in figure I. Some areas are 

more gas prone than others. By the end of 1991, 819 

proved fields had been discovered in the GOM OCS, 586 

in the central portion offshore Louisiana, Mississippi, and 

Alabama; 232 in the western portion offshore Texas; and 

1 offshore Florida. Original recoverable proved reserves 

in the central and eastern portions were I 0.19 Bbo and 

I 07. I Tcfg, 95 and 82 percent, respectively, of the GOM 

OCS total. In the central portion, the original proved gas 

reserves were concentrated in fields located on the shelf 

off the central and western Louisiana coast (fig. 5). The 

central portion of the GOM OCS becomes increasingly 

more gas prone in a westerly direction. At the end of 

1991, there were 55 proved fields in this area whose reserves were depleted and an additional 53 active fields 

classified as unproved. In addition to a single proved 

field , 3 unproved fields are active in the area off eastern 

Alabama and western Florida. 

Under-saturated 

oil reservoirs 

,. I 

Annual gas 

production 

1945 1950 1955 1960 1965 1970 1975 

YEAR 

1980 1985 1990 1995 

Figure 3. Annual gas production and original recoverable proved gas reserves by reservoir type and field discovery year. 
164 THE FUTURE OF ENERGY GASES 

Estimates of original recoverable proved reserves in 

offshore Texas are 0.55 Bbo and 23.4 Tcfg. The majority 

of the original recoverable proved gas reserves were 

located in the High Island area off eastern Texas. Except 

for the High Island area and some of the more recent 

large deep-water discoveries in the East Breaks and Garden Banks areas, offshore Texas is almost exclusively a 

gas-producing region. Through 1991 , the proved reserves 

in 26 fields offshore Texas had been depleted and another 14 active fields were classified as unproved. 

Cumulative production in the central portion of the 

GOM OCS was 8.13 Bbo and 83.6 Tcfg, nearly 80 percent 

of the original recoverable proved reserves. Offshore 

Texas produced 0.28 Bbo and 14.9 Tcfg. A larger percentage of the original recoverable proved reserves remains to 

be produced from offshore Texas, where 50 percent of the 

oil and 64 percent of the original gas reserves have been 

produced. For the GOM OCS as a whole, 78 percent of 

the original oil and 75 percent of the original gas reserves 

have been produced. The remaining proved gas reserves 

are located primarily in the area off central and western 

Louisiana and in the Matagorda Island, High Island, and 

Sabine Pass areas off eastern Texas. 

WATER DEPTH DISTRIBUTION 

More than 80 percent of both the original recoverable 

proved gas reserves and fields were located in water depths 

less than 200 ft (fig. 6). The area on the continental shelf 

(less than 600 ft of water) accounted for 97 percent of both 

8 

the original gas reserves and fields. Reserves in the 22 

proved fields in deeper water are 830 MMbo (million barrels of oil) and 3.2 Tcfg. Preliminary estimates of the unproved resources in 17 of the 22 active unproved deepwater fields that may ultimately be developed are about 390 

MMbo and 1.67 Tcfg. The deep-water GOM OCS is discussed in more detail in the section entitled, "Flexure Trend 

and Upper Slope." It is an area where half the proved fields 

are under development and proved reserves can be expected to increase appreciably. It also contains several announced discoveries that have not yet qualified as fields. 

This frontier area holds great promise for the discovery of 

very large accumulations of hydrocarbons. 

RECENT EVENTS AND 

EMERGING PLAYS 

Exploration activity in the GOM OCS has decreased 

significantly in recent years. Evidence can be seen in the 

decrease in the traditional measures of exploratory activity: 

the number of geophysical permits issued, new leases issued, and exploratory wells drilled. During the past six 

years, however, some areas have shown a relatively steady 

level of activity and others are being studied with renewed 

interest. The "good prospects" have generally managed to 

attract needed funds. The single shining light in the overall 

depressed level of exploration activity is the acquisition of 

three dimensional (3-D) seismic data. In 1983, 16 permits 

were issued in the GOM OCS to acquire 14,460 line-miles 

of 3-D seismic data. In 1991, the number of permits issued 

Non-associated 

gas reservoirs 

Combination 

reservoirs 

Under-saturated 

oil reservoirs 

Annual gas 

production 

t1i 

w 

u.. 6 

() 

en 

::J 

() 

5 4 

_j 

_j 

a: 

1-

z 

~ (.!) 

2 

0 

1945 

I .. ,!o;;!lj 

1950 1955 1960 

·>:->:·:··>:<<:<1 

1965 1970 

YEAR 

1975 1980 1985 1990 1995 

Figure 4. Annual gas production and original recoverable proved gas reserves by reservoir type and reservoir discovery year. 
CONVENTIONAL GAS RESOURCES, GULF OF MEXICO OUTER CONTINENTAL SHELF 165 

increased to 45, and the line-miles acquired mushroomed to 

363,259. 

The following discussion highlights two high-potential, high-cost, high-risk frontier plays. While not experiencing historical peaks in terms of exploration, these plays 

have continued to attract interest as operators mull the results of previous efforts and consider the development 

200 

en 

g 

w 150 u.. 

0 

w 

> 0 

~ 100 

u.. 

0 

a: 

w 

(]) 50 ~ 

:::> 

z 

150 

en 

g 

w 

u.. 

0100 

w 

> 0 

a: 

ll.. 

u.. 

0 

a: 50 w 

(]) 

~ 

:::> 

z 

0 

~,.sY.. 

possibilities of these high-profile projects. Discussed also 

are two gas plays illustrative of the dozens on the GOM 

OCS that offer modest reserves at equally modest costs 

and risks. One is a recent play employing modern technology and concepts, the other a new play in a well-explored 

area resulting from a fresh approach to a target that previously had yielded only failures. 

Number of 

proved fields 

1<<.:.:.:.:-:-:-:--:: :-:-:-:-:-:-:-:-:-1 

Number of 

proved .as fields 

Original recoverable gas 

all proved fields 

I I 

Original recoverable gas 

proved gas fields 

• 

Number of 

proved fields 

I // I 

Number of 

proved gas fields 

• 

Origina l recoverable gas 

all proved fields 

Original recoverable gas 

proved gas fields 

• 

0 

~AREA 

15 

en 

w 

> a: 

w 

en 

w 

a: tu 

10 en 

w 

u.. 

~ () 

w ffi 

...J :::> 

a:l (.) 

~ z 

w 0 

> ~ 0 ....J 

5 () a: w 1- a: z ....J 

< z 

a 

a: 

0 

0 

~AREA 

Figure 5. Geographic distribution of original recoverable proved gas reserves. See figure I for an explanation of abbreviations 

and area locations. 
166 THE FUTURE OF ENERGY GASES 

NORPHLET GAS PLAY 

Probably the single, most exciting natural-gas play in 

the United States in the last several decades is the prolific 

Jurassic Norphlet gas play in Alabama coastal waters and 

the GOM OCS. The play extends from onshore southeastern Mississippi, into Alabama through state waters, into 

the GOM OCS and eastward into the Destin Dome Area 

offshore the Florida panhandle (fig. I). At least 43 fields 

have been discovered within the play (Mink and others, 

I 990). The first Norphlet discovery in the area was the 

Pelahatchie field in Mississippi in I 967. However, it was 

not until the initial 1979 offshore discovery of significant 

gas reserves in the Lower Mobile Bay-Mary Ann field that 

excitement began to run high concerning the Norphlet as 

an exploration objective. Subsequently, six fields have 

been discovered in Alabama state coastal waters and I 2 in 

the GOM OCS. Reservoir depths in these fields are 20,000 

to 25 ,000 ft, subsea. The intermediate estimate of original 

recoverable proved reserves in the state fields is about 

4. I 7 Tcfg with an additional 2.35 Tcf of potential gas reserves (Mink and others, 1987). Seven proved Norphlet 

fields with original recoverable reserves of 1.0 I Tcfg were 

established on the GOM OCS prior to 1992. An additional 

five fields with unproved reserves of approximately 2.47 

Tcfg were also active. Further enhancing the attractiveness 

of this play are the very prolific wells. Individual wells 

typically have production rates on tests as high as 20 to 30 

MMcfpd (million cubic feet per day). One well tested at 

300 

en 250 0 

.....J 

w 

LL 200 0 

w 

> 0 

a: 150 a_ 

LL 

0 

a: 100 w 

CD 

~ 

:::l 

z 50 

0 

rates of nearly 100 MMcfpd. All are anticipated to have 

high ultimate recoveries per well. 

The Norphlet Formation is predominantly nonmarine 

to shallow marine strata in the southern portions of the 

Mississippi Interior and Alabama Salt Basins and the offshore area. Eolian sandstone represents the primary reservoir lithofacies. The Norphlet sands were derived from 

erosion of the exposed southern Appalachian highlands, 

and, in the updip areas, were deposited as alluvial fan and 

braided stream complexes. The eolian sands are of two 

types: massive sheet sands and dune sands. The other common reservoir lithofacies present in the offshore fields is the 

reworked marine tidal sand in the upper part of the formation. This facies derived from the ensuing marine transgression (Marzano and others, 1989; Mink and others, 1985). 

The natural gas is trapped in a series of generally eastwest-trending salt anticlines or pillows. Salt movement has 

created broad, low-relief anticlines, most of which exhibit 

small-scale extensional faulting. 

FLEXURE TREND AND UPPER SLOPE 

The steady march of GOM OCS exploration and development activities into progressively deeper waters has 

paid spectacular dividends. Many oil and gas fields have 

been discovered and are being developed along the TexasLouisiana shelf break in an area commonly referred to as 

the "Flexure Trend" (fig. I). As of December 31, 1991, 35 

Number of 

proved fields 

I I 

Number of 

proved gas fields 

• 

Original recoverable gas 

all proved fields 

l .I 

Original recoverable gas 

proved gas fields 

• 

40 

30 

20 

10 

0 

en 

w 

5: 

w 

en 

~tlJ enw 

<(LL 

<!J(,) 

WID 

.....l:J 

Ill() 

<z ffio 

>- o:::l 

u- wa: a:I-

.....Jz 

<( 

z 

0 

a: 

0 

0-25 26-50 51-100 101-200 201-400 401-600 601-1200 >1200 

WATER DEPTH, IN FEET 

Figure 6. Distribution by water depth of original recoverable proved gas reserves and fields. 
CONVENTIONAL GAS RESOURCES, GULF OF MEXICO OUTER CONTINENTAL SHELF 167 

proved fields (including one expired and depleted field) 

were in this trend. Original recoverable proved reserves 

were 527 MMbo and 5.6 Tcfg. Cumulative production was 

220 MMbo and 3.3 Tcfg. The reserve potential for 8 of the 

unproved fields is about 115 MMbo and 300 Bcfg (billion 

cubic feet of gas). 

Recent exploratory drilling in even deeper water on 

the continental slope both south and east of this trend has 

resulted in the discovery of significant giant accumulations 

like Shell's Auger and Mars fields, Amoco's Ram/Powell 

field and Exxon's Cooper field. Elsewhere on the slope 

there were 15 active unproved fields and more than a 

dozen other oil and gas discoveries, 13 of which were located in water depths between 3,000 and 7,800 ft. Estimates of original recoverable proved reserves for the 15 

proven non-Flexure Trend fields on the slope exceed 585 

MMbo and 2.9 Tcfg. Initial estimates of unproved reserves 

and resources for 13 of the remaining active fields are estimated at 567 MMbo and 1.78 Tcfg. 

Unlike the Norphlet gas play, these areas are both oil 

and gas prone. In the Flexure Trend the 35 proved fields 

comprise 19 gas and 16 oil fields. The 18 proved nonFlexure Trend fields on the slope are equally divided between oil and gas fields. Khan (1992) identifies the three 

principal plays in this area as: (1) potential reservoir sands 

of predominantly Pleistocene age in the East Breaks, Garden Banks, and Green Canyon Areas; (2) reservoirs of 

mostly Pliocene age in the Ewing Bank, Mississippi Canyon, Viosca Knoll, Atwater and eastern portion of the 

Green Canyon Area; and (3) reservoir sands that are mainly 

middle and upper Miocene on the southeastern Louisiana 

slope in water depths greater than 3,000 ft. Pliocene and 

Pleistocene sediment accumulated locally to thicknesses of 

as much as 20,000 ft in small, isolated, intraslope basins 

and troughs bounded by massive salt stocks, pillows, and 

ridges. The reservoir sandstones are typical of shelf and 

submarine-fan environments of deposition. 

Hydrocarbon traps include those commonly characteristic of salt-dome-related features on the shelf. The style of 

salt tectonics, however, changes dramatically in a southward direction. Frequently present are salt tongues and tabular sheets that, due to up-dip sediment loading, spread 

laterally, overriding sediment of Miocene age and younger. 

These horizontal salt masses have recently been penetrated 

by several wells, most notably Exxon's Mickey Mouse 

prospect, which resulted in the discovery of a significant 

hydrocarbon accumulation. The discovery well was drilled 

in 1990 in over 4,000 ft of water and penetrated 3,000 ft of 

salt before encountering multiple oil and gas pays. This 

discovery, though not the first well to drill through a tabular 

salt body successfully, demonstrates that hydrocarbons can 

be trapped in the subsalt sediments and thus opens an entirely new play that extends over much of the outer edge of 

the continental shelf. 

This expansive frontier area offers an important opportunity for continued long-term additions to the natural-gasreserves base. The challenge facing operators is the effective implementation of existing technologies and the development of innovative new ones. Technology is the key· to 

identifying commercially attractive hydrocarbon prospects 

successfully and developing discoveries in these water 

depths. Chief among the exploration keys is the use of 3-D 

seismic data prior to exploratory drilling in conjunction 

with analyses of relative amplitude anomalies and amplitude versus offset. Novel implementation of existing technologies and the development of new exploitation schemes 

are critical to production at these challenging water-depth 

frontiers. 

SHALLOW MIOCENE BRIGHT SPOT PLAY 

A 1979 onshore deep Jurassic Norphlet gas play test in 

southwest Alabama encountered hydrocarbons in shallow 

Miocene sands. This discovery established an exploration 

play that currently extends through Alabama state waters 

and into the GOM OCS (fig. I). Since the initial discovery, 

30 fields have been established onshore and 3 within Alabama coastal waters. An additional 34 proved and 4 unproved fields were discovered on the GOM OCS between 

1981 and 1991. Original recoverable proved reserves in the 

GOM OCS fields are 917 Bcfg, a mean field size of 27 

Bcfg. Preliminary estimates of reserves in the four unproved fields are about 33 Bcfg. 

The hydrocarbon accumulations within this play are 

primarily stratigraphic traps representing lateral pinchouts 

of deltaic and reworked marine sandstone reservoirs. All 

hydrocarbons encountered are natural gas of biogenic origin (Bearden and others, 1986). Exploration targets within 

the play are identified principally on the basis of seismic 

relative amplitude anomalies, commonly referred to as direct hydrocarbon indicators or bright spots. 

Exploration interest in this play has managed to remain 

relatively high due to several considerations that result in 

economically attractive prospects. These factors include 

shallow drilling depths ( 1,500 to 4,500 ft), shallow water 

depths in the offshore (50 to 150 ft), and high exploratory 

success rates on the order of 80 percent. The eastern portion 

of this play has benefited because it overlies the much 

deeper Jurassic Norphlet gas play and is a secondary objective of many of these deep tests. These objectives have also 

been targeted by some operators in this area as a means of 

retaining leases while awaiting developments that could 

improve the economics of the Norphlet gas play. 

SEAGULL PLAY 

The Seagull play occurs off the coast of Texas in the 

Brazos and Galveston areas (fig. 1). The active portion 

of the play covers an area approximately 15 miles wide 

by 75 miles long, the northern limit just seaward of the 
168 THE FUTURE OF ENERGY GASES 

state/Federal boundary. The play is limited to a single 

reservoir sand within the middle Miocene section; the 

reservoir sand appears to be coincident with a disturbed 

interval identifiable on seismic data. The northern limit 

is well defined by the downdip section of a large regional extension fault. Individual· accumulations within this 

play are not large by offshore standards, containing 10 to 

60 Bcfg, but they offer attractive targets for independent 

operators. The play takes its name from the most active 

company in the play, Seagull Energy Exploration and 

Production Inc. 

Prior to 1990, numerous wells were drilled to test this 

disturbed section, and, although the reservoir sand was always found, no commercial hydrocarbons were identified. 

Early in 1990, however, the first successful well was 

drilled. By the end of 1991, as many as 18 wells may have 

been drilled in the play, resulting in five new proved fields 

being discovered. Since the initial discovery, leasing, ex-

. ploratory, and development activity have maintained a 

steady pace. Preliminary estimates of proved reserves in 

these new field discoveries are !55 Bcfg. 

Plays similar to the Seagull play and the shallow Miocene Bright Spot play do not offer the potential for the 

huge reserves of the deep Norphlet gas play or the deepwater Flexure Trend/upper slope areas, nor are they burdened by their equally immense financial risks. They are, 

however, typical of the many play concepts that are being 

actively pursued in the mature shallow-water areas of the 

GOM OCS. Some of these plays are the result of companies willing and able to fill a particular niche. Others are 

the direct result of unconventional thinking. Often this 

thinking evolves from a systematic analysis of past failures. In other instances it results from transferring lessons 

learned in one area to opportunities in another. Dozens of 

similar plays await conception in the mind of the innovative and persistent prospector. The critical ingredients in 

the identification and exploitation of these new plays in 

old areas are the direct consequences of using modern exploration techniques and innovative and unconventional 

concepts and methods. Whatever the play in these areas, 

it is a testimonial to the persistence of the oil and gas 

prospector. 

INFLUENCES OF ECONOMICS ON 

EXPLORATION, LEASE ACQUISITION, 

EXPLOITATION, AND POTENTIAL 

RESOURCES 

The exploitation of petroleum resources is a business 

venture. All aspects of these activities are subject to the 

vagaries of economic analyses. This is particularly true in 

offshore operations with their substantive capital requirements. Some impacts of changing economic expectations 

are immediate, obvious, and well documented-lease acquisition, drilling, seismic acquisition. Others are more subtle and long term. 

An example of the immediate industry response to a 

price shock is the annual average water depth of new field 

discoveries. Historically through 1975 the average water 

depth of new discoveries continued to increase until it 

reached 233 ft (fig. 2). Depths then fluctuated until they 

peaked in 1985 at 345 ft. The price collapse of the last 

quarter of 1985 resulted in a dramatic decrease in the average water depth of fields discovered during 1986 to 

only 91 ft. 

A long-term changing of the guard has been occurring 

in the GOM OCS. For example, in 1991 smaller companies 

drilled more than 86 percent of the exploratory wells, a 

figure approaching the historical high of 91 percent in 

1986, when industry was retrenching from the price collapse of late 1985. Both these figures are much higher than 

the intervening period, when smaller operators drilled 70 to 

75 percent of the exploratory wells, and a decade earlier, 

when major companies drilled most of the wells. The shallower waters of the shelf are becoming the domain of the 

independent operator while the major operators have retained the high-cost, high-risk, high-technology frontiers 

such as the deep water and the Norphlet play. 

The development of discovered hydrocarbons on the 

GOM OCS is sensitive to product prices and exploration, 

development, and production costs. One example of this 

sensitivity is marginal reserves in existing producing fields. 

Major integrated companies are increasingly assigning or 

selling their interests in marginal producing properties on 

the shelf to smaller independent operators who can more 

economically operate these fields. In a recent 12-month period, 2,345 leases were reassigned, up from about 1, 100 

assignments in each of the two preceding 12-month periods. 

The high cost of offshore operations requires large 

minimum economic field sizes. Significant volumes of resources in recently discovered new fields are economically 

marginal at certain cost/price relationships. Nowhere is this 

effect more obvious than in deep-water fields. There have 

been 74 fields discovered in water depths greater than 600 

ft (fig. 6). The leases on 30 fields have since expired without production. Two other fields produced for a period of 

less than two years. Cumulative production in the fields 

was 0.5 MMbo and 5.3 Bcfg. Therefore, 43 percent of the 

geologic successes are confinned economic failures. Twenty fields are classified as proved, 14 of which are producing, and 22 are active unproved fields with development 

decisions still pending. Proved reserves in the deep-water 

GOM OCS are 841 MMbo and 3.71 Tcfg. Not surprisingly, 

the average size of the 20 active proved fields is over 75 

MMboe. In spite of such large fields, it appears, on the 

basis of preliminary estimates of unproved potential, that 

many will be economic failures. The average size of the 17 

unproved fields waiting a development decision and for 
CONVENTIONAL GAS RESOURCES, GULF OF MEXICO OUTER CONTINENTAL SHELF 169 

which preliminary estimates of resources are available is 40 

MMboe. These fields represent a potential addition to the 

reserves base of 390 MMbo and 1.67 Tcfg. Yet, despite 

these large field sizes (by domestic standards), many fields 

will not be developed. 

Internal assessments of undiscovered economically recoverable resources affect long-term company policy, yet 

they are highly sensitive to economic perceptions. The 

MMS principal estimate of undiscovered economically recoverable conventional resources on the GOM OCS as of 

December 31, 1991, is 5.28 Bbo and 60.94 Tcfg. This estimate is an update of the previous assessment presented as 

the primary-case economic scenario (Cooke, 1991 ). The 

scenario assumes initial prices for oil of $18 per barrel and 

$1.80 per Mcf for gas, with a range of real price increases 

encompassing many possible product price paths. These 

assumptions are explained in detail in both Mast and others (1989) and Cooke and Dellagiarino (1990). The range 

of economically recoverable undiscovered oil and gas resources under the assumptions of this economic scenario 

are 0.18 to 16.10 Bbo and 24.10 to 118.88 Tcfg (table 3). 

Nearly three-quarters of the undiscovered oil and 70 percent of the natural gas are projected to exist in water 

depths exceeding 600 ft. 

Resources were also assessed under different economic 

scenarios to show the sensitivity of the volumes of undiscovered resources to assumptions concerning future price/ 

cost relationships. The alternative-case scenario assumes 

starting prices of $30 per barrel and $3.00 per Mcf. In this 

higher price scenario the potential quantities of undiscovered natural gas resources increase to 75.52 Tcf at the mean 

level and 143.34 Tcf at the high level, an increase of 24 and 

21 percent over the respective primary-case estimates. The 

additional resources are derived primarily from high-cost 

deep-water prospects and deeper targets on the shelf. These 

prospects are subeconomic at lower prices, but have significant potential at higher prices. 

The final set of undiscovered resource estimates presented in table 3 is referred to as the undiscovered resource base. This assessment includes all quantities of 

undiscovered conventionally recoverable hydrocarbons estimated to exist in fields larger than 1 MMboe without 

consideration of technological accessibility or profitability. 

These additional resources result from increased recovery 

in fields that are economic in the primary case . as well as 

from prospects that were not profitable. These are smaller 

targets on the shelf, high-cost targets such as deeper objectives on the shelf or in deep or ultra-deep waters, prospects in areas lacking a regional infrastructure, and (or) 

prospects w_ith high geologic risk. As such, this assessment 

represents an upper bound to the volumes of undiscovered 

resources in the GOM OCS. The mean level quantity of 

undiscovered natural gas is nearly 100 Tcf and more than 

150 Tcf in the high case. 

Any qualified critic or expert (and generally everyone 

qualifies) will readily proclaim that quantitative resource 

assessment is an imperfect process. It is constrained in the 

broadest sense by existing knowledge, which in practice is 

always limited and even myopic. The unequivocal geologic model perfectly explaining all aspects of petroleum 

generation, migration, entrapment, and production remains 

to be developed. Poorly understood plays as well as serendipidity, which embraces the unforeseen or unknown 

play(s), are inadequately incorporated in an assessment. 

This nearsighted view of the world order is subsequently 

subjected to at least equally imperfect perceptions of future technology and economic conditions. Nevertheless, all 

we can do is use the best tools and judgment available. 

Having dispensed with this disclaimer, both the alternative 

economic scenario and the resource base encompass undiscovered natural gas resources in quantities approaching 

or exceeding currently discovered volumes. 

CONCLUSIONS 

The discovery process as it unfolded on the GOM 

OCS was typical of most hydrocarbon-producing basins 

Table 3. Estimates of undiscovered hydrocarbon resource potential. 

[Bbbl, billion barrels; Tcf, trillion cubic feet] 

OIL (Bbbl) GAS (Tcf) 

95% 5% Mean 95% 5% Mean 

Primary case 0.18 16.10 5.28 24.10 118.88 60.94 

Alternative case 0.70 19.18 6.80 31.69 143.34 75.52 

Resource base 4.82 15.99 9.49 57.03 158.71 100.16 
170 THE FUTURE OF ENERGY GASES 

worldwide. The largest fields were discovered relatively 

early during the exploration process. As exploration proceeded, discoveries became progressively smaller and 

more difficult to achieve. Coincident with this steady decrease in the mean field size of new discoveries was a decrease in exploratory-well success rates. 

The GOM OCS offers a multitude of exploration challenges. The mature, well-explored shallow-water areas 

have an abundance of geological, geophysical, and production data available. The explorationist with a new concept 

or "wrinkle" will be able to manage risk and successfully 

explore for and discover modest individual accumulations. 

On the other hand, there are also world-class frontiers such 

as the deep-water areas and an emerging subsalt objective 

near the outer shelf edge. The frontier plays offer the potential of giant reserves, but exploring them involves high risk 

and high costs. Exploitation of geologic successes in these 

economically and technologically harsh environments is 

highly dependent upon available technologies and favorable cost-price relationships. 

Seventy-five percent of the 130.5 Tcf of original recoverable proved natural gas reserves have been produced. 

The GOM OCS, however, will continue to be a significant 

source of domestic natural-gas supply in the future. Considerable quantities of unproved reserves exist in new field 

discoveries and in old fields. Continued activity in these 

old fields and plays spurred by the application of new 

technologies have re~ulted in new reservoir discoveries in 

old fields and new field discoveries in old plays. Current 

assessments of undiscovered resources under favorable 

economic scenarios may exceed the volume of proved natural gas reserves discovered to date. 

REFERENCES CITED 

Bearden, B.L., Mink R.M., and Mancini, E.A., 1986, Regional 

geologic framework and petroleum geology of Miocene 

strata of Alabama coastal waters area and adjacent Federal 

waters area, Draft Interim Report to U.S. Minerals Management Service, Cooperative Agreement No. 14-12-0001-

30296: Geological Survey of Alabama and State Oil and 

Gas Board, Tuscaloosa, Alabama, 47 p. 

Cooke, L.W., 1991, Estimates of undiscovered economically recoverable oil and gas resources for the Outer Continental 

Shelf, revised as of January 1990: Minerals Management 

Service OCS Report MMS 91-0051, 30 p. 

Cooke, L.W., and Dellagiarino, G., 1990, Estimates of undiscovered oil and gas resources for the Outer Continental 

Shelf as of January 1987: Minerals Management Service 

OCS Report 89-0090, 115 p. 

Drew, L.J. and Lore, G.L., 1992, Field growth in the Gulf of 

Mexico-A progress report, in Carter, L.M.H., ed., USGS 

research on energy resources, 1992: U.S. Geological Survey Circular 1074, p. 22-23. ~ 

Khan, Abdul S., 1992, Hydrocarbon accumulations, exploration 

plays, and drilling on the Texas and Louisiana Continental 

Slope, in Hunt, M.C., Masterson, A.R., and Miller, L.A., 

eds., Program and Abstracts, Third Symposium on Studies 

Related to Continental Margins-A Summary of Year-Five 

and Year-Six Activities, November 15-18, 1992: Austin, 

Texas, p. 45-46. 

Lore, G.L., 1992, Exploration and discoveries, 1947-1989: An 

historical perspective: U.S. Minerals Management Service 

OCS Report 91-0078, 87 p. 

Marzano, M.S., Pense, G.M., and Andronaco, P.A., 1989, A 

look at the Norphlet in Mary Ann field: Oil and Gas Journal, v. 87, no. I 0, p. 55-58. 

Mast, R.F., Dolton, G.L., Crovelli, R.A., Root, D.H., Attanasi, 

E.D., Martin, P.E., Cooke, L.W., Pecora, W.C., and Rose, 

M.B., 1989, Estimates of undiscovered conventional oil 

and gas resources in the United States-A part of the Nation's energy endowment: Washington, D.C., U.S. Department of the Interior, 44 p. 

Melancon, J.M., Kinler, C.J., Marin, D.A., and Prendergast, 

M.T., 1992, Estimated proved oil and gas reserves, Gulf of 

Mexico, December 31, 1991: U.S. Minerals Management 

Service OCS Report 92-0037, 61 p. 

Meisner, J., and Demiren, F., 1981, The creaming method, a 

Bayesian procedure to forecast future oil and gas discoveries in mature exploration provinces: Journal of Royal Statistical Society, v. 144, no. I, p. 1-31. 

Mink, R.M., Bearden, B.L., and Mancini, E.A., 1985, Regional 

Jurassic geologic framework of Alabama coastal waters 

area and adjacent Federal waters area, Final Interim Report 

to the U.S. Minerals Management Service, Cooperative 

Agreement No. 14-12-0001-30 II 5: Geological Survey of 

Alabama and State Oil and Gas Board, Tuscaloosa, Alabama, 72 p. 

Mink, R.M., Hamilton, R.P., Bearden, B.L., and Mancini, E.A., 

1987, Determination of recoverable natural gas reserves for 

the Alabama coastal waters area, Oil and Gas Report 13: 

Geological Survey of Alabama, Tuscaloosa, Alabama, 74 p. 

Mink, R.M., Tew, B.T., Mann, S.D., Bearden, B.L., and Mancini, E.A., 1990, Norphlet and pre-Norphlet geologic framework of Alabama and Panhandle Florida coastal waters 

area and adjacent Federal waters area, Report to the U.S. 

Minerals Management Service, Cooperative Agreement No. 

14-12-0001-30387: Geological Survey of Alabama and 

State Oil and Gas Board of Alabama, Tuscaloosa, Alabama, 

81 p. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Geologic Studies of Deep Natural-Gas Resources 

in the United States 

By T.S. Dyman1

, D.D. Rice 1

, J.W. Schmoker1, C.J. Wandrey1, R.C. Burruss 1, R.A. Crovelli 1, 

G.L.Dolton1

, T.C. Hester1

, C.W. Keighin1, J.G. Palacas1, W.J. Perry, Jr. 1, L.C. Price 1

, 

C.W. Spencer1

, and D.K. Vaughan 1 

CONTENTS 

Abstract ... . . .. ...... ... .. .... .. .. . .. . ... .. . ... .. .. .... .. .. . .. . ... . . ...... ... . . . . 171 

Introduction .................................................... ............... 172 

Distribution of Deep Wells in the United States 

by Geologic Age ........................................................... 173 

Identification of Known Significant Deep 

Reservoirs ...................................................... ............... 176 

Distr:ibution of Porosity in Sedimentary Rocks 

as a Function of Time-Temperature Exposure ............. 178 

Rocky Mountain Basins . .. . .. . .. ... ... ... . . . . .. . . . ... . ... . . ... .. 178 

Anadarko Basin ...................................................... 180 

N onreservoir Sandstone .. .. .... .. ... . . . . . . . .. .. . ... .. . . .. 181 

Reservoir Sandstone ........................................ 181 

Reservoir Properties of Clastic Reservoirs in the 

Uinta, Wind River, and Anadarko Basins .................... 182 

Sequential Laramide Deformation of the 

Rocky Mountain Foreland-Implications for 

Deep Natural-Gas Resources ....................................... 184 

Potential for Deep Natural Gas in the 

· Hanna Basin-A Case Study ................................. 187 

Source-Rock Potential of Precambrian Rocks in 

Selected Basins ............................................................. 189 

Midcontinent Rift System ...................................... 189 

Lake Superior Segment ................................... 189 

Minnesota Segment ... .... .. .... .. ..... ..... .. ...... ...... .. 190 

Iowa Segment .................................................. 191 

Kansas Segment .............................................. 191 

1

U.S. Geological Survey, Denver Federal Center, Box 25046, Denver, CO 80225-0046. 

Source-Rock Potential of Precambrian Rocks in 

Selected Basins-Continued 

Grand Canyon Area, Northern Arizona ................. 192 

C15+ Hydrocarbon Thermal Destruction and HighRank Deep Basin Natural-Gas Accumulations ............. 193 

Migration of Large Volumes of Hydrocarbon and 

Nonhydrocarbon Gases from the Deep Crust: 

Composition, Flux, and Tectonic Setting ...................... 196 

Resource Assessment Methodologies for 

Deep Natural-Gas Accumulations ................................. 197 

Methodologies for Deep Natural-Gas Resources ... 197 

Hypothetical Deep Basin Example ........................ 198 

Conclusions ................................................................... 199 

Acknowledgments ......................................................... 200 

References Cited ........................................................... 20 I 

ABSTRACT 

Deep parts of sedimentary basins in the United States 

contain large volumes of natural gas. Deep producing 

reservoirs, which are defined as reservoirs at depths 

greater than 15,000 feet (about 4,600 m), accounted for 

7 percent of the total cumulative gas production in the 

United States through 1989 (50 trillion cubic feet (Tcf) 

of 698 Tcf). The distribution and character of undiscovered deep gas accumulations can be better understood 

through the following: (1) Internally sourced hydrocarbons contribute to porosity preservation in some reservoirs at depth in the Anadarko Basin and Rocky 

Mountain Basins. This leads to the derivation of an 

empirical framework for predicting the porosity range of 

171 
172 THE FUTURE OF ENERGY GASES 

sandstones as a function of vitrinite reflectance (R0 ). (2) 

Measurements of capillary pressure, which are very sensitive to confining stress, suggest that small-pore throats 

( <0.1 micrometer), common in fine-grained clastic rocks, 

limit the flow of gas to the well bore. (3) In selected basins of the Rocky Mountain region, structural partitioning 

prior to thrusting, and sequential breakup of the foreland 

during the Late Cretaceous and Paleocene may have 

strongly affected the volume and distribution of deep natural-gas accumulations. (4) In flanking basins of the Midcontinent Rift and the Grand Canyon region, Middle 

Proterozoic source rocks, active hydrocarbon seeps, and 

favorable thermal maturities for generating and preserving natural gas, indicate a potential for economic gas 

accumulations. (5) Methane generation by thermal decomposition of C15+ hydrocarbons takes place at very 

high maturation ranks. C15+ hydrocarbons are thermally 

stable to ranks as high as R0 =7.0 to 8.0 percent in deep, 

,unsheared basins. (6) Significant amounts of carbon dioxide and the presence of hydrogen sulfide indicate that 

thermochemical sulfate reduction and simultaneous oxidation of hydrocarbons to carbon dioxide may be the 

dominant control on nonhydrocarbon gas composition in 

deep carbonate reservoirs. Quartz-vein systems in convergent, transpressive plate-margin basins may act as conduits for migration of natural gas. (7) Where geologic 

information is available concerning known or suspected 

accumulations of deep gas, a "deposit simulation" based 

500 KILOME.T£RS 

300 ~IL£5 

on a geologic model of reservoir volumes is the most appropriate assessment methodology. 

INTRODUCTION 

Because of lower worldwide oil prices, drilling activity in the United States has declined and exploration companies are looking overseas for oil and gas prospects. 

Concurrently, produ~tion from existing wells is declining, 

and U.S. reliance on imported oil is increasing. Even if oil 

prices were to increase drastically, it would take several 

years for domestic exploration to reach previous levels of 

intensity. Many drilling frontiers deserve review from a 

purely geologic perspective. One such frontier is natural 

gas in deep sedimentary basins (fig. 1 ). 

In many respects, natural gas is more preferable than 

oil. The United States is rapidly exhausting its oil reserves 

whereas resource estimates of natural gas remain high. 

According to the National Petroleum Council (1992), the 

United States contains nearly 1,300 Tcf of recoverable natural-gas resources. Natural gas is a clean-burning fuel that 

is far less environmentally damaging than oil. Increased 

use of domestic natural-gas resources would lessen our reliance on foreign oil imports. 

According to Petroleum Information Corporation's 

Well History Control System (WHCS) (Petroleum Information Corporation, 1991), more than 16,000 wells have 

Figure 1. Basins and regions of the conterminous United States containing sedimentary rocks greater than 15,000 

feet (about 4,600 m) deep. Shaded areas represent entire basins. Mts., mountains. 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 173 

been drilled deeper than 15,000 feet (about 4,600 m) in 

the U.S. These deep wells are widely distributed and are 

drilled into rocks of various ages and lithologies, but they 

represent a very small number of the 2.2 million wells 

contained in the data file. 

Almost one-fourth of the total undiscovered naturalgas resources of the onshore lower 48 States lie below 

15,000 feet (139 of 577 Tcf; Potential Gas Committee, 

1990). However, in some basins, only a few deep wells 

have been drilled, and the natural-gas potential of these 

and other deep horizons remains unknown. 

One of the most significant new deep exploration 

plays in the United States is in the Jurassic Norphlet Formation of the eastern Gulf Coast Basin. Woods (1991) 

identified substantial growth in production for this play 

through the year 2005. Geologic and geochemical studies 

by Rice and others (1992) indicate significant potential for 

Norphlet and Smackover reservoirs in the eastern Gulf 

Coast region. 

Of the total U.S. natural-gas resources (nearly 1,300 

Tcf), about 40 percent (519 Tcf) is considered unconventional including such sources as coalbed methane, gas from 

shales, gas in low-permeability sandstone reservoirs, and 

deep-basin gas accumulations (National Petroleum Council, 

1992). New geologic research dealing with all aspects of 

natural-gas exploration and production is needed to fully 

realize the potential of these unconventional sources. 

The U.S. Geological Survey has initiated an active research program to investigate the geologic parameters controlling the distribution of deep natural gas. This report is 

a summary of part of this geologic research conducted as 

an outgrowth of work funded by the Gas Research Institute (Rice, 1989; Dyman, 1992). 

DISTRIBUTION OF DEEP WELLS IN THE 

UNITED STATES BY GEOLOGIC AGE 

Wandrey and Vaughan (1992), using Petroleum Information Corporation's WHCS file current to June 1991, 

published nine digital maps showing wells drilled deeper 

than 15,000 feet (about 4,600 m). WHCS contains geologic and engineering data for approximately 2.2 million 

wells drilled in the United States; of these, 16,500 wells 

were drilled deeper than 15,000 feet (Petroleum Information Corporation, 1988; 1991 ). Figures 2 and 3 of this report are compilations of plates l through 9 of Wandrey 

and Vaughan (1992). 

Wells that have produced hydrocarbons from depths of 

15,000 feet or greater, color-coded by geologic age of the 

producing reservoir rocks are shown in figure 2. Whereas 

the WHCS file is current, it is not always complete or entirely accurate. Various methods were used to ensure accuracy and completeness. Several checks were made to 

ensure that the wells shown on figure 2 did in fact produce 

from depths greater than 15,000 feet. Often the records indicated that a well was drilled to greater than 15,000 feet 

and produced hydrocarbons, but the depth of production 

was not identified in the WHCS data file. In these cases, 

wells were checked against subsurface geologic maps, 

depths to top of producing formations, and initial-potential 

(IP) data files. Information on individual wells in the Gulf 

Coast region was particularly misleading or lacking. In 

many cases, the wells in the Gulf Coast region were 

drilled into salt domes created by salt migration from 

older deeper salt beds into younger rock, and the age of 

the salt rather than the age of the surrounding rock was 

identified. 

Nonproducing wells color-coded by the geologic age 

of the oldest rocks penetrated are shown in figure 3. Nonproducing means that hydrocarbons were not economically 

producible at any depth at the time drilling was completed. 

Shows of oil and (or) gas may have been present but were 

insufficient to warrant production, or well-completion 

problems precluded production. Because the WHCS file 

uses the same code for dry holes and abandoned producers, some wells labeled as dry holes may in fact have 

produced hydrocarbons in the past or were temporarily 

"shut-in" until pipelines or production facilities were completed. The number of wells that have produced or are still 

producing hydrocarbons is relatively accurate, but dry-hole 

estimates may be high. 

The yellow parts of figures 2 and 3 show areas of basins with sedimentary rocks at depths of 15,000 feet or 

greater. Sedimentary thickness data were compiled using a 

sedimentary rock depth contour map of the continental 

United States (Frezon and others, 1983), an unpublished 

basement map of the southwestern United States (W.C. 

Butler, written commun., 1992), and well-log and seismic 

data for the Midcontinent Rift System (Anderson, 1990). 

A summary of deep wells and basin types from the 

WHCS data file is shown in table I. Of the 6,178 wells 

that produce or have produced hydrocarbons from depths 

greater than 15,000 feet, 4,54 7 are gas wells or gas- and 

condensate-producing wells. The total wells column of 

table l does not always equal the sum of the other three 

columns because some wells produced both oil and gas 

and were therefore listed twice. Some wells lacked final 

well-classification information indicating the type of production. Still other wells lacked a basin identification because of insufficient location information. More than 200 

wells were not shown on figures 2 and 3 because well 

classification and location problems could not be resolved. 

Geologic age of formation at total depth of well was absent in the WHCS data file for many offshore wells in the 

Gulf Coast Basin, but approximate ages were determined 

by comparing the total depths to neighboring wells with 

age information. Wells outside the yellow areas on figures 

2 and 3 may have inaccurate location data or the yellow 

area may not have been extended far enough because of 
.__ _ __.I Sedimentary rocks at 

depths > 15,000 ft 

Cenozoic 

Mesozoic 

Paleozoic 

Figure 2. Petroleum exploration wells of conterminous United 

States drilled deeper than 15,000 feet (about 4,600 m) completed 

as dry holes, and color-coded by age of formation at total depth. 

Areas of basins containing sediment at a depths greater than 15,000 

feet are shaded yellow. Data from Petroleum Information Corporation Well History Control System (Petroleum Information Corporation, 1991). Scale, I inch (2 .5 em) equals approximately 400 miles 

(about 670 km). 
L--_ ___.1 Sedimentary rocks at 

depths > 15,000 ft 

Cenozoic production 

Mesozoic production 

Paleozoic production 

,. 

Figure 3. Petroleum exploration wells of conterminous United States 

drilled deeper than 15,000 feet (about 4,600 m) completed as producing wells, and color-coded by age of formation at total depth. Areas 

of basins containing more than 15,000 feet of sedimentary rock 

are shaded yellow. Data from Petroleum Information Corporation 

Well History Control System (Petroleum Information Corporation, 

1991 ). Scale: I inch (2.5 em) equals approximately 400 miles (about 

670 km). 

Cl 

tTl 

0 

r 

0 

Cl 

n 

U'l 

...., 

c 

ti 

tTl 

U'l 

0 

'Tl 

ti 

tTl 

tTl 

"0 

z 

~ c 

:::0 

> r 

6 

> U'l 

:::0 

tTl 

U'l 

0 

c 

:::0 

() 

tTl 

U'l 

z 

...., 

::r:: 

tTl 

c::: 

z 

::J 

tTl 

ti 

U'l 

>l i-3 

tTl 

U'l 
176 THE FUTURE OF ENERGY GASES 

Table 1. Summary of deep wells by production category for selected basins in the United States. 

[Data from Well History Control System (WHCS) data file through 1991 (Petroleum Information Corporation, 

1991)] 

Basin or province Tota1 1 Oil Gas Oil/gas Basin type 

Anadarko----------------- 1,258 41 1,231 Foreland 

Ardmore------------------ 10 0 10 0 Foreland 

Arkoma----~-------------- 6 10 0 Foreland 

Bighorn------------------- 4 0 4 0 Foreland 

Green River-------------- 107 24 81 0 Foreland 

Gulf region -------------- 3,465 999 2,411 35 Passive margin 

Marietta ------------------ 14 3 II 0 Foreland 

Permian------------------- 873 22 793 2 Continental margin, rift 

Piceance ------------------ 2 I 0 Foreland 

Powder River------------ 32 31 0 0 Foreland 

San Joaquin-------------- 6 5 0 0 Foreland 

Uinta---------------------- 154 152 2 0 Foreland 

Ventura ------------------- 6 4 2 0 Transpressive 

Wind River-------------- 72 6 65 0 Foreland 

1

Total wells column does not always equal the sum of the other three columns because some 

wells produced both oil and gas and were therefore listed twice. Total wells column does not equal 

the 6,178 wells discussed in text. Some wells lacked final well classification information indicating 

type of production, and in still other cases, location information was insufficient to determine the 

correct basin. Approximately 169 of these wells were not plotted on figures 2 and 3 because well 

classification and location problems could not be resolved. 

insufficient data. The Uinta Basin and the Gulf Coast 

Basin, the two areas where t~ere are significant numbers 

of deep oil wells, are producing from Mesozoic and Cenozoic rock. The success ratio of approximately 46 percent 

for these deep wells is higher than for all wells together. 

IDENTIFICATION OF KNOWN 

SIGNIFICANT DEEP RESERVOIRS 

Geologic conditions or variables favorable for naturalgas accumulations in deep sedimentary basins (Dyman and 

others, 1992) are derived from the digital maps of Takahashi and Cunningham ( 1987), Wandrey and Vaughan 

(1992), and from published information and computerized 

data files. Computerized data were taken primarily from the 

NRG Associates, Inc., field file (NRG Associates Inc., 

1988; 1991) and Petroleum Information Corporation's 

WHCS file (Petroleum Information Corporation, 1988; 

1991). NRG's field file contains geologic, production, and 

engineering data for significant reservoirs (reservoirs with 6 

billion cubic feet (Bcf) of gas ultimately recoverable) in the 

United States. 

Because a producing horizon may extend both above 

and below 15,000 feet, NRG retrievals were selected for 

all reservoirs below 14,000 feet (about 4,300 m) to capture 

all reservoirs near or below 15,000 feet. As many as 378 

significant reservoirs in the United States produce from 

depths greater than 14,000 feet, and 256 produce from 

depths greater than 15,000 feet. These reservoirs are primarily in the Gulf Coast, Permian, Anadarko, Williston, 

Powder River, Wind River, and Green River Basins, and 

in the Wyoming Thrust Belt (fig. 1). A brief summary of 

the main geologic and production characteristics of significant reservoirs from these regions is outlined in table 2. 

U.S. sedimentary basins contain additional deep gas reservoirs below 14,000 feet, but these reservoirs do not meet 

the minimum production qualifications for entry into the 

NRG Associates field file. 

According to Dwight's Energy Data (1985), 1,998 

total reservoirs produced below 14,000 feet in the United 

States at the end of 1985. Of the total cumulative naturalgas production in the United States (698 Tcf; Mast 

and others, 1989), deep reservoirs account for 7 percent 

(50 Tcf) of the total, and significant d~ep reservoirs (NRG 

reservoirs) account for nearly half (21.4 Tcf; table 2) of 

the deep reservoir total (Dyman and others, 1990). Deep 

gas reservoirs account for only a small part of the Nation's 

total cumulative production. 

Sixty-six percent of the deep significant reservoirs are 

classified as gas producers. An additional 25 reservoirs are 

classified as oil and gas producers. Sixty-eight percent of 

all significant deep reservoirs are classified as structural or 

combination (combined structural and stratigraphic) traps. 

Fifty percent of these reservoirs (188 reservoirs) produce 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 177 

Table 2. Summary of significant deep reservoirs in selected deep basins and areas of the United States. 

[Information based on data from NRG Associates field file (NRG Associates, 1988). There are 378 significant deep reservoirs in the United States, but 8 of these reservoirs 

from the Wi11iston Basin and Pacific region are not included] 

Number of 

Basin reservoirs and 

percent of total 

Gulf Coast -------- 174/370= 

47 percent. 

Permian------------ 89/370= 

24 percent. 

Anadarko---------- 85/370= 

Rocky Mountain 

Basins. 

23 percent. 

22/370= 

6 percent. 

Known Cumulative gas recoverable gas and percent of 

total gas and percent of 

total gas 

6.2/21.4= 13.3/33.7= 

29 percent. 40 percent. 

12.4/21.4= 15.1/33.7= 

58 percent. 45 percent. 

2.4/21.4= 2.8/33.7= 

II percent. 8 percent. 

0.4/21.4= 2.2/33.7= 

2 percent. 7 percent. 

from Mesozoic or younger rocks, and 58 percent (221 reservoirs) produce from clastic rocks of any geologic age. 

As expected, the number of reservoirs decreases with increasing depth, but more than one quarter (26 percent) of 

the total significant deep reservoirs are below 17,000 feet 

(about 5,200 m). 

Of the 378 deep reservoirs, 174 (or 47 percent) occur 

in the Gulf Coast Basin (table 2). Reservoirs are primarily 

in Tertiary clastic rocks and deeper mixed carbonate-clastic rocks of Mesozoic age. Forty percent of the known recoverable natural-gas resources (13.3 Tcf) in significant 

deep reservoirs occurs in the Gulf Coast Basin. 

The other. significant deep reservoirs occur in the 

Permian, Anadarko, and Williston Basins, and in basins 

of the Rocky Mountain region, California, and Alaska 

(table 2). Large volumes of deeply buried sedimentary 

rocks are. present in other basins in the United States 

where few or no wells have been drilled and where no 

significant gas production now exists. Recent work by 

Stratigraphic and 

lithologic 

information 

Tertiary reservoirs 

mostly clastic; 

Jurassic and 

Cretaceous 

reservoirs mixed 

carbonate and 

clastic. 

Middle Paleozoic 

mixed clastic 

and carbonate 

reservoirs; 

Silurian and 

Devonian mostly 

carbonate 

reservoirs. 

Mostly clastic rock 

reservoirs. Some 

production from 

Cambrian and 

Silurian 

carbonate 

reservoirs. 

Jurassic and 

Cretaceous 

clastic 

reservoirs and 

Paleozoic mixed 

carbonate and 

clastic reservoirs. 

Number of fields 

discovered prior 

to 1970 and 

percent of total 

641174= 

37 percent. 

32/174= 

36 percent. 

25/85= 

29 percent. 

9122= 

41 percent. 

Comments 

3 7 percent of deep 

reservoirs are Tertiary. 

67/89 reservoirs occur in 

Devonian or oider 

rocks. Permian 

reservoirs 

stratigraphically 

trapped. 

65 percent of reservoirs 

produce from 

Pennsylvanian strata. 

Deep gas mostly from 

Utah-Wyoming Thrust 

Belt. Potential from 

Hanna, Wind River, 

Piceance, Green River, 

Uinta, Crazy 

Mountains, Big Hom, 

and Raton Basins. 

Palacas (1992) indicates that parts of the Midcontinent 

Rift System may contain Precambrian source rocks capable of generating natural gas below 15,000 feet. Deep 

Rocky Mountain Basins (fig. 1) including the Raton, Albuquerque, and Crazy Mountains Basins have been 

sparsely drilled and the recoverable natural gas resource 

is unknown. Furthermore, drilling data analyzed by Wandrey and Vaughan (1992; figs. 2, 3) show that the deeper 

parts of many productive basins have not been adequately drilled even where promising source and reservoir 

rocks are presumably present. For the last U.S. Geological Survey national petroleum assessment (Mast and others, 1989), 59 of approximately 250 petroleum plays 

assessed contain reservoir rocks at least in part, below 

15,000 feet (Dyman, unpub. data). Work with large computerized data files by Dyman and others (1990) and 

Dyman and others (1992) suggests that additional significant quantities of deep natural gas remain to be found in 

sedimentary basins of the United States. 
178 THE FUTURE OF ENERGY GASES 

DISTRIBUTION OF POROSITY IN 

SEDIMENTARY ROCKS AS A FUNCTION 

OF TIME-TEMPERATURE EXPOSURE 

One of the factors that has inhibited deep drilling for 

clastic and carbonate reservoirs is the knowledge that porosity and permeability can be too low to sustain economic 

hydrocarbon production (see Hefner, this volume). Better 

predictive relations for determining the porosity range of 

sandstones (Schmoker, 1992; Hester, I992) can aid in risk 

evaluation in deep-drilling programs. Porosity trends, as 

functions of thermal maturity, may be represented by vitrinite reflectance (R0). In this context, R0 serves as a general 

index of burial history. In addition to R0, clay content, carbonate cementation, grain size, and hydrocarbon generation 

data are used to provide a probable porosity range. 

ROCKY MOUNTAIN BASINS 

Examples from the Rocky Mountain region are drawn 

from Cretaceous sandstones, with emphasis on the Lower 

Cretaceous Muddy Sandstone ("J" sandstone of drillers' 

usage, MacMillan and Weimer, 1976) of the Denver 

Basin, Colorado, and Upper Cretaceous sandstones of the 

Mesaverde Group of the Piceance and Uinta Basins, Colorado and Utah (fig. 4). 

Porosity-thermal maturity relations, like porositydepth curves, do not provide much insight into the actual 

processes causing porosity change in the subsurface. The 

Big Horn and 

Crazy Mountains Basins 

Wind 

Green River 

Uinta Basin 

Piceance Basin 

1170 

I 

San Juan Basin 

Montana 

influence upon porosity by factors such as grain size and 

sorting, clay matrix, framework composition, early cementation, overpressuring, proximity to unconformities, dissolution (secondary porosity), and coating of framework 

grains is empirically accounted for by porosity-R0 trends 

that represent the I Oth, 25th, 50th, 75th, and 90th porosity 

percentiles of data sets (fig. 5). 

The 90th porosity percentile, for example, represents 

strata of the data set that have rock properties relatively 

favorable for porosity preservation or development; in 

contrast, the I Oth porosity percentile represents intervals 

of the data set with properties that result in low porosities 

at similar levels of thermal maturity. By depicting porosity 

using the I Oth through 90th porosity percentiles (fig. 5), 

the porosity range at a given R0 is taken into account. 

An empirical approach for estimating the porosity and 

the porosity range of Cretaceous sandstone in Rocky 

Mountain Basins is based on two models (A and B) 

(figs. SA, SB). These two models better represent porosityR0 data than regression lines fitted to the entire R0 range. 

For R0 values less than 0.9 percent, trendlines for models A 

and B are identical and represent all data. Model A applies 

to strata in which porosity continues to decrease at a uniform rate as R0 values increase above 0.9 percent. Model B 

applies to strata in which the rate of porosity loss becomes 

more gradual as R0 values increase above 0.9 percent. 

Models A and B do not directly represent variability in rock 

properties such as grain size and sorting, shale content, and 

composition of framework grains. The porosity variations 

induced by these factors are already incorporated in the 

porosity range defined by the 1Oth through 90th porosity 

Denver Basin 

Kansas 

400 Miles 

645 Kilometers 

c=:J Potential deep gas 

areas 

Figure 4. Rocky Mountain Basins where deep natural gas is interpreted to be present on the basis 

of gas shows, formation tests, geology, and known production. Potential deep gas areas are of 

depths greater than 15,000 feet. 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 

20 

10 

20 

10 

~ 

"-- 8 >- f--

u; 6 0 

15 5 a_ 

0.4 0.5 0.6 

A 

0.4 0.5 0.6 

B 

1-- Ao=0.9% 

I 

0~ 08 09 1~ 

Ro(%) 

1-- Ro = 0.9"1'. 

I 

0.7 0.8 0.9 1 0 

Ra(%) 

2.0 

2.0 

Type 

curve 

Type 

curve 

3.0 

3.0 

Figure 5. Plot of porosity (%, percent) versus vitrinite reflectance (R0 ) showing subjective 

trendlines representing the I Oth, 25th, 50th, 75th, and 90th porosity percentiles for Cretaceous 

sandstone data set from Rocky Mountain Basins. The dashed type curve is a reference line that 

represents sandstone in general (Schmoker and Gautier, 1989). For R0 values less than 0.9 

percent, trendlines of Figure 5A and B are identical and represent all data (Schmoker, 1992). 

For R0 greater than 0.9 percent, trendlines of A (model A of text) represent strata in which 

porosity continues to decrease at a uniform rate; trendlines of B (model B of text) represent 

strata in which the rate of porosity loss becomes more gradual as R0 values increase above 0.9 

percent. 

179 

percentiles. Rather, models A and B are interpreted as sandstone in which porosity evolution follows one of two 

fundamentally different pathways. Models A and B are derived from observation of porosity-R0 crossplot patterns 

(Schmoker, 1992) and represent a working hypothesis. 

The choice of diagenetic pathway (model A versus 

model B) is important for sandstone porosity prediction in 

deep parts of Rocky Mountain Basins. At R0 =2.0 percent, 

for example, model A predicts median porosities of about 2 

percent and 90th percentile porosities of only 4 percent; in 

contrast, model B predicts median porosities of about 5 

percent and 90th percentile porosities of 8 percent. Extrapolating beyond the data to R0=3.0 percent, model A predicts that the lOth- through 90th-percentile porosities are all 

less than 3 percent, whereas model B predicts some porosities of 6 to 7 percent. Maximum depths of production predicted by model A in a given area of a basin would be 

thousands of feet less than those predicted by model B. 
180 THE FUTURE OF ENERGY GASES 

The particular strata of the data set that conform to 

model B are from the Upper Cretaceous Almond Formation in the Green River Basin and the Upper Cretaceous 

Mesaverde Group in the Piceance Basin (fig. 4). Lowpermeability sandstone in both formations is commonly 

overpressured, at R0 greater than 0.9 percent, owing to hydrocarbon generation. Some Cretaceous sandstones in 

Rocky Mountain Basins may not follow "normal" diagenetic pathways because of the effects upon diagenesis of 

hydrocarbon generation from adjacent and interbedded 

coal and organic-rich shale. 

The hypothesis that porosity evolution can follow distinctly different pathways as R0 increases above 0.9 percent has significant implications for the economic 

production of deep hydrocarbons. Hydrocarbon generation 

in overpressured nonsubsiding basins of the Rocky Mountain region may retard porosity loss as R0 increases in at 

least three ways. These are (1) hydrocarbons can inhibit 

cementation by displacing pore water, (2) carbon dioxide 

and organic acids produced by the thermal breakdown of 

kerogen can create secondary porosity by dissolving cements and framework grains, (3) overpressuring can slow 

pressure solution and associated porosity decrease by reducing the lithostatic load on grain contacts. Overpressuring can also reduce cementation by developing a fluid-flow 

system characterized by expulsion, rather than exchange, 

of liquids. Although the relative importance of these three 

reasons is difficult to determine, the presence of hydrocar50 

10 REGRESSION-liNE 

FRAMEWORK FOR 

.o SANDSTONES IN GENERAL 

O' 

>- 1-

U5 

0 

a: ANADARKO BASIN 

0 NONRESERVOR CL SANDSTONES : 

to 

bons is the fundamental reason for porosity preservation at 

depth and an important factor in the presence of deep natural-gas resources. 

If hydrocarbon generation is indeed the primary underlying process that causes some sandstone to deviate from 

porosity-R0 trends similar to those of figure SA and instead 

follow trends similar to those of figure 5B, then the results 

of this analysis are not restricted to Rocky Mountain Cretaceous sandstone but are applicable to other deep sedimentary basins in the United States and elsewhere. 

ANADARKO BASIN 

Anadarko Basin sandstone-porosity trends can also be 

analyzed with respect to thermal maturity using the same 

techniques described for sandstone in the Rocky Mountain 

region (Hester, 1992). Hester based his analysis on three R0 

data sets (figs. 6 and 7). The first data set provides a porosity-R0 trend typical of Anadarko Basin hydrocarbon-bearing 

sandstone reservoirs of Paleozoic age. Nonreservoir sandstone in the second data set is defined as Paleozoic sandstone typical of the Anadarko Basin and may be reservoir 

sandstone at other locations. Nonreservoir sandstone provides a background with which to compare other sandstone. 

The third data set represents sandstone samples of diverse 

ages, diagenetic facies, and thermal histories from regions 

outside the Anadarko Basin. 

Ro - t1% 

90th 

75th 

50th 

25th 

lOth 

0.2 -~---r--~---,--,---,----,---,-----r---'-------,------,-----,----, 

02 1 0 

VITRINITE REFLECTANCE I%) 

Figure 6. Porosity (%, percent) of Anadarko Basin nonreservoir sandstone versus vitrinite 

reflectance (R0 ) plotted with least-squares regression lines fit to each of two nonreservoir 

sandstone data sets separated at R0 values=l.l percent (dashed where inferred). Also plotted are least-squares regression lines fit to the lOth, 25th, 50th, 75th, and 90th porosity 

percentiles of the framework data set representing sandstone in general (third data set of 

text, representing sandstones of diverse ages, facies, and diagenetic histories; Schmoker 

and Hester, 1990). 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 181 

>-

1-

Ui 

0 

a: 

0 

()_ 

50 

10 

1 0 

ANADARKO BASIN ~· 

RESERVOIR------

SANDSTONES 

BOX DIAGRAM 

PERCENTILES 

~I :;:> ~ :::: 50th 

~ 

Vi 25th i'ii 

5 t Oth 

:;::: PERCENTILE 

ANADARKO BASIN 

I>.Q\JRESERVOIR 

SANDSTONES 

. .. 

0.2+--------,-----,--~r--.---,-,--,-,--------------,------~------

0.2 1.0 2.0 3.0 

VITRINITE REFLECTANCE (%) 

Figure 7. Porosity (%, percent) of Anadarko Basin reservoir sandstone versus vitrinite reflectance (R0 ) values plotted with least-squares regression line. Box-diagram percentiles 

representing Anadarko Basin nonreservoir sandstone data are shown. 

NONRESERVOIR SANDSTONE 

A least-squares fit to the porosity-R0 data for nonreservoir sandstone of the central and southern Anadarko Basin 

shows that sandstone porosity generally declines with increasing thermal maturity (fig. 6). However, the data appear 

to consist of two separate populations-a less thermally 

mature population represented by R0 values of less than 1.1 

percent, and a more thermally mature population represented by R0 values of greater than 1.1 percent. Correlation 

coefficients of the least-squares fit to each population 

shows a much stronger dependence of porosity on R0 for. 

the less mature trend of nonreservoir sandstone than for 

sandstone in general. The improved correlation of the less 

mature trend over that of the entire data set suggests that 

the two data populations might best be considered separate 

trends. The two trends probably overlap to some extent as 

the more mature diverges from the less mature. Nevertheless, for the purposes of this report, a single preliminary 

boundary separating the two trends is placed at about R0 

values= 1.1 percent. 

In both the general and nonreservoir data sets, porosity 

generally declines as a power function of increasing thermal maturity. The least-squares fit to the data show that for 

R0 less than 1.1 percent, the rate-of-porosity decrease with 

increasing R0 for nonreservoir sandstone is more rapid than 

that of the average trend of the porosity-R0 framework representing sandstone in general (fig. 6). For R0 greater than 

1.1 percent, the rate-of-porosity decrease for nonreservoir 

sandstone is less rapid than that of sandstone in general. 

Sufficient data to substantiate a probable cause for the 

change of slope of the porosity trend of Anadarko Basin 

nonreservoir sandstone are not yet available. The two populations of nonreservoir sandstone-porosity data (fig. 6) may 

represent sandstones from different geographic areas, depositional environments, or subsurface pressure regimes, or 

sandstones with different burial or cementation histories. 

RESERVOIR SANDSTONE 

The porosity-R0 trend of Anadarko Basin reservoir 

sandstone follows a different pattern than the nonreservoir 

sandstone. The least-squares fit shows that the rate-of-porosity loss for reservoir sandstones is much slower than 

that of both nonreservoir sandstone of the central and 

southern Anadarko R0 , and that of sandstone in general 

(fig. 7). This relatively slow rate of porosity decline with 

increasing R0 may reflect overpressuring, the inhibiting effects of early hydrocarbon emplacement, or even economic factors such as the bias inherent in the selection of 

sandstone hydrocarbon reservoirs. 

As R0 increases from low levels to about 1.1 percent, 

the porosity trends of Anadarko Basin reservoir and nonreservoir sandstone cross (fig. 7). As thermal maturity levels increase above about 1.1 percent R0 , however, the 

slopes of these porosity trends are similar; these similarities suggest that sandstone of the Anadarko Basin may retain sufficient porosity for economic accumulation of 

hydrocarbons, even at high thermal maturities. 
182 THE FUTURE OF ENERGY GASES 

RESERVOIR PROPERTIES OF 

CLASTIC RESERVOIRS IN THE UINTA, 

WIND RIVER, AND ANADARKO BASINS 

An understanding of pore structures and how they are 

formed and modified with increasing depth and burial history is useful for optimizing production in deep sedimentary basins. Effects of confining stress on pore geometry, as 

well as on porosity and permeability in clastic reservoirs at 

various depths can be investigated by mercury-injection porosimetry on samples under confining stress (Keighin, 

1992). Nineteen samples from three basins (Uinta, Wind 

River, and Anadarko Basins, see fig. I, table 3), from different depths, and with different diagenetic histories, were 

analyzed. The samples varied primarily in the relative 

abundance of quartz, feldspar, and rock fragments (table 3); 

carbonate cementation is locally prevalent. 

Mercury-injection porosimetry is based on volume 

distribution measurement of pore throats; the method depends on forcing mercury into small voids (or pore 

throats) within the rock. Pore throats control access to 

larger voids (pores), because greater pressures are required 

1,000 

• 

100 "tl 

E 

>- 10 -

..c 

lU 

4) 

E 

.. 1 4) 

a. 

Cl 

.. 0.1 4) 

..c 

• I• 

c: 

4) 

.Ill: 

c: 

~ 0.01 • :I 

- II._ -,_ lA 

' 0.001 c: II •• ""'·I .... ·- • 

0.0001 -- 0 2 4 6 8 10 12 14 16 

A In-situ Helium porosity (%) 

to force mercury, or other nonwetting fluids, into smaller 

spaces (Purcell, 1949). Therefore, pore throats are bottlenecks in the system, and it is necessary to exceed their 

critical capillary pressure to inject mercury into pores. By 

injecting mercury at incrementally higher pressures, and 

allowing time for equilibration between pressure increments, mercury is injected into increasingly smaller pores. 

It is then possible to calculate the size distribution of pore 

throats, and to determine how pore-throat size is affected 

by increasing confining stress to approximate reservoir 

conditions, and how this affects permeability. Klinkenberg 

(1941) showed that, especially in low-permeability media, 

permeability to a gas is a function of the mean free path of 

the gas molecules. 

Porosity and permeability of samples show a wide 

range of values, although porosity is typically less than 8 

percent and Klinkenberg determined permeability to be 

below 0.1 millidarcies (md) for all samples examined 

(table 3). Plots of in-situ Klinkenberg permeability against 

in-situ helium porosity (fig. 8A) and standard air permeability (fig. 88) show a general decrease in porosity and permeability with depth, but depth is not the only factor affecting 

the decrease of both. Nor is the decrease in porosity with 

1,000 

100 I 

"tl 

E 

10 >- ~ I v 

- = ..c 

lU 

Cl) 1 E 

v .. 

Cl) 

a. 

Cl 

.. 0.1 

, / Q) 

..c 

c: 

Q) 

.Ill: 

c: 0.01 / • ~ 

- :I 

-lA 0.001 ' I t7 -

f=:o c: 

= 

-

-

0.0001 -

0.001 0.01 0.1 10 100 1,000 

B Standard air permeability (md) 

Figure 8. In-situ Klinkenberg permeability (md, millidarcies) versus in-situ helium porosity (%, percent) and routine air permeability 

(md, millidarcies) for core samples from Anadarko, Uinta, and Wind River Basins. A, in-situ Klinkenberg permeability versus in situ 

helium porosity and B, in-situ Klinkenberg permeability versus routine air permeability. 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 183 

Table 3. Modal analyses of petrographic data, physical grain properties, and porosity and permeability of samples from Uinta, Wind 

River, and Anadarko Basins. 

[-.-,zero or trace; ND. not determined] 

Modal analysis 1 

(volume percent) 

Propenjes porosity Permeahjljty3 

Permeability 

(percent) 

(In-situ/Ambient) 

No. Sample Depth (ft) (see below) (percent) (md) 

Q F R Size Sort Ang. Helium2 Modal Ambient In-situ. 

Uinta Basin, Utah 

Ch 1-35 11852 

2 Ch 1-35 11932 

91.3 

93.1 

2.5 

3.1 

6.2 

3.8 

165 

193 

0.7 

0.8 

3.5 

2.1 

2.2 

4.0 

3.0 

7.6 

0.0065 

0.0165 

0.0004 

0.0018 

6.15 

. 10.9 

Anadarko Basin, Oklahoma 

3 OK-I 

4 OK-2 

5 OK-3 

6 OK-4 

7 OK-5 

8 OK-6 

9 OK-7 

10 OK-8 

II OK-9 

18076 

16078 

11960 

12072 

16626 

10161 

7096 

7197.5 

10378 

100.0 

98.1 

99.6 

100.0 

99.5 

98.7 

91.4 

99.6 

98.7 

207 

0.8 1.1 148 

0.4 210 

!56 

0.5 140 

0.9 0.4 166 

1.0 7.6 321 

0.4 209 

0.65 0.65 101 

0.4 

0.4 

0.9 

0.4 

1.0 

0.5 

0.4 

1.7 

1.5 

3.5 

2.9 

2.0 

2.0 

2.5 

3.6 

3.8 

3.8 

0.6 

2.0 

4.9 

13.3 

4.3 

8.8 

ND 

14.0 

12.8 

9.6 

0.8 

8.5 

24.0 

6.0 

10.8 

15.4 

25.0 

22.0 

4.8 

0.0050 

0.0729 

95.466 

0.0477 

0.5185 

ND 

343.75 

50.75 

0.0078 

0.0010 

0.0078 

89.6 

0.0026 

0.1975 

ND 

330.20 

47.65 

0.0032 

20.0 

10.69 

93.39 

5.45 

38.09 

ND 

96.06 

93.89 

41.03 

Wind River Basin, Wyoming 

12 WY-8 

13 WY-10 

14 WY-20 

15 WY-21 

16 WY-25 

17 WY-27 

18 WY-31 

19 WY-35 

12097.5 

12111 

12709.4 

13483 

13517.3 

13527 

13602.5 

13631 

85.5 

85.2 

75.8 

60.4 

69.7 

77.8 

80.0 

62.1 

2.0 

0.5 

2.4 

3.9 

4.3 

3.9 

10.9 

15.9 

12.5 

14.3 

21.8 

35.7 

26.0 

18.3 

18.3 

22.0 

317 

162 

255 

330 

226 

317 

397 

272 

0.7 

0.5 

0.8 

1.0 

1.2 

0.8 

0.5 

0.5 

1.5 

1.5 

2.0 

1.8 

1.2 

1.5 

2.1 

2.2 

6.5 

8.2 

5.5 

5.9 

3.7 

5.2 

4.7 

6.7 

12.2 

9.5 

6.1 

5.7 

4.1 

3.3 

4.9 

7.2 

0.0157 

0.0077 

0.0106 

0.0133 

0.0012 

0.0052 

0.0051 

0.0065 

0.0022 

0.0017 

0.0012 

0.0010 

0.0001 

0.0005 

0.0011 

0.0024 

14.01 

22.07 

10.85 

7.52 

8.33 

9.62 

21.57 

36.92 

1

Content of quartz (Q), feldspar (F), and rock fragments (R), normalized to I 00 percent. 2

In-situ values of helium porosity are listed. 3

Permeabi1ity values, in millidarcies, were measured to correct for Klinkenberg effect; listed are averages of two or more determinations. 

Properties 

Gram Size Sorting Angularity 

Size (in m) 

550- 250 

250- 125 

125- 62.5 

Wentwonh size 

Medium sand 

Fine sand 

Very fine sand 

Visual estimate 

0 -0.35 

0.35 - 0.5 

0.5 - 1.0 

1.0 - 2.0 

depth uniform. Examination of thin sections indicates that 

whereas compaction due to increasing burial depth appears 

to be a factor, the degree of compaction is greatly influenced by lithology, especially by the presence and quantity 

of labile rock fragments. Cementation, either by silica or 

carbonate minerals, reduces both porosity and permeability 

as well as significantly modifying pore structure. 

The relative abundance of rock fragments may have a 

significant effect on both porosity (macro and micro) and 

Degree of sorting 

Very well sorted 

Well sorted' 

Moderately sorted 

Poorly sorted 

Class interval 

2.0- 3.0 

3.0- 4.0 

4.0- 5.0 

Grade term 

Subangular 

Subrounded 

Rounded 

permeability. Compression of labile rock fragments reduces 

intergranular porosity and creates intergranular pseudomatrix porosity; effective permeability is thus reduced. 

Partial dissolution of rock fragments commonly creates microporosity; micropores introduce micropore throats, which 

restrict fluid migration. 

Confining stress has a varying effect on permeability. 

Plots of air-mercury capillary pressure versus wetting phase 

(that is, air) saturation, and pore-size frequency versus 
184 THE FUTURE OF ENERGY GASES 

pore-throat diameter are plotted for four wells in figure 9. 

Data suggest that samples from King Stevenson No. 1 

Anderson and Humble Patterson No. 1 (figs. 9A, 9B) wells 

from the Anadarko Basin are porous and have large visible 

pores. However, plots of pore-size frequency versus porethroat diameter for these wells, reveal that pore throats in 

these samples are most frequently in the 10 f.U11 or less 

range, which is significantly smaller than pores visible in 

thin section. Plots of air-mercury capillary pressure versus 

wetting-phase saturation for these samples show that pore 

throats are constricted by increased confining stress, although not as dramatically as in samples with lower initial 

porosity and permeability, and smaller measured pore 

throats. Data plotted for the Monsanto 1-35 Dolis well in 

the Wind River Basin (fig. 9C) and the Kerr McGee No. 1 

Tentanque well (fig. 9D) in the Anadarko Basin indicate 

that for samples more typically fitting the tight sandstone 

designation, pore throats are more typically in the less than 

0.1 !ID1 size range, and that these already small pores are 

further reduced by confining stress. Accordingly, even 

though pores visible in thin section may be relatively large, 

all pores must be accessed through pore throats, which are 

smaller (often much smaller) than the pores themselves. 

The data also suggest that pore throats, rather than stressrelief microfractures, are closed with increasing confining 

stress. Variations in the size and distribution of pore throats 

may be important factors in controlling reservoir quality in 

deep natural-gas reservoirs. 

SEQUENTIAL LARAMIDE 

DEFORMATION OF THE 

ROCKY MOUNTAIN FORELANDIMPLICATIONS FOR DEEP 

NATURAL-GAS RESOURCES 

The structural setting and trapping mechanisms of deep 

natural-gas accumulations in different sedimentary basins in 

the Rocky Mountain region can be used as models from 

which to compare the structural characteristics of other deep 

basins (Perry, 1989; 1992; Perry and others, 1992). Also, the 

timing and structural style of Rocky Mountain Basins can 

be used to determine the evolution of deformation and to 

establish the timing of natural-gas entrapment. 

A southeastward progression of major uplift and consequent basin development in the Rocky Mountain foreland 

began in extreme southwestern Montana during Cenomanian and Turonian time with the Blacktail-Snowcrest uplift 

(figs. 10, 11). The Late Cretaceous eastward progradation of 

the Laramide deformation front reached the Colorado Front 

Range (central Colorado, fig. 11) by 69 Ma. Subsequent 

Laramide deformation spread northeastward from the Granite Mountains-Shirley Mountains uplift in south-central 

Wyoming; the Laramide deformation front reached the 

Black Hills by late Paleocene time. The Laramide first created the Wind River and then the Powder River Basins, and 

later it partitioned these basins from an earlier continuous 

foreland basin with minor welts (figs. 10, 11). These broad 

structural welts of low relief, such as the San Rafael swell in 

eastern Utah, had begun to grow in the Rocky Mountain 

foreland by mid-Cretaceous time. 

South of the large-scale east-west crustal discontinuity 

along the Wyoming-Colorado border, which separates 

Archean basement rocks on the north from Proterozoic 

basement rock to the south, Laramide deformation proceeded from east to west; it culminated along and defined the 

eastern boundary of the Colorado Plateau during the late 

Eocene (fig. 11 ). 

Economic implications of this new model of deformation of the Rocky Mountain foreland include progressive 

..... Figure 9. Capillary pressure (psia, pounds per square in of 

air) versus wetting-phase (air) saturation (%, percent) and poresize distribution (!!ffi, micrometers) for samples at ambient 

temperature and pressure and under in-situ stress conditions. 

Measurements under ambient conditions are represented by rectangles; in situ measurements represented by triangles. The values 

of porosity and permeability which follow are in-situ values. A, 

Anadarko Basin, sample OK-8; porosity, I2.8 percent; perme-. 

ability, 47.65 md. Shape and configuration of the capillary pressure versus saturation curve indicate that mercury entered pores 

at relatively low pressure, and essentially complete saturation occurred at approximately 7,000 psia. Although the l~rger pores are 

approximately 50x 100 !!ffi, measured pore-size distribution 

shows the majority of pore throats to be smaller than approximately I5 !!ffi. B, Anadarko Basin, sample OK-3; porosity, 13.3 

percent; permeability, 89.6 md. Measured porosity and visible 

pores suggest properties very similar to those of sample OK-8. 

The capillary pressure vs. saturation curve indicates that more 

pore throats are being constricted by application of confining 

stress. The pore-size distribution curves reveal a slightly higher 

proportion of larger pores (although still in the 20 !!ffi size range) 

in· this sample compared to OK-8; pore throats under confining 

stress are typically smaller than I5 !!ffi. C, Wind River Basin, 

sample WY-21; porosity, 5.9 percent; permeability, 0.0010 md. 

Capillary pressure versus saturation curves show that mercury 

saturation of pore space is not accomplished, even at I 0,000 

psia, and that entry into pores is significantly restricted with increasing confining stress. Pore-size distribution curves reveal that 

unconfined pore throats are typically smaller than approximately 

I !!ffi; when under confining stress, pore throats are reduced significantly in size and are typically Jess than 0.05 !!ffi. D, Anadarko Basin, sample OK-I; porosity, 2.0 percent; permeability, 

0.0010 md. Physical appearance of the sample suggests very low 

porosity and permeability (due, at least in part, to compaction 

and cementation by carbonate arid silica overgrows). Examination of the thin section illustrated in Keighin (1992) suggests that 

the "thin-film" intergranular pores may be I to 2 f.Ull across. 

Pore-size distribution curves, however, show that pore throats are 

most often <0.2 !lffi (unconfined) to 0.04-0.I f.UI1 (confined). See 

Keighin ( 1992) for sample and well location data. 
.. 

.. 

a. 

~ 

• " • 

~ 

a. 

a. 

.. 

u 

Gl 

N 

.. 

~ 0 

0.. 

A 

.. 

• a. 

a. 

• u 

>-

" r:: 

Qj 

:::1 

C" 

Qj 

Cll 

!! 

.. 

.. 

0 

0.. 

B 

GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 185 

10 

9 

8 

7 

6 

5 

4 

3 

,000 

,000 

,000 

,000 

,000 

,000 

,000 

,000 

0 "' 

2,000 

1,800 ~ .. 1,600 ~ 

1,400 : 

.:: 

1,200 ~ 

1,000 .8 

< 800 

600 

400 

200 

0 0 10 20 30 40 50 60 70 80 90 100 

30 

20 

10 

0 

0.01 

0 

\ 

\ 

\ 

\ 

10,000 

9,000 

8,000 

7,000 

6,000 

5,000 

4,000 

3,000 

2,00 

1,00 0 it 

"-.: 0 

Wetting-phase saturation (%) 

i\ • 

~~ \ 0.1 10 100 

Pore-throat diameter <pm) 

!"'~... 

0 1 0 20 30 40 50 60 70 80 90 

30 

20 

10 

0 

0.01 

Wetting-phase saturation (%) 

- ~ 0.1 1 

Pore-throat 

.,.. 

~14 t\ 10 

diameter <pm) 

100 

2 

1 

1 

1 

1 

1 

,000 

g ,800 G:i 

,600 ~ 

,400 e 

u. ,200 Q) 

> ,000 _g 

< BOO 

600 

400 

200 

0 

:E 

Gi "' 

J: 

.. 

e 

a. 

a. 

< 

100 

1000 

.. 

• a. 

~ 

• "• 

~ 

a. 

a. 

• u 

10,000 

9,000 

8,000 

7,000 

6,000 

5,000 

4,000 

3,000 

2,000 

1,000 

l 

Cll 

N 

.. 

~ 0 

0.. 

c 

.. 

·;; 

a. 

20 

16 

12 

4 

0 

0.01 

10,000 

~ 9,000 

• " • 8,000 

~ 7,000 

6,000 

~ 5,000 

'ii. 4,000 

• u 3,000 

~ 2,000 

1,000 

0 

0 

0 

! 16 

> 

g 12 Qj 

:::1 

C" 

~ 8 

Gl 

!! 

• 

.. 

0 

0.. 

D 

4 

0 

0.01 

~ 

m 

0 

~ 

\ \ 

\ 

\ 1\ 

"\ "\ 

P\-._ 

""\ ""--

1\. '"""- ~ ,.....__ 

---- ~ 

2,000 

g 1,800 :;; 

1,600 ~ 

1,400 e 

1,200 ~ 

1,000 ~ 

800 

600 

400 

200 

0 

< 

:E 

Gi "' 

J: 

.. 

e 

a. 

a. 

< 

1 0 20 30 40 50 60 70 80 90 100 

I 

Wetting-phase saturation (%) 

"' w<~ 

I 1111 Ill~ 0.1 

Pore-throat 

I IIIII 

10 

diameter <pm) 

L 100 

\ 

\ 

~ 

~ 

~ ~ 

~ ..._._..._,_ 

---.0.::...::::: ::--. 

10 20 30 40 50 60 70 80 90 

Wetting-phase saturation (%) 

• 

~\ 

q~ 

G 

0.1 1 

Pore-throat 

10 

diameter <pm) 100 

2, 

1, 

1, 

1, 

1, 

1, 

1000 

000 

800 ~ .. 600~ 

400 :: 

.:: 200 " 

> 

0 000 < "" 8 

6 

2 

00 

00 

400 

00 

:E 

Gi "' 

J: 

.. 

e 

a. 

a. 

< 

100 

1000 
186 THE FUTURE OF ENERGY GASES 

opening and subsequent blockage of migration paths for 

hydrocarbons generated from source rocks in southeastern 

Idaho, southwestern Montana, Wyoming, Colorado, and 

eastern Utah. Regional and basinwide exploration models 

for deep natural gas should consider trapping mechanisms 

in light of this deformation model. 

0 100' - 1lr lWO lOB' 106' 104' _ 102---

~---T----~---~---~-- l 

MONTANA 

Figure 10. Rocky Mountain foreland province showing 

principal Laramide basins and uplifts. AU, Axial Uplift; 

BB, Bighorn Basin; BHU, Black Hills Uplift; BSU, 

Blacktail-Snowcrest Uplift; BU, Bighorn Uplift; CA, 

Casper Arch; CMB, Crazy Mountains Basin; FRU, Front 

Range Uplift; GHB, Grand Hogback Uplift; GRB, Green 

River Basin; GR-SU, Granite Mountains-Shirley Mountains (Sweetwater) Uplift; HB, Hanna Basin; HU, 

Hartville Uplift; LB, Laramie Basin; LU, Laramie Uplift; MA, Moxa Arch; MBU, Medicine Bow Uplift; 

200 

I 

I 

I 

I 

NORTH 

DAKOTA 

-----

SOUTH 

DAKOTA 

NEBRASKA 

..J ____ __, 

COLORADO I 

I 

t---

1 

I 

\ 

I 

I 

\ 

400 KILOMETERS 

OCU, Owl Creek Uplift; PB, North and Middle Parks 

Basin; PCB, Piceance Creek Basin; PRB, Powder River 

Basin; PSU, Park-Sierra Madre Uplift; RAU, Rawlins 

Uplift; RU, Rock Springs Uplift; SCU, Sangre de Cristo 

Uplift; SSU, Sawatch-San Luis Uplift; SWB, Sand Wash 

Basin; UB, Uinta Basin; UMU, Uncompagre Uplift; UU, 

Uinta Mountains Uplift; WB, Washakie Basin; WHU, 

White River Uplift; WMU, Wet Mountains Uplift; WRB, 

Wind River Basin, and WRU, Wind River Uplift. Modified from Bayley and Muehl berger ( 1968). 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 187 

POTENTIAL FOR DEEP NATURAL GAS 

IN THE HANNA BASIN-A CASE STUDY 

Source-rock and structural data can be used effectively to identify the deep natural-gas potential of the Hanna 

Basin in southern Wyoming (Perry, 1992). The Hanna 

Basin (fig. 12) contains more than 30,000 feet (about 

9,150 m) of Phanerozoic sedimentary rock of which more 

than 15,000 feet (about 4,600 m) is Upper Cretaceous and 

predominantly of marine origin. Less than 2,500 feet 

(760 m) of pre-Cretaceous Phanerozoic sedimentary rocks 

is present. Latest Cretaceous(?) and Paleocene nonmarine 

rock (the Ferris and Hanna Formations) is more than 

14,000 feet (about 4,300 m) thick. 

The basin contains numerous horizons of Late Cretaceous(?) to Paleocene coals (Glass, 1975; Glass and Roberts, 1984 ). Analyses of pollen samples from these coals 

indicate that virtually the entire 8, 150-feet (2,480 m)-thick 

coal-bearing section is Paleocene in age (D.J. Nichols in 

Perry, 1992). The nonmarine formations penetrated are 

. gas prone, and shallow equivalent rocks are being exploited for coalbed methane. 

Vitrinite samples were analyzed from the Hanna Unit. 

No. 1 well (figs. 12, 13). The well was completed as a 

dry hole to a total depth of 12,496 feet (3,809 m) within 

the Paleocene part of the Ferris Formation. Vitrinite reflectance (R0 ) values rose rapidly to 1.23 percent near the 

bottom of the hole (Ben Law, unpub. data, U.S. Geological Survey). Because of these high reflectance values, the 

more deeply buried marine Cretaceous rocks should have 

generated thermogenic natural gas. However, only one 

small gas field has been developed on the northwestern 

flank of the basin. 

EXPLANATION 

1::;: ':;j Area of major uplift 

I j Area of subdued uplift 

Sea-level contour at surface of Precambrian 

basement 

--+-•• Arch axis-Showing direction of plunge 

Syncline or· basin axis-Showing direction of plunge 

Foreland thrust-fault zone-Sawteeth on upthrown 

block; dashed where approximately located; 

dotted where inferred 

• • • Front of Cordilleran thrust belt-Sawteeth on 

upthrown block; dashed where approximately 

located; dolled where inferred 

////////// Left-slip fault zone--Obscured by younger cover 

Figure 10. Contmued. 

The Hanna Basin is surrounded by Laramide thrust 

faults, which are imprecisely dated. The coal-bearing nonmarine Hanna and Ferris Formations may represent the 

time of maximum thrust-related subsidence. Also, the 

northern margin of the Hanna Basin may represent the 

locus of a zone of latest Cretaceous to Paleocene strikeslip faulting. It may be the northern boundary of the zone 

of Colorado Front Range-Laramie Range Laramide 

shortening. 

The sequence of three structural events are interpreted 

for the· Hanna Basin region. First, the east-west trending 

Hanna trough sequence of thick marine Upper Cretaceous 

sediment developed across southern Wyoming. Second, 

the Hanna Basin was partially isolated as a subarea of the 

Greater Green River Basin by early Paleocene growth of 

the Granite Mountains-Shirley Mountains transpressive 

zone to the north. Third, southward tilting probably occurred during middle Paleocene time concurrent with 

growth of the Sweetwater Uplift and initial development 

of the Shirley Thrust Fault along the northern margin of 

the basin. The last phase of structural growth, uplift of the 

Medicine Bow Mountains and Rawlins Uplift, concurrent 

with development of the Arlington Thrust, appears to have 

been initiated in late Paleocene time. The geometry of the 

northern margin of the basin (figs. 12, 13) suggests the 

possibility of large gas fields in the undrilled northern part 

of the basin beneath the Shirley Thrust provided gas 

generation continued during and after thrusting. Published 

seismic data (Kaplan and Skeen, 1985) do not adequately 

define the structure of the northern margin of the Hanna 

Basin. 

'- Montana 

200 Mil .. 

320 Kllornetero 

Figure 11. Sequence of inception of Laramide deformation in 

millions of years before present (Ma). Arrows represent migration of Laramide deformation front. 
188 THE FUTURE OF ENERGY GASES 

If the scenario described herein is correct, many deep 

accumulations of natural gas remain to be found in Rocky 

Mountain Basins. Because of the high vitrinite reflectance 

values at depths of greater than I 0,000 feet (3,040 m) in 

the Hanna Basin, deeper Cretaceous rocks should also 

yield natural gas. 

1 o 7" 1 06"30' 1 os• 

I I I 

:~~--i·:.:_ ::~:~:;.i-=:;,· .. ;,.:~-~-~+:· ~----~~~Nl)' ____ ~~r Sfit<~ 

...... · ..• sw~~~TER ..••..•.... · •.. · .. · • WYOMING ~! ~ •. c i 

42°-

42"30' -

. :·:: :.: . ._:: . . . .: . o I o · ' ,·: : ·· 

·:.·,·. ~ID~u~ ... -....:· . . ··,· .. : 0 

.. ... a:: liD ....... · .... 

··~ .. •' ...... .. · .. · ... .. . .. · .. 

25 Miles 

40 Kilometers 

EXPLANATION 

__.--0- Sea-level contour at surface of Precambrian 

basement 

~ Arch axis-Showing direction of plunge 

A 1\ 1\ Foreland thrust-fault zone--Sawteeth on upthrown 

block; dashed where approximately located; 

arrows show relative motion 

ti .~ .· ':< 

I 

Figure 12- Tectonic map of the Hanna Basin region, Wyoming (modified from Blackstone, 1990), showing location 

of Hanna Unit No. I well and cross section (fig. 13). Stippled pattern shows areas of structurally elevated Precambrian basement significantly above sea level. 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 189 

-10,000 

-20,000 

Shirley Thrust 

sw ' - - _) ' 

\ 

Hanna Formation ----/ 

Ferris 

1-----? 

CretaceoUS rocks 

FEET /-

1 Mile = 1.6 Kilometers 

Fault 

NE 

0 

-10,000 

Figure 13. Diagrammatic cross-section through the northern part of the Hanna Basin, Wyoming (line of cross section shown in fig. 12). 

Modified from Blackstone, 1983. 

SOURCE-ROCK POTENTIAL OF 

PRECAMBRIAN R,OCKS IN 

SELECTED BASINS 

Proterozoic rocks are widely distributed in the United 

States and commonly occur in the deeper parts of many 

sedimentary basins. Their petroleum source-rock potential, 

however, is poorly known (Palacas, 1992). The reason for 

assigning petroleum potential to Precambrian rocks in the 

United States is influenced by the actual production of 

commercial oil and gas derived from Precambrian rocks in 

other parts of the world such as in Russia, China, and 

Oman. Two regions of the United States, the Midcontinent 

Rift System and the Grand Canyon area of northern Arizona can be evaluated for their source-rock potential from 

Proterozoic rocks. 

MIDCONTINENT RIFT SYSTEM 

Middle Proterozoic rock of the Midcontinent Rift System· define strong gravimetric and magnetic anomalies. 

The 940-mile-long (1,570-km) Midcontinent Rift System 

is a failed rift characterized by a series of asymmetric basins filled with clastic rock, in places as thick as 32,000 

feet (about 9,750 m). The Midcontinent Rift System is 

conveniently divided into four geographically identifiable 

segments: Lake Superior, Minnesota, Iowa, and Kansas 

(fig. 14). 

LAKE SUPERIOR SEGMENT 

The potential for petroleum reserves in the Midcontinent Rift System has long been recognized because of the 

active crude-oil seeps emanating from the approximately 

1.1 billion-year-old Nonesuch Formation near the White 

Pine Mine in Minnesota. In this segment, the Nonesuch 

Formation consists of interbedded dark gray · to green 

sandstone, siltstone, and silty shale with poor source-rock 

potential. However, for silty shale that occurs in thin intervals, total organic carbon (TOC) content ranges from 0.25 

to 2.8 percent (table 4). Should thicker sections of this hydrocarbon-generating shale be present downdip from the 

outcrop belt and be subjected to higher levels of thermal 

maturation (but still within the wet gas to dry gas window; 

Rice, 1989), the gas source-rock potential for the Lake Superior segment and adjoining areas in northern Wisconsin 

may be considered good. 
190 THE FUTURE OF ENERGY GASES 

Sd'-

95° 

I 

MANITOBA _j1. ONTARIO 

- ·- ·------- · \...._"'--_~-L. 

NORTH 

DAKOTA 

SOUTH 

DAKOTA 

\ 

" 

•r'\., 

MINNESOTA 

'® .. · I 2 ___, 

I ,-- --

90° -50° 

\ 

WiSCONSIN 

f ~:--------

-) 

I 

I 

I ....--- 40° 

I LLI NO IS I 

INDIANA 

40°-

KANSAS MiSSOURI 

,__,... 

' J 

95. 

\ 

90° 

0 100 

Miles 

0 100 200 

Kilometers 

Figure 14. Location and major rock types of the Midcontinent 

Rift System and the location of the four sites in which potential Precambrian source rocks were studied. I, Lake Superior 

segment outcrop belt (bracketed); 2, Minnesota segment, Lonsdale 65-1 well, Rice County ; 3, Iowa segment, Amoco EiscMINNESOTA SEGMENT 

The source rock potential of the Minnesota segment 

of the Midcontinent Rift System is evaluated from examination of Precambrian Solar Church Formation as sampled in the Lonsdale 65-1 well, Rice County, Minnesota 

(fig. 14). The formation consists principally of interbedded 

conglomerate, sandstone, siltstone, and shale or mudstone. 

Analyses of core samples, mainly from the bottom 20 percent of the core, show TOC content ranging from 0.01 to 

I .-, _/ -~-J--

( 

( .... 0 .. Rocks of Midcontinent Rift System • --.r-----..1 y 

\ 

es· 

CLJ 

~ 

Keweenawan 

clastic rocks 

Keweenawan 

volcanic rocks 

+ Location of AMOCO 

M.G. Eischeid #1 

well 

heid No. I well, Carroll County; 4, Kansas segment, Texaco 

Poersch No. I, Washington County, and Producers Engineering 

Finn No. I, Marshall County (modified from Palacas, 1992). 

Line of cross-section A-A' shown from Palacas and others, 

1990. 

1. 77 percent and averaging 0.24 percent; the TOC content 

indicates an overall poor source-rock potential for oil or 

gas for the entire formation (table 4). A very low average 

genetic potential (S 1+S2) is largely attributed to the advanced level of thermal maturation. On the basis of maturity evaluations for basins worldwide, Solar Church 

organic matter at the Lonsdale 65-1 locality has advanced 

to the transition stage between the wet gas and dry gas 

generating zones (table 4). Therefore, the natural gas 

source-rock potential of the Precambrian Solar Church 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 191 

Table 4. Summary of possible Precambrian hydrocarbon source rocks in the Midcontinent Rift System and Grand 

Canyon area of northern Arizona. 

(TOC, total organic carbon; T max• maximum temperature 1 

TOC (weight percent) 

Location Stratigraphic unit Maturity level 

Range Average 

Midcontinent Rift System 

Lake Superior segment --- Nonesuch Formation 

Minnesota segment-------- Solar Church Formation 

(mudstones). 

Iowa segment--------------- Nonesuch Formation 

equivalent (dark 

shales). 

Kansas segment Keweenawan 

(Producers (undifferentiated 

Engineering Finn siltstones). 

No.I well). 

0.25-2.8 0.6 

0.13-1.77 0.4 

0.1-1.4 0.6 

0.1-0.8 0.6 

418-427 

494 

497-508 

445-450 

Marginally mature to 

mature. 

Overmature. 

Overmature. 

Mature. 

Grand Canyon area, Northern Arizona 

Eastern Grand Canyon---- Walcott Member of 

Kwagunt Formation 

of Chuar Group (dark 

mudstones). 

1.0--9.0 

Formation, near the Lonsdale well and presumably in the 

neighboring areas, is poor. 

IOWA SEGMENT 

The hydrocarbon source-rock assessment of the Iowa 

segment of the Midcontinent Rift System was made from 

the thickest part (14,898 feet or 4,541 m) of the Precambrian sequence. Assessment is based on analyses of core 

and cuttings samples from the 17,851-feet-deep (5,441-m) 

Amoco M.G. Eischeid No. I well, drilled in 1987 in an 

asymmetric half-graben-like basin northwest of the Iowa 

horst, Carroll County, Iowa (Palacas and others, 1990; 

Schmoker and Palacas, 1990; fig. 14). Most of the Precambrian sedimentary rock, composed of red and redbrown sandstone, siltstone, and silty shale, is oxidized and 

has no source-rock potential. Between 15,000 feet (about 

4,600 m) and 16,425 feet (5,006 m), however, 200 to 300 

feet (60 to 90 m) of gray to black, pyrite-bearing, organicrich laminated shale is present. This sequence may be 

equivalent to the Nonesuch Formation of the Lake Superior region. Maximum temperature (T max) from Rock Eva! 

analyses strongly indicates that the shales are thermally 

overmature and in the transitional zone between wet gas 

and dry gas, similar to the findings for the Solor Church 

Formation in southeastern Minnesota (table 4). The laminated shales have little remaining capacity for hydrocar-

-3.0 424-452 Mature. 

bon generation but may have generated significant 

amounts of gas in the geologic past. Equivalent laminated 

shale facies, as those observed in the Eischeid well, might 

have fair to good hydrocarbon source-rock potential if 

present at shallower depths of burial, under lower levels of 

thermal stress, along basin flanks, away from the frontal 

fault zone of the medial horst. 

KANSAS SEGMENT 

The Kansas segment of the Midcontinent Rift System 

was evaluated on the basis of well cuttings from two 

boreholes in northeastern Kansas: the Texaco Poersch No. 

I well and the Producers Engineering Finn No. I well 

(fig. 14). Samples from the two wells exhibit remarkably 

different lithologies; this difference probably indicates different structural, stratigraphic, and (or) depositional regimes. Hence, the two sections of rock may belong to two 

different subbasins. Geophysical and borehole data indicate that the Midcontinent Rift in northeastern Kansas is 

divided into small subbasins that probably are only a few 

tens of square miles in extent. 

The Poersch well, drilled to a total depth of 11,300 

feet (3,440 m), penetrated 2,846 feet (867 m) of Phanerozoic rock and 8,454 feet (2,580 m) of Precambrian 

(Keweenawan) rock, the latter of which is composed 

of nearly equal successions of highly oxidized arkosic 
192 THE FUTURE OF ENERGY GASES 

sandstone and siltstone and mafic volcanic and intrusive 

rock. Organic matter was not identified in any of the oxidized sedimentary rock. 

The Producers Engineering Finn No. 1 well showed 

some minor gas source potential in a 300-ft (91-m) section 

of gray siltstone directly beneath the Precambrian-Phanerozoic boundary unconformity. Thermal maturity values contrasted dramatically with the much higher maturity values 

observed in the Minnesota and Iowa segments of the Midcontinent Rift System, but they demonstrate some gas 

source-rock potential (table 4). Because of the structural 

complexity and abrupt facies changes, individual subbasins 

need to be examined before complete source-rock evaluation can be made of the Kansas part of the rift system. 

GRAND CANYON AREA, NORTHERN ARIZONA 

The Late Proterozoic Chuar Group is exposed in the 

eastern part of the Grand Canyon (fig. 15). It is composed 

of a 5,370-feet-thick (1 ,640-m) succession of predominantly very fine grained siliciclastic rock that contains thin units 

UTAH COLORADO 

NEW MEXICO 

36'30' 

112'30' 112'00' 

A -~0 _ _.__~10 Miles 

~ ~-0 -~° Kilometers 

of sandstone and stromatolitic and cryptalgal carbonate 

rock. More than half the succession consists of organic-rich 

gray to black mudstone and siltstone. 

Geochemical analyses indicate that the 922-feet-thick 

(280-m-thick) Walcott Member, the uppermost unit of the 

Kwagunt Formation (fig. 15), has good to excellent petroleum source-rock potential. The lower half of the Walcott is 

characterized by TOC contents of as much as 8 to 10 percent (averaging approximately 3 percent, table 4), hydrogen 

indices of as much as 204 milligrams hydrocarbon per 

gram of rock (mgHC/g), genetic potentials (S 1+S2) of nearly 16,000 ppm, and extractable organic matter of as much 

as 4,000 ppm. Preliminary data for the upper Walcott suggest that these rocks are as rich or richer than the lower 

Walcott. Maturity assessment indicates that source rocks of 

the Walcott are within the oil generation window. 

Strata of the underlying thermally mature Awatubi 

Member of the Kwagunt Formation and the thermally mature to overmature Galeros Formation are, in general, rated · 

as poor oil sources with genetic potentials generally less 

than I ;000 ppm, but they appear to be acceptable to good 

source rocks for gas generation. 

Sixtymile 

Formation 

Walcott Member - 0-000 0-0 ------ Pisol11ic Chert --tz-=· Z~ ::."'"c:-:j' ,.::::i.., =1· F I a k y D a I om 1 t e 

Awalubl Member 

Carbon Bulle Member 

Duppa Member 

Carbon Canyon 

Member 

Jupiler Member 

------

----

----

------

------

~=""'="""'=-9 Shales w1th _ ---- _- stromatollles 

------

------

-..f==>=-===1 Stromatolites 

T anncr Mcml>cr 

1 Massive 

coarsely 

Kwagunt 

Formation 

a: 

c( 

;::) 

r 

u 

Galeros 

Formation 

~~~~~].~~I~ crystalline 

_...J.J..L_J--.J--'-' ~o ~ m ~ e _ _ _ __ _ 

B 

Figure 15. Map and section of eastern Grand Canyon, northern Arizona. A, Map showing eastern Grand Canyon in northern Arizona. 

Sampling area shown by solid black pattern, B, Simplified geologic section of the Precambrian Chuar Group. (Modified from Vidal 

and Ford, 1985.) 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 193 

Chuar Group strata may be potential sources for economic accumulations of gas and oil in upper Proterozoic or 

lower Paleozoic reservoir rocks in northwest Arizona and 

Utah. The relative proportion of gas or oil in any one area will 

depend in large part upon the degree of thermal maturation. 

Cts+ HYDROCARBON THERMAL 

DESTRUCTION AND HIGH-RANK DEEP 

BASIN NATURAL-GAS ACCUMULATIONS 

Thermal maturation models are questionable by predicting that CIS+ hydrocarbons are thermally destroyed 

when R0 values exceed 1.35 percent and that CrC4 

hydrocarbons are destroyed when R0 values exceed 2.00 

percent. Thermal destruction of C1s+ hydrocarbons at temperatures corresponding to R0 = 1.35 percent also would 

seem to contradict physical-chemical principles, because of 

the extreme bond strengths (82.6 to 117 kilocalories/ mole), 

which must be broken for hydrocarbon destruction. Data 

from Price (1992) indicate that CIS+ hydrocarbons may be 

thermally stable at R0 values from 7.0 to 8.0 percent in the 

natural system, dependent on several variables in deep petroleum basins. The C2-C4 hydrocarbons are probably thermally stable well into greenschist metamorphism, and 

methane may persist to mantle conditions. 

Evidence for significant thermal stability of CIS+ hydrocarbons comes from a large petroleum-geochemical data 

base (Price, 1992), part of which is shown in tables 5 and 6. 

These data demonstrate that high to moderate concentrations of indigenous C1s+ hydrocarbons and bitumen persist 

in deeply buried rocks at present-day R0 values of 1.35 to 

5.0 percent. Furthermore, moderate to low concentrations 

of C15+ hydrocarbons and bitumen persist in rocks with R0 

values of 5.0 to 7.0 percent. 

Qualitative analyses of bitumen from high-rank rocks 

(R0 of 2.0 to 7.6 percent), high-rank gases and gas condensates, and bitumen from aqueous-pyrolysis experiments in 

the hydrocarbon-thermal-destructive phase all provide significant insight into CIS+ hydrocarbon thermal destruction. 

Characteristic carbon-isotopic and chemical assemblages 

occur both in hydrocarbon gases and Cs+ hydrocarbons 

prior to, and during, C1s+ hydrocarbon thermal destruction. 

C1s+ hydrocarbon thermal stability is controlled by 

organic matter (OM) metamorphism which includes all reactions involving the maturation of kerogen and the generation, maturation, and thermal destruction of methane, all 

C2+ hydrocarbons, and bitumen (Price, 1992). OM metamorphism is hypothesized to occur by a parallel series of 

first-order reactions and is thus controlled primarily by 

burial temperature and geologic. time. However, a large 

body of petroleum-geochemical data suggest that OM 

metamorphic reactions are not first order but are higher 

ordered reactions. If this is the case, then geologic time 

would play little or no role in OM metamorphism. There 

are four controlling parameters, suggested by Price (1992), 

which have direct bearing on the genesis and persistence of 

deeply buried, high-rank gas accumulations. These are: 

1. The absence or presence of water in the system is 

important because C1s+ hydrocarbon thermal destruction is 

significantly promoted in water-barren systems and is suppressed in water-bearing systems. 

2. Increasing fluid pressure suppresses all aspects of 

OM metamorphism, including C1s+ hydrocarbon generation and thermal destruction. 

3. Whether the reaction takes place in an open or 

closed system is also important, because a lack of product 

escape from reaction sites (closed systems) retards OM 

metamorphism, and product escape (open systems) promotes OM metamorphism. 

4. Increasing temperature is the principal drive for OM 

metamorphic reactions, which is in agreement with presentday petroleum-geochemical paradigms. 

Oil and gas accumulations are zoned in many petroleum-bearing basins. Only dry gas is present in deep-basin 

Table S. Vitrinite reflectance (R0 ) for samples from selected wells extrapolated from vitrinite reflectance at well bottom. 

[Extrapolation based on depth versus R0 plots, all of which have correlation coefficients of less than 0.99. Sediment age is range of rock ages penetrated in well bore] 

Well Location Depth Vitrinite reflectance Sediment age Reference (meters) (percent) 

Lone Star Bertha Rogers Washita County, 9,S83.7 8.0 Permian through Price and others (1981). 

No. 1. Oklahoma. Cambrian. 

Ralph-Lowe No. I ----------- Pecos County, 8,686.4 S.8 Permian through Price (1988). 

Texas. Ordovician. 

Shell McNair No. 1---------- Hinds County, 6,911.0 2.8 Lower Tertiary through Price and others (1979). 

Mississippi. Jurassic. 

Chevron Jacobs No. 1 ------- Goliad County, 7,S46.8 7.S Miocene through Lower Price ( 1982). 

Texas. Cretaceous. 

Pan Am Foester No. 1------- La Salle County, 6,703.7 7.0 Lower Tertiary through Price and Clayton 

Texas. Jurassic. (1990). 
194 THE FUTURE OF ENERGY GASES 

Table 6. Vitrinite reflectance, bitumen and hydrocarbon content, and present day burial temperature for samples from selected wells 

in Texas and Oklahoma. 

[NA, not available; ppm, pans per million; mg/gOC; milligrams per gram of organic carbon; TOC, total organic carbon (in percent). C 15+ bitumen and c 15+ hydrocarbons in ppm by rock weight and normalized to organic carbon; S2 is the Rock Eva) S2 pyrolysis in ppm and mg/gOC, which is the hydrocarbon index (Hi). Burial 

temperatures for the Foerster No. I well based on estimated geothermal gradient for LaSalle County, Texas of 36.7°/km] 

cl5+ bitumen Ct5+ hydrocarbons 

Depth {meters) 

Vitrinite 

reflectance 

ppm mg/gOC ppm mg/gOC 

HI 

TOC mg/gOC ppm 

Present day 

burial temp. 

("C) 

Age 

Foerster No. 

4602-4724 

4724-4846 

4968-S1S1 

S1S1-S334 

S334-S4S6 

S4S6-SS78 

S761-S882 

2.S8 

2.73 

3.10 

3.36 

3.60 

3.80 

4.37 

193 

2S2 

S56 

828 

740 

442 

467 

80.4 

lOS 

132 

172 

IS4 

108 

31 

114 

118 

280 

S45 

476 

271 

165 

47.7 

49.2 

67.0 

114 

99.1 

56.1 

10.8 

0.24 

0.24 

0.42 

0.48 

0.48 

0.41 

l.SI 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

196 

201 

211 

218 

224 

228 

238 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Jurassic. 

Jurassic. 

Jurassic. 

Jurassic. 

Ralph Lowe No.1 

6026-60321 

6629-663S 1 

6882-68881 

7080-7087 

7324-7330 

7391-7398 

7718-7724 

3.08 

3.20 

3.38 

3.S7 

3.86 

3.93 

4.30 

358 

500 

451 

1,410 

1,650 

3,590 

2.420 

26 

37 

14 

41 

38 

lSI 

90 

179 

332 

251 

1,030 

1,380 

1,610 

NA 

13 

2S 

8 

30 

32 

68 

NA 

1.39 

1.34 

3.08 

3.46 

4.32 

2.87 

2.68 

7.0 

0 

0 

9.2 

24.3 

127 

77.4 

94 

0 

0 

306 

1,010 

2,550 

1.920 

187 

204 

211 

216 

223 

225 

234 

Pennsylvanian. 

Pennsylvanian. 

Pennsylvanian. 

Mississippian. 

Mississippian. 

Mississippian. 

Devonian. 

R.G. Jacobs No. 1 

6400.8 

6401.7 

6407.7 

6418.3 

6698.7 

670S.8 

6711.2 

7000.0 

7005.7 

7297.7 

7313.8 

7539.1 

7544.6 

4.60 

4.60 

4.61 

4.61 

5.22 

S.22 

5.23 

5.95 

5.95 

6.80 

6.81 

7.SO 

7.SI 

2,200 

1.400 

1,100 

776 

1,800 

80S 

S48 

200 

483 

1,025 

230 

165 

129 

176 

303 

105 

141 

367 

267 

261 

74 

172 

214 

74 

72 

64 

NA 

1,100 

NA 

588 

NA 

590 

398 

NA 

365 

844 

153 

104 

65 

NA 

239 

NA 

107 

NA 

174 

189 

NA 

130 

176 

49.0 

45.0 

32.5 

1.2S 

0.46 

1.05 

0.55 

0.49 

0.34 

0.21 

0.27 

0.28 

0.48 

0.31 

0.23 

0.20 

NA 

100 

NA 

105 

NA 

85 

43 

NA 

NA 

110 

39 

37 

44 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

254 

254 

2SS 

2SS 

26S 

266 

266 

276 

276 

286 

288 

296 

296 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Early Cretaceous. 

Bertha Rogers No. 1 

83S7-8378 

8442-8470 

8SS8-8723 

5.20 

5.30 

5.70 

306 

3,010 

389 

278 

84 

162 

140 

1,4SO 

252 

145 

60 

134 

reservoirs and increasing amounts of oil are present at shallower depths in many basins. Also, both American Petroleum Institute (API) gravity and gas-oil ratios of oil 

accumulations decrease at shallower depths on the basin 

shelves removed from the deep basin. However, the persistence of C1s+ hydrocarbons to great depths (7 to I 0 km) 

0.11 

3.S9 

0.24 

NA 

NA 

NA 

NA 

NA 

NA 

224 

226 

230 

Mississippian. 

Mississippian to 

Devonian. 

Devonian. 

and extreme maturation ranks (R0 from 5.0 to 7.0 percent) 

in fine-grained rocks in petroleum basins and methane carbon-isotopic compositions in the Anadarko basin both suggest that most deep-basin methane has been generated from 

kerogen during all stages of the C1s+ hydrocarbon generative phase (Price, 1992). The basin zonation of hydrocar-
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 195 

bons probably results from condensation, buoyancy, and 

separation-migration processes. In deep basins, only methane remains in the gas phase owing to high fluid pressures. 

The Cz-C4 hydrocarbon gases are condensed into, and behave as liquids. With continued C1s+ hydrocarbon and 

methane generation from deep-basin sediment, deep-basin 

traps accumulate more and more methane and eventually 

are filled to the spill point with methane. Methane is more 

prevalent at depth because all other fluids (crude oil, condensed Cz-C4 hydrocarbon gases, and water) are displaced 

out of deep-basin traps, by methane, to shallower traps on 

the stable shelves of petroleum basins. This displacement is 

due to Gussow's ( 1954) "Principle of Differentiated Entrapment," which states that buoyancy differences exist between the different fluids in petroleum basins and methane, 

being the most buoyant, is found on top of, and thus displaces, all other fluids in traps. 

Evidence exists that all water may have been flushed 

(displaced) from some deep-basin traps by methane. Both 

carbon dioxide and hydrogen sulfide are found in abundance in some deep-basin gas reservoirs and have existed 

in those reservoirs for tens to hundreds of millions of 

years since emplacement. Because those gases are highly 

soluble in water, their presence dictates that water is not 

in contact with such gas reservoirs. The absence of water 

in some deep-basin gas reservoirs carries implications for 

the deep-basin gas-resource base. There are two important 

implications. First, hydrocarbon thermal cracking reactions will be promoted in these water-free environments. 

Second, when water is introduced into such reservoirs 

during drilling and completion operations, reservoir damage may occur in the area around the well bore from the 

principles of two-phase fluid flow and the Jamin effect 

(discussed below). Such reservoir damage could greatly 

harm localized gas extraction, which could lead to an underestimation of the recoverability and economic viability 

of deep-basin gas-resource bases and the condemnation of 

individual wells. 

The principles of two-phase flow (fig. 16) state that 

where two immiscible fluid phases (here water and gas) 

coexist in the same matrix porosity, both fluids have critical fluid saturation levels that must be exceeded before the 

solid has permeability with respect to either fluid. If the 

concentration of fluid under consideration is less than its 

critical fluid saturation level, the solid will have no perme-

.ability with respect to that fluid, which cannot move 

through the solid. If the concentrations of both fluids exceed their respective critical fluid saturation levels, then 

both fluids can move through the solid. However, their relative permeabilities will be greatly reduced with respect to 

what their permeabilities would be if one fluid were in the 

solid alone (fig. 16). 

When two separate, immiscible fluid phases coexist in 

a rock, and one phase (water) is below its critical fluid 

saturation level, part of the water may be in the form of 

totally immobile spherical globules, which cannot be distorted, and which will occupy a percentage of connecting 

pore throats. This filling of connecting pore throats by 

immobile globules is called the Jamin effect. The globules 

decrease, or reduce to zero (stippled area, fig. 16), the 

permeability of the rock with respect to the other fluid 

phase (gas). Therefore, the introduction of water to a 

water-free, dry-gas, deep-basin reservoir can greatly damage reservoir productivity immediately around the well 

bore, as a result of the Jamin effect. 

Most deep-basin gas accumulations probably originated from methane generation, which accompanies CIS+ 

hydrocarbon generation, combined with condensationbuoyancy-separation-migration processes, which flush all 

fluids, other than methane, from deep-basin traps. However, carbon isotopic values of methane and carbon dioxide 

in some deep-basin gas accumulations indicate that highrank dry-gas accumulations, which originated from C1s+ 

hydrocarbon thermal destruction, do exist. Such accumulations appear to be unusual, however. 

Primary gas migration from the source rock, like 

primary oil migration, is very inefficient (Price, 1992). 

However, primary gas migration is greatly facilitated 

by large-scale faulting (with accompanying large-scale 

~ ;;;;! 

CD <! 

w 

~ 

a: 

w 

0.. 

w 

> 

i= 

:5 

w 

a: 

500 md 

80 

60 

40 

20 

0 

100%GAS 

a: 

wz 

!;;:Q 

~I- ...J<! <!a: u::J -I- I-<{ ccUl 

u 

20 40 60 80 

PERCENT WATER/GAS SATURATION 

20 md 

100 

100% WATER 

Figure 16. Idealized plot of relative permeabilities of gas and 

water. Stippled area is range of gas concentrations (below critical 

gas-saturation level for water) where Jamin effect can reduce or 

destroy relative permeability of rock with respect to water. md, 

millidarcies. 
196 THE FUTURE OF ENERGY GASES 

fracturing). Such faulting disrupts source rocks (and the 

rocks adjacent to them) to allow gas to escape in significant 

volumes. Thus, conventional deep-basin dry-gas accumulations should have a strong correlation to significant deepbasin faults. Evidence suggests that deep basins may be 

largely closed systems with respect to fluid flow. Consequently, much of the natural gas generated in deep basins has 

probably been retained, resulting in larger and higher grade 

deep-basin gas-resource bases than previously estimated. 

MIGRATION OF LARGE VOLUMES OF 

HYDROCARBON AND 

NONHYDROCARBON GASES 

FROM THE DEEP CRUST: 

COMPOSITION, FLUX, AND 

TECTONIC SETTING 

Nonhydrocarbon gases such as carbon dioxide, hydrogen sulfide, and nitrogen, can dilute deep natural gas and 

contribute to the destruction of it (Burruss, 1992). Gas 

compositions in deep reservoirs can be compared to the 

compositions of gases generated in the deep crust. First, 

compositional similarities between the gases in the two 

crustal regimes can be identified. Second, evidence for 

volumetric fluxes of nonhydrocarbon and hydrocarbon 

gases in metamorphic rocks presently exposed at the surface can be used to estimate the potential flux of gases 

from great depths to shallow crustal levels accessible to 

the drill. Third, identification of crustal environments (tectonic and metamorphic terranes) that generate significant 

quantities of gas can be coupled with analysis of basin 

structural style and setting to identify basins where deep 

crustal sources may have contributed to the hydrocarbon 

resource base. 

Analyses of trends in gas composition versus depth and 

reservoir lithology were performed on available gas data in 

the NRG Associates field file for 120 U.S. reservoirs at 

depths of 14,000 feet (about 4,300 m) or greater (NRG 

Associates Inc., 1991 ). When the fraction of total nonhydrocarbon gases is plotted as a function of reservoir temperature (to eliminate significant variations in geothermal 

gradient) two trends became apparent (fig. 17). One trend, 

of gradually increasing nonhydrocarbon gases with depth 

up to about 10 percent, is common to both carbonate and 

sandstone reservoirs from all basins. This trend is due to 

fluid-rock interactions involving organic matter and the dissolution and reprecipitation of carbonate cements. A second 

trend, of rapidly increasing nonhydrocarbon gas with depth 

is present in a small number of reservoirs, all but two of 

which are in carbonate rocks. The second trend is present in 

carbonate reservoirs of the Permian Basin (Ordovician Ellenberger Group) and carbonate and sandstone reservoirs in 

the Jurassic Smackover and Norphlet Formations of the 

Gulf Coast. Although the dominant nonhydrocarbon gases 

in these reservoirs is carbon dioxide, hydrogen sulfide is 

also present (as much as 25 percent). The occurrence of 

high concentrations of nonhydrocarbon gases in carbonate 

reservoirs and the presence of hydrogen sulfide indicate 

that thermochemical sulfate reduction and simultaneous oxidation of hydrocarbons to carbon dioxide may be the dominant control on gas composition in these deep reservoirs. 

Most of the evidence for the composition of fluids in 

the deep crust comes from observations on fluid inclusions 

in metamorphic and igneous rocks. Metasedimentary rocks, 

which contain graphitic carbon and carbonate minerals can 

act as a source of such carbon-bearing gas components as 

methane and carbon dioxide (Burruss, 1992; this volume). 

An additional source of information on fluids in crustal 

rocks is fluid inclusions in quartz veins associated with ore 

bodies. Recent information from ore deposits 'is important 

because it records the flux of fluids from deep to shallower 

levels of the crust and provides a basis for quantitative 

estimates of the flux of gases to shallow crustal levels. 

The trends in nonhydrocarbon content of natural gases 

shown in figure 17 can be extended to deeper crustal levels by including data from fluid inclusions in rocks of 

known depth of burial. Figure 18 shows the data of 

figure 17 together with fluid-inclusion compositions in 

metamorphic rocks from three different terranes. Individual localities may show a significant range in composition, 

but even the highest temperature rocks still contain some 

methane and the compositions tend to lie along the extension of the dominant trend for sedimentary basins. Clearly, 

0.6 

0.5 

c.:l 0.4 (..) 

I 

z 

"iii 

~ 03 

c 

0 

-~ 

U: 0.2 

0.1 

0 

~B 

~= Carbonate Reservoir I 

Sandstone Reservoir I I 

I • v 

I 

l(, • • .... - ~ ~ ~~ 

r ~,.. ~A _ .. J-M _,.. • 

0 20 40 60 80 1 00 120 1 40 1 60 180 200 

Reservoir Temperature, °C 

Figure 17. Fraction of total nonhydrocarbon gases (NHCG), as 

(N2+C02+H2S+He)/(Sum of all gases) versus reservoir temperature for all production data available in the NRG Associates field 

file (NRG Associates, 1991) from depths greater than 14,000 ft 

(4,300 m). Fields separated by sandstone- and carbonate-reservoir lithologies. Lines A and B define general trends in the data 

and are not mathematical fits to the data. 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 197 

the "early burnout" of hydrocarbon gases predicted from 

the trend of rapidly increasing nonhydrocarbon gases, for 

carbonate reservoirs, does not occur in all crustal rocks. 

Work on a siliceous marble that equilibrated at 800°C documents the occurrence of about one mole percent methane 

in carbon dioxide at this temperature-this evidence indicates that methane is stable to great depths in the crust. 

Metamorphic rocks that contain more than about 10 

mole percent methane in fluid inclusions tend to be graphite 

bearing. The compositions of the inclusions are generally 

consistent with calculated compositions of aqueous fluids 

in equilibrium with graphite, especially when the possibility of hydrogen diffusion from inclusions is considered. 

This observation plus the textural evidence for precipitation 

of graphite from fluids clearly documents the generation 

and migration of methane- and carbon dioxide-bearing 

fluids in the deep crust. It also suggests that identification 

of geologic environments where carbon-rich sediments 

have been incorporated into metamorphic rocks will help 

define areas where there is the greatest probability of deep 

crustal gas sources that contribute to shallower natural-gas 

resources. 

Estimates of the flux of gases from the deep crust are 

based on the measured solubility of quartz in water as a 

function of temperature, pressure, and salinity, which can 

be translated into a quantity of quartz precipitated per vol09 

0 8 

0 7 

(9 

';! 0 6 z 

<i 

~ 0 5 

c 

0 

·g 0.4 

u: 

0.3 

0 2 

0 1 

8 

100 200 

6. Carbonate Reservorr 

e Sandstone Reservorr 

D Flurd rnclusrons in 

metamorphrc rocks 

300 400 sao 

Temperature, °C 

A 

600 700 800 

Figure 18. Data from figure 17 plotted over a wider range of 

composition and subsurface temperature for comparison with 

composition of fluid inclusions in metamorphic rocks. Numbered 

boxes define the range of temperature and composition of inclusions from five sample localities. Boxes 1 and 2, anthracite belt 

of the Valley-and-Ridge province, Pennsylvania, United States 

(Kisch and van den Kerkhof, 1991); Boxes 3 and 4, retrograded 

rocks in the granulites of Rogaland, Norway (van den Kerkhof, 

and others, 1991 ); Box 5, prograde granulite rocks of Khtada 

Lake, British Columbia, Canada (Hollister and Burruss, 1976; 

Burruss, 1977). Lines A and B are approximate extensions of 

same lines in figure 17. NHCG, nonhydrocarbon gases. 

ume of water in a vein system at a given depth. From the 

volume of quartz veins that can be measured in the field, 

the volume of water necessary to form the vein system can 

be estimated. The ratio of hydrocarbon and nonhydrocarbon gases to water can be determined from fluid-inclusion 

measurements. Therefore, we can estimate the volume of 

gases transported with the water needed to form quartz 

veins at depth in a given tectonic setting. 

Studies have documented the geochemical processes 

and tectonic setting of the formation of "giant quartz-vein 

systems," which in many cases contain gold (Kerrick and 

Feng, 1992). In one giant vein system, an estimated 

6x1018 g (6xl03 km3) of aqueous fluid deposited about 

6x 1015 g of quartz and, in the process, transported 

3x 1015 g of carbon dioxide. This is equivalent to I ,500 Tcf 

of carbon dioxide. On the basis of the range of methane/ 

carbon dioxide ratios observed in fluid inclusions in quartz 

from one of these giant vein systems (1 :3 to 1 :40), a single vein system may transport from 50 to 500 Tcf of methane to shallow crustal levels. Twelve giant vein systems 

have been documented in the Canadian, European, and 

Australian shields (Kerrick and Feng, 1992). 

Giant quartz-vein systems are an important component 

of any assessment of deep crustal sources of hydrocarbon 

and nonhydrocarbon gases for several reasons. First, quartz 

veins are direct evidence of focused flow of fluids from 

deep to shallow crustal levels. Second, the systems are 

present at convergent plate margins, especially those associated with transpressive tectonic regimes, a geologic environment with large hydrocarbon accumulations. Giant vein 

systems may be the best evidence to support earlier suggestions of natural-gas accumulations in accretionary terranes. On the negative side, convergent, transpressive 

tectonic regimes tend to have a component of vertical tectonism, which can lead to erosional exhumation and loss of 

potential reservoir rocks. 

RESOURCE ASSESSMENT 

METHODOLOGIES FOR DEEP 

NATURAL-GAS ACCUMULATIONS 

Quantitative re~ource assessment methods and models 

of undiscovered deep natural-gas resources can be developed in association with geologic studies of deep sedimentary basins (Dolton and Crovelli, 1992). 

METHODOLOGIES FOR DEEP 

NATURAL-GAS RESOURCES 

Review and analysis of resource appraisal methodologies and approaches allows methods for dealing with deep 

gas accumulations to be identified. These methods are 
I98 THE FUTURE OF ENERGY GASES 

ultimately dependent upon the level of geologic and engineering data available and understanding of the geologic 

model for the specific deep-gas accumulation. One or 

more may be appropriate in a given case, and multiple approaches are desirable as independent checks. The methods, which appear most appropriate to assessment of 

undiscovered resources of deep gas, are (1) deposit simulation, (2) reservoir performance, (3) analog, (4) discovery 

process and finding rate models, (5) mass-balance calculations, and (6) volumetric and areal yield determinations. 

Geologic information in our companion studies indicates that many deep gas accumulations should be treated 

at a play level (Mast and others, I989; Dolton and Crovelli, 1992). Furthermore, they should be analyzed by a method that will provide information on the size of the 

accumulations and their geologic characteristics, as well as 

a total resource value, so that economic and supply studies 

can be made. Several of the methods listed above meet 

these criteria. Where sufficient information is available 

concerning the geologic characteristics of known or possible accumulations of deep gas, a volumetric calculation of 

resources is most appropriate. This method is based on 

measurement of known or estimated physical properties of 

the traps, reservoir rock, and fluids and of the host environment in terms of temperature, pressure, and fluid dynamics. It has the advantage of working with the basic 

geologic properties of the accumulations and dealing with 

them in a rigorous, quantitative mode. The method allows 

for simulation of the hydrocarbon deposit(s) through estimation of properties where data are lacking or incomplete. 

The calculation of gas resources is based on a fundamental reservoir engineering formula, expressed as follows: 

Gas volume (ft3) 

where A 

F 

H 

Por 

Sw 

Pr 

Tr 

Psc 

Tsc 

z 

= 

= 

= 

= 

43,560 A F H Por (I-Sw) 

(Prffr)(l!Z)(Tsc/Psc) 

area of closure (acres), 

trap fill (decimal fraction), 

reservoir thickness (ft), 

porosity (decimal fraction), 

water saturation, 

original reservoir pressure, 

reservoir temperature 

(

0 Rankine), 

pressure, standard conditions, 

temperature (

0 Rankine), and 

gas compressibility factor. 

Simulation of properties of the accumulation or an aggregate of accumulations requires that the parameters be 

represented as estimates expressed as ranges of values, accompanied by probabilities of occurrence (probability distributions). Thus, the parameters represent the natural geologic 

variability of geologic characteristics and our uncertainty 

about them. Hence, the values shown represent the range of 

possibilities, which might be encountered at a randomly 

selected prospect within a population. The model can be 

used both at the scale of a single prospect or for an aggregate 

of prospects within a common geologic setting or play. 

HYPOTHETICAL DEEP BASIN EXAMPLE 

An example of a deep-gas accumulation in a hypothetical basin demonstrates the use of this model. Several U.S. 

basins meet the requirements for the conditions of this 

model such as the Anadarko Basin, the Gulf Coast Basin, 

and several deep Rocky Mountain Basins. This exercise is 

only intended to demonstrate the use and flexibility of this 

model rather than providing an actual assessment of recoverable resources. 

In this case, a population of drillable prospects are 

identified. These prospects have been defined geologically 

or geophysically or are hypothesized to exist, and they 

have common geologic characteristics. The reservoir rock 

is a sandstone lying in structural traps at depths ranging 

from I8,000 to 22,000 feet (about 5,500 to 6,700 m). 

The input used for this example is shown in figure I9. 

In this case, the various play attributes for hydrocarbon 

accumulation (that is, source- and reservoir rock characteristics) have been met, hence no risk has been assigned. If 

questionable, then a probability of occurrence of less than 

1 would be assigned. 

It is possible that prospect attributes may not be present 

or favorable at a randomly selected prospect. For instance, on 

an individual prospect basis or at a randomly selected prospect, the trapping mechanism or trapping configuration has a 

6 in I 0 chance of existing (probability of trapping mechanism=0.6), and the necessary migration paths from source 

rocks to the trap have a 7 in I 0 chance of existing (probability 

of hydrocarbon accumulation=0.7). Each attribute assessed 

is conditioned on the other attributes being favorable and 

also on the basis of being sufficient to meet the minimum 

values for hydrocarbon volume parameters of the accumulations to be considered (shown in lower part of, fig. 19). 

For hydrocarbon volume parameters, the general characteristics and properties of deep-gas accumulations or occurrences, which have been documented elsewhere in the 

companion studies, were used. In this case, minimum values are: area of closure=300 acres; reservoir thickness=IO 

feet (about 3 m); effective porosity=5 percent; trap fill=IO 

percent; and hydrocarbon saturation=60 percent. The program FASPU was used to calculate the estimates (Crovelli 

and Balay, 1990). 

Results from calculation of the modeled play are 

shown in table 7. Several interesting relationships emerge 

from this calculation. First, there is a relatively modest 

amount of gas calculated, given the areal size of the prospect. This result is largely a function of the small amounts 

of effective matrix porosity assumed. Porosity loss is 

viewed as a significant factor in many deep gas reservoirs. 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 199 

PROBABILITY OF FA VORARLE 

ATTRIBUTE OR PRESENT 

~ "' Hy~arbon source I 0 

~ Timin,g 1.0 .0 

·t:: 

~ Migration I 0 

i? Potential reservoir fac1es 1.0 

5::: 

Margmal play probability 10 

uE Trapping mechantsm 06 

"::t Effecttve porosuy (>3%) 1.0 O...o 

cg·s Hydrocarbon accumulal!on 0.7 0:::~ 

Conditional deposit probab1IH 0.42 

Sand X 

Reservoir lithology 

Carbonate 

Ga!> 1 () 

Hydrocarbon type 

~ 0<1 0 

~ Fracule<; " Probabilny of equal to or greate1 than E 

e 

"' Attribute 100 95 75 50 25 5 0 

0.. 

E "Area of closure (1,000 acres) 0.3 04 0.9 1.7 l.O 4.6 62 

::t 

0 Reservoir thickness/ 10 20 35 50 70 100 120 ;. vertical closure (feet) 

d -·· -

0 

~ Effective porosuy (%) 5 52 6 8 10 14 20 

u 

2 Trap fill(%) 10 25 45 60 75 90 - _lllll_ 

""' 

::r: "' Reservoir depth ( l 000 feet) 18 18.75 19 5 20 20 5 21 25 22 

Hydrocarbon saturatiOn(%) 60 65 70 75 Rll 85 90 

Number of drillable prospects 10 12 14 15 17 20 22 (a play charactemtJc) 

Figure 19. Oil and gas appraisal data form (from Dolton and 

Crovelli, 1992) completed for hypothetical deep natural-gas play. 

Reservoir variables as follows: original reservoir pressure is 0.46 

psi/ft (depth in ft)+ 14.7; reservoir temperature (

0

Rankine) is 

0.013°/ft (depth in ft)+515°; gas compressibility factor is 1.2; gas 

recovery factor is 0.80. 

It affects not only the amount of resource but producibility, as a consequence of associated low permeability. In 

many cases, the presence of natural fractures is necessary 

for economic production. In fractured reservoirs, adjustment of reservoir porosity values must be made to include 

fracture porosity for volume calculations. Situations in 

which porosity is retained at great depth, as in some 

geopressured reservoirs, need to be considered in exploration, development, and assessment scenarios. 

Note that in this calculation, independence of volume 

parameters is assumed, other than a positive correlation 

between porosity and gas saturation. However, dependencies may exist and may be dealt with. For instance, one 

might assume that a positive correlation or dependency 

exists between trap size and fill to effectively collapse the 

container size parameters into a single variable; in that 

case the field size possible at the 5th fractile (the largest 

reported field size) increases from about 160 billion cubic 

feet (Bet) to approximately 200 Bcf. This recoverable resource represents a conservative case. 

Alternatively, if the reservoir is considered overpressured, in which better reservoir conditions occur, resources increase significantly. Table 7 (case 2) shows the 

recoverable gas estimated for the improved reservoir conditions. For this case, an average reservoir porosity of 18 

percent and a pressure gradient of 0.75 psi/ft (16.97 

kPa/m-kilopascals/meter) were assumed (clearly an 

overpressured reservoir as is commonly associated with 

deep natural gas accumulations). In the original case (case 

I), the mean resource value in these prospects contained 

298 Bcf. In the second, more optimistic case, the prospects contained I ,017 Bcf of gas, a three-fold increase 

due entirely to the increase in porosity and pressure. 

Other variables which particularly affect the overall reservoir volume include reservoir thickness and size of 

prospects. In both calculations, nonhydrocarbon gas is assumed present. Nonhydrocarbon gas may be accounted 

for by a percentage reduction of the gas calculated as part 

of the input recovery factor. This flexibility of the assessment method allows the geologist to model the geologic 

conditions controlling the resource values to reflect a wide 

range of geologic conditions. · 

CONCLUSIONS 

I. Significant deep reservoirs (reservoirs with greater 

than 6 Bcf of ultimate recoverable gas) occur primarily in 

the Gulf Coast, Permian, Anadarko, Williston, and Rocky 

Mountain Basins. Analysis of drilling, geologic, and production data for significant reservoirs indicate that a complex interplay of geologic and geochemical factors control 

the distribution of deep natural gas in sedimentary basins. 

2. An empirical framework for predicting the porosity 

range of sandstone in Rocky Mountain Basins can be 

broadly applied to deeply buried sandstone in general and 

in the Anadarko Basin. For vitrinite reflectance (R0 ) greater 

than 1.1 percent, the rate of porosity decrease as thermal 

maturity increases is less rapid for Anadarko Basin reservoir and nonreservoir sandstones than for sandstone in general. Sandstone of the central and southern Anadarko Basin 

may retain sufficient porosity for economic accumulations 

of hydrocarbons, even at high thermal maturities. 

3. Pore throats are a controlling factor in the flow of 

fluids through pore networks. They are. typically smaller 

than pores visible in thin section, or apparent in hand 

specimen. Pore throats, especially small ( <0.1 flill) ones, 

common in fine to very fine grained clastic rocks, are very 

sensitive to confining stress, and they probably act as limiting factors controlling the flow of gas to the well bore. 

Small pore throats are also very sensitive to the presence 

of formation fluids, which reduce their effective diameter. 

Measurement of capillary pressure under confining stress 

suggests that constriction of pore throats is the controlling 

mechanism affecting fluid flow at reservoir conditions. 
200 THE FUTURE OF ENERGY GASES 

Table 7. Results of calculation for hypothetical deep natural-gas play. 

[F. fractile~ Bcf, billion cubic feet. Number of accumulations, accumulation size, and unconditional play potential 

based on fractiles. See Dolton and Crovelli (1992) for detailed explanation of methods] 

Case It 

Mean F95 F75 F50 F25 F05 

Number of accumulations------ 6.3 3 5 6 8 10 

Accumulation size (Bcf)-------- 55 8 19 35 66 164 

Uncond. play potential---------- 345 122 207 298 430 726 

Case 2* 

Mean F95 F75 F50 F25 F05 

Number of accumulations------ 6.3 3 5 6 8 10 

Accumulation size (Bcf)-------- 185 27 66 122 226 547 

Uncond. play potential---------- 1169 425 712 1017 1454 2431 

tFor case I: closure, 300 acres; reservoir thickness, 10 ft (about 3 m); effective porosity, 5 

percent; trap fill, 10 percent; water saturation, 60 percent. 

:j:For case 2: closure, 300 acres; reservoir thickness, 10 ft (about 3 m), effective porosity, 18 

percent; trap fill, 10 percent; water saturation, 60 percent; assumed overpressured reservoir with pressure gradient of 0. 75 psi/ft. 

These data aid in defining reservoir properties under insitu conditions, and they are valuable for reservoir descriptions and in simulation studies. 

4. In the Rocky Mountain region, structural partitioning prior to thrusting in selected basins, and sequential 

southeastward and later northeastward partitioning of the 

Rocky Mountain foreland during Late Cretaceous may be 

critical to the entrapment of deep natural-gas resources. 

Economic implications of this new model of deformation 

of the Rocky Mountain foreland include progressive opening and subsequent blockage of migration paths for hydrocarbons generated from source rocks in southeastern 

Idaho, southwestern Montana, Wyoming, Colorado, and 

eastern Utah. 

5. The presence of geochemically identified source 

beds of Middle Proterozoic age, active hydrocarbon seeps, 

and favorable thermal maturities for generating and preserving natural gas, indicate a source-rock potential adequate for economic gas accumulations in many basins and 

regions such as the Midcontinent Rift System and the 

Grand Canyon region. 

6. Methane generation (from thermal decomposition of 

c 15+ hydrocarbons) takes place at very high maturation 

ranks. C15+ hydrocarbons are thermally stable to ranks as 

high as R0 =7.0-8.0 percent in deep, unsheared petroleum 

basins. c2+ hydrocarbons are thermally stable to even 

higher ranks, well into rock metamorphism conditions. 

Methane is probably stable into mantle conditions. The 

vertical stratification of various hydrocarbon phases is 

probably a consequence of condensation, buoyancy, and 

segregation based on geochemical processes. 

7. The presence of significant nonhydrocarbon gases 

in carbonate reservoirs and the presence of hydrogen sulfide indicates that thermochemical sulfate reduction and simultaneous oxidation of hydrocarbons to carbon dioxide 

may be the dominant control on gas composition in these 

reservoirs. 

Giant quartz-vein systems in convergent, transpressive 

plate-margin basins may be associated with major deep 

gas accumulations such as in the deep Anadarko and 

Arkoma Basins. Based on the range of methane to carbon 

dioxide ratios observed in fluid inclusions in quartz from 

one of these vein systems (I :3 to I :40), a single giant vein 

system may transport anywhere from 50 to 500 Tcf of 

methane to shallow crustal levels. 

8. Review and analysis of resource appraisal methodologies and approaches has allowed identification of methodologies for dealing with deep gas accumulations. 

Modeling of assessment methodologies supports the possibility of large volumes of natural-gas resources in deep 

sedimentary basins. Where sufficient information is available concerning the geologic characteristics of known or 

possible accumulations of deep gas, a volumetric calculation of resources is appropriate. 

ACKNOWLEDGMENTS 

We wish to acknowledge the careful and critical reviews of this manuscript by Paul Westcott of Gas Research 

Institute (GRI) and Mahlon Ball, Jerry Clayton, and Michael Lewan of the U.S. Geological Survey. Ronald Charpenti-
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 201 

er and Raymond Obuch retrieved reservoir data from the 

NRG Associates field file and well data from the WHCS for 

quantitative analysis. James Baird and Diane Nielsen of the 

U.S. Geological Survey tabulated production data summaries and prepared graphical output for analysis. Many 

thanks go to Tom Kostick of the U.S. Geological Survey 

for his patience in preparing text figures for the final manuscript. Work was conducted in part under contract to Gas 

Research Institute, Chicago, Illinois (Contract Nos. 5087-

260-1607 and 5090-260-2040) and by the Onshore Oil and 

Gas Program of the U.S. Geological Survey. 

REFERENCES CITED 

Anderson, R.R., ed., 1990, The AMOCO M.G, Eischeid No. I 

deep Petroleum test Carroll County, Iowa preliminary investigations: Energy and Geological Resources Division Geological Survey Bureau, 98 p. 

Bayley, R.W., and Muehlberger, W.R., 1968, Basement rock map 

of the U.S.: U.S. Geological Survey, scale I :2,500,000. 

Blackstone, D.L., Jr., 1983, Laramide compressional tectonics, 

southeastern Wyoming: Contributions to Geology, University of Wyoming, v. 22, p. 1-38. 

---1990, Precambrian basement map of Wyoming-Outcrop 

and structural configuration, revised, 1990: Geological Survey of Wyoming Map Series 27, scale I: I ,000,000. 

Burruss, R.C., 1977, Analysis of fluid inclusions in graphitic metamorphic rocks from Bryant Pond, Maine, and Khtada Lake, 

British Columbia: Thermodynamic basis and geologic interpretation of observed fluid compositions and molar volumes: 

unpublished Ph.D. dissertation, Princeton University, 156 p. 

Burruss, R.C., 1992, Migration of IO's to IOO's of Tcf of hydrocarbon and nonhydrocarbon gases from the deep crust: composition, flux, and tectonic setting. in Dyman, T.S., ed., 

Geologic controls and resource potential of natural gas in 

deep sedimentary basins: U.S. Geological Survey Open-File 

Report 92-524, p. 279-285. 

Crovelli, R.A .. and Balay, R.H., 1990, FASPU English and 

Metric conversion: analytic petroleum resource appraisal microcomputer programs for play analysis using a reservoirengineering model: U.S. Geological Survey Open-File 

Report 90-509B, 23 p. 

Dolton, G.L., and Crovelli, R.A., 1992, Resource assessment 

methodologies and deep gas resources, in Dyman, T.S., ed., 

Geologic controls and resource potential of natural gas in 

deep sedimentary basins: U.S. Geological Survey Open-File 

Report 92-524, p. 286-297. 

Dwights Energy Data, 1985, Petroleum Data System (through 

1985), [Available from Dwights Energy Data Corp., Oklahoma City, OK 73108]. 

Dyman, T.S., Nielsen, D.T., Obuch, R.C., Baird, J .K., and Wise, 

R.A., 1990, Summary of deep oil and gas wells and reservoirs in the U.S. from the Well History Control System and 

Petroleum Data System: U.S. Geological Survey Open-File 

Report 90-305, 35 p. 

Dyman, T.S., ed., 1992, Geologic controls and resource potential of 

natural gas in deep sedimentary basins in the United States: 

U.S. Geological Survey Open-File Report 92-524, 287 p. 

Dyman, T.S., Spencer, C.W., Baird, J., Obuch, R., and Nielsen, 

D., 1992, Geologic characteristics of deep natural gas resources based on data from significant fields and reservoirs, 

in Dyman, T.S., ed., Geologic controls and resource potential of natural gas in deep sedimentary basins in the United 

States: U.S. Geological Survey Open-File Report 92-524, 

287 p. 

Frezon, Sherwood E., Finn, Thomas M., Lister, Jean H., 1983, 

Total thickness of sedimentary rocks in the conterminous 

United States: U.S. Geological Survey Open-File Report 83-

920, scale 1 :5,000,000. 

Glass, G.B., 1975, Analyses and measured sections of 54 Wyoming coal samples (collected in 1974): Geological Survey of 

Wyoming Report of Investigations No. 11, 219 p. 

Glass, G.B., and Roberts, J.T., 1984, Analyses and measured sections of 25 coal samples from the Hanna coal field of southcentral Wyoming (collected between 1975 and 1979): Geological Survey of Wyoming Report of Investigations No. 4, 

104 p. 

Gussow, W.C., 1954, Differential entrapment of oil and gas-A 

fundamental principle: American Association Petroleum Geologists Bulletin, v. 38, p. 816-853. 

Hester, T.C., 1992, Trends in sandstone porosity in the Anadarko 

Basin with respect to thermal maturity, in Dyman, T.S., ed., 

Geologic controls and resource potential of natural gas in 

deep sedimentary basins in the United States: U.S. Geological Survey Open-File Report 92-524, p. 63-75. 

Hollister, L.S., and Burruss,.R.C., 1976, Phase equilibria in fluid 

inclusions from the Khtada Lake metamorphic complex: 

Geochimica et Cosmochimica Acta, v. 40, p. 163-175. 

Kaplan, S.S., and Skeen, R.C., 1985, North-south regional seismic profile of the Hanna Basin, Wyoming, in Gries, R.R., 

and Dyer, R.C., eds., Seismic exploration of the Rocky 

Mountain region: Rocky Mountain Association of Geologists 

and Denver Geophysical Society, p. 219-224. 

Keighin, C.W., 1992, Pore throats, capillary pressures, porosity, 

and permeability of clastic reservoirs in the Uinta, Wind 

Rover, and Anadarko Basins, in Dyman, T.S., ed., Geologic 

controls and resource potential of natural gas in deep 

sedimentary basins in the United States: U.S. Geological 

Survey Open-File Report 92-524, p. 76-85. 

Kerrick, R., and Feng, R., 1992, Archean geodynamics and the 

Abitibi-Pontiac collision: implications for advection of fluids 

at transpressive collisional boundaries and the origin of giant 

quartz vein systems: Earth-Science Reviews, v. 32, p. 33-60. 

Kisch, H.J., and van den Kerkhof, A.M., 1991, CH4-rich inclusions form quartz veins in the Valley-and-Ridge province 

and the anthracite fields of the Pennsylvania Appalachians: 

American Mineralogist, v. 76, p. 230-240. 

Klinkenberg, L.J ., 1941, The permeability of porous media to 

liquids and gases: American Petroleum institute, Drilling and 

Production Practices (1941), p. 200-213. 

MacMillan, L.T., and Weimer, R.J ., 1976, Stratigraphic model, 

Delta Plain Sequence, "J" Sandstone (Lower Cretaceous) 

Turkey Creek area, Jefferson County, Colorado: Colorado 

School of Mines Professional Contr., no. 8, p. 228-241. 

Mast, R.F., Dolton, G.L., Crovelli, R.A., Root, D.H., and Attanasi, E.D., 1989, Estimates of undiscovered conventional oil 

and gas resources in the United States-A part of the Nation's energy endowment: U.S. Geological Survey and Minerals Management Service special publication, 44 p. 
202 THE FUTURE OF ENERGY GASES 

National Petroleum Council, 1992, The potential for natural gas 

in the United States-executive summary: National Petroleum Council, 24 p., with appendixes. 

NRG Associates Inc., 1988, The significant oil and gas fields of 

the United states (through December 31, 1988), [Available 

from Nehring Associates, Inc., P.O. Box 1655, Colorado 

Springs, CO 80901]. 

NRG Associates Inc., 1991, The significant oil and gas fields of 

the United states (through December 31, 1991): Available 

from Nehring Associates, Inc., P.O. Box 1655, Colorado 

Springs, CO 80901. 

Palacas, J.G., 1992, Source-rock potential of Precambrian rocks 

in selected basins of the U.S., in Dyman, T.S., ed., Geologic 

controls and resource potential of natural gas in deep sedimentary basins: U.S. Geological Survey Open-File Report 

92-524, p. 161-172. 

Palacas, J.G., Schmoker, J.W., Daws, T.A., Pawlewicz, M.J., and 

Anderson, R.R., 1990, Petroleum source-rock assessment of 

Middle Proterozoic (Keweenawan) sedimentary rocks, Eischeid No. 1 well, Carroll County, Iowa, in Anderson, R.R., 

ed., The Amoco Eischeid No. 1 deep petroleum test, Carroll 

County, Iowa: Iowa Department of Natural Resources, Special Report Series No. 2, p. 119-134. 

Perry, W.J., Jr., 1989, Structural settings of deep natural gas accumulations in the conterminous United States, in Rice, 

D.D., ed., Distribution of natural gas and reservoir properties in the continental crust of the United States: Gas Research Institute report 89-0188, p. 62-72. 

Perry, W.J -~- Jr., 1992, Deep gas-prone basins of the Rocky 

Mountain region, in Dyman, T.S., ed., Geologic controls 

and resource potential of natural gas in deep sedimentary 

basins: U.S. Geological Survey Open-File Report 92-524, p. 

148-160. 

Perry, W.J., Jr., Nichols, D.J., Dyman, T.S., and Haley, J.C., 

1992, Sequential Laramide deformation of the Rocky 

Mountain foreland of southwestern Montana, Wyoming, and 

north-central Colorado, in Thorman, C.H., ed., Application 

of structural geology to mineral and energy resources of the 

central and western United states: U.S. Geological Survey 

Bulletin 2012, p. Cl-Cl4. 

Petroleum Information Corporation, 1988, Well History Control 

System (through December 1988), [Available from Petroleum Information Corporation, 4100 East Dry Creek Road, 

Littleton, CO 80122]. 

Petroleum Information Corporation, 1991, Well History Control 

System (through December 1991), [Available from Petroleum Information Corporation, 4100 East Dry Creek Road, 

Littleton, CO 80122]. 

Potential Gas Committee, 1990, Potential Supply of natural gas 

in the United States: Potential Gas Committee, Colorado 

School of Mines, Golden, CO, 169 p. 

Price, L.C., 1982, Organic geochemistry of 300°C, 7 km core 

samples, South Texas: Chemical Geology, v. 37, p. 205-

214. 

Price, L.C., 1988, The organic geochemistry (and causes thereof) 

of high-rank rocks from the Ralph Lowe-! and other boreholes: U.S. Geological Survey Open-File Report 91-307. 

Price, L.C., 1992, C15+ hydrocarbon thermal destruction as related to high-rank, deep-basin gas resource bases, in Dyman, 

T.S., ed., Geologic controls and resource potential of natural 

gas in deep sedimentary basins: U.S. Geological Survey 

Open-File Report 92-524, p. 173-278. 

Price, L.C., Clayton, J.L., and Rumen, L.L., 1979, Organic 

geochemistry of a 6.90 kilometer-deep well, Hinds County 

Mississippi: Transactions of the Gulf Coast Geological Society, v. 29, p. 352-370. 

Price, L.C., Clayton, J.L., and Rumen, L.L., 1981, Organic 

geochemistry of the 9.6 km Bertha Rogers No. I, Oklahoma: Journal of Organic Geochemistry, v. 3, p. 59-77. 

Price, L.C., and Clayton, J.L., 1990, Reasons for and significance of deep, high-rank hydrocarbon generation in the 

south Texas Gulf Coast, in Schumaker, D., and Perkins, 

B.F., eds., Gulf Coast oils and gases: Proceedings of the 

Ninth Annual Research Conference Gulf Coast Section 

SEPM, p. 105-137. 

Purcell, W.R., 1949. Capillary-pressures-their measurement 

using mercury and the calculation of permeability therefrom: American Institute of Mining, Metallurgical, and Petroleum Engineers, Petroleum Transactions, v. 186, p. 39-

48. 

Rice, D.D., 1989, Distribution of natural gas and reservoir properties in the continental crust of the U.S.: Gas Research Institute Final Report GRI-89/0188, 132 p. 

Rice, D.D., Schenk, C.J., Schmoker, J.W., Fox, J.E., Clayton, 

J.L., Dyman, T.S., Higley, D.K., Keighin, C.W., Law, B.E., 

and Pollastro, R.M., 1992, Potential for deep gas resources 

in eastern Gulf of Mexico: Proceedings of Natural Gas Research and Development Contractors Review Meeting, 

DOE/METC-92/6125, 1992, p. 151-166. 

Schmoker, J.W., 1992, Distribution of porosity in sedimentary 

rock as a function of time-temperature exposure, in Dyman, 

T.S., ed., Geologic controls and resource potential of natural 

gas in deep sedimentary basins in the United States: U.S. 

Geological Survey Open-File Report 92-524, 296 p. 

Schmoker, J.W., and Gautier, D.L., 1989, Compaction of basin 

sediments: Modeling based on time-temperature history: 

Journal of Geophysical Research, v. 94(B), no. 6, p. 7379-

7386. 

Schmoker, J .S., and Hester, T.C., 1990, Regional trends of sandstone porosity versus vitrinite reflectance-a preliminary 

framework, in Nuccio, V.F., and Barker, C.E., eds., Applications of thermal maturity studies to energy exploration: 

Rocky Mountain Section-SEPM, Denver, p. 53-60. 

Schmoker, J.W., and Palacas, J.G., 1990, Porosity of Precambrian sandstones in the lower portion of the Eischeid No. 1 

well, Carroll County, Iowa, in Anderson, R.R., ed., The 

Amoco Eischeid No. I deep petroleum test, Carroll County, 

Iowa: Iowa Department of Natural Resources, Special Report Series No.2, p. 135-142. 

Takahashi, K.I., and Cunningham, K.I., 1987, Map showing 

wells drilled for oil and gas deeper than 15,000 feet (about 

4,600 m) in the conterminous United States and offshore: 

U.S. Geological Survey Oil and Gas Investigations Map 

OM-220, scale I :5,000,000. 
GEOLOGIC STUDIES OF DEEP NATURAL-GAS RESOURCES IN THE UNITED STATES 203 

van den Kerkhof, A.M., Touret, J.L.R., Maijer, C., and Jansen, 

J.B.H., 1991, Retrograde methane-dominated fluid inclusions from high-temperature granulites of Rogaland, southwestern Norway, Geochimica et Cosrpochimica Acta, v. 55, 

p. 2533-2544. 

Vidal, G., and Ford, T.D., 1985, Microbiotas from the Late 

Proterozoic Chuar Group (northern Arizona) and Uinta 

Mountain Group (Utah) and their chronostratigraphic implications: Precambrian Research, v. 28, p. 349-389. 

Wandrey, C.J., Vaughan, D.K., 1992, Maps illustrating the distribution of deep wells in the U.S. by geologic age, in Dyman, 

T.S., ed., Geologic controls and resource potential of natural 

gas in deep sedimentary basins: U.S. Geological Survey 

Open-File Report 92-524, p. 114-116, 9 plates. 

Woods, T.J., 1991, The long-term trends in U.S. gas supply and 

prices-1991 edition of the GRI baseline projection of U.S. 

energy supply and demand to 2010: Gas Research Institute, 

Washington, D.C., 54 p. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Challenges of Ultradeep Drilling 

By Richard E. Wyman 1 

CONTENTS 

Abstract .. .. . . . .. .. . . .. . ... .. ... . .. . .. .. .. .. ... . ... ...... .... .. .. . . . .... .. .. . . .. . 205 

Introduction ................................................................... 206 

Geology ......................................................................... 207 

Recommended Research Strategy ....... .................. 207 

Geophysics .................................................................... 208 

Reservoir Delineation ............................................ 208 

Seismic Attributes of Reflectivity and 

Electromagnetics . ..... .. . . .. ... . .. ... ... . . . ... . . . . .. . . .. .. .. . . .. .. . . 208 

Processes .. . .. .. ... ... ... . . . . . .. . .. . . .. .. . ... .. .. .. .. .. .. .. .. .. .. . .... .. . 209 

Geochemistry ................................................................ 209 

Source Requirements for Methane ........................ 209 

Geochemical Constraints on Methane 

Preservation ............................................................ 210 

Thermodynamics ............................................. 210 

Kinetics ......... ...... .. .. ... ...... .. . .. ......... .... ...... ...... .. 21 0 

Solubility ......................................................... 210 

Engineering . ... . .. .. .. . . .. .. .... .. . ... .. .. .. . .. ... . . . .... . . . .. . . .. .. .. .. .. .. .. 210 

Rock Mechanics .. ..... ...... .. .. .. .. .... .. ...... ............ ...... .. 210 

Drilling ................................................................... 211 

Formation Evaluation ............................................ 211 

Well Completions .................................................. 211 

Economics .. .. .. .. . . . . ......... ... . .. ... . . . ... . .. ... .. .... .. . . .. .. .. .. . . . .. . .. . 212 

Feasibility Study Estimated Costs ......................... 212 

Field-Based Research ............................................ 212 

Reserve Requirements .......................................... . 

Summary ..................................................................... .. 

Acknowledgments ....................................................... . 

References Cited .......................................................... . 

213 

214 

214 

215 

1

Canadian Hunter Exploration Ltd., 2000 605-5 Ave. S.W., Calgary, 

Alberta, Canada T2P3H5. 

ABSTRACT 

To successfully produce ultradeep gas (below 25,000 

ft), advances will be needed in geoscience and engineering. 

Combined thinking from experts in geology, geophysics, 

geochemistry, and engineering has outlined some of the 

challenges. Geologists will require assistance from geophysicists to identify the spatial distribution of sedimentary 

rocks. They will need to interpret the structural and tectonic 

framework and fit them into an integrated geological 

model. 

Characterization of potential reservoirs including 

knowledge of the preservation or creation of porosity will 

be vital. Although seismic methods have the highest resolving power for delineating structure at depth and indicating other rock properties, other geophysical methods 

should also be utilized for additional information on deep 

sediments. A better understanding of the source requirements and chemical reactions for generation of methane is 

required. 

Methane can survive at high temperatures and high 

pressures associated with depths of 40,000 ft in an inert 

dry reservoir, but the stability of methane in the presence 

of complex mixtures of minerals and other fluids is uncertain. Further experimental studies and theoretical work 

are needed to understand the constraints on methane 

preservation. 

Severe problems will be encountered in drilling, evaluation, and completion of ultradeep wells. Engineering 

challenges will come from higher in-place stresses, temperatures, pressures, and the probability of encountering 

corrosive and toxic fluids. Drill strings, casing, and other 

tubular materials used in the drilling and well completion 

process will need advanced metallurgy to reach and complete wells in deep targets. The economic returns at $3.00 

per Mcf can be attractive if 200 ft of gas within a 7 percent porosity reservoir can be successfully completed at 

205 
206 THE FUTURE OF ENERGY GASES 

30,000 to 40,000 ft. This assumes good productivity and 

draining gas reserves of 125 Bcf from a single well. 

INTRODUCTION 

The potential for natural gas production from ultradeep sources (below 25,000 ft), although unknown, is 

probably very large. However, ultradeep sources are only 

one of many possible sources from which future gas may 

be produced. Such potential can be depicted with a resource triangle (fig. 1 ), where the least expensive and easiest-to-obtain gas is indicated at the top of the triangle. 

These sources, however, are relatively small. To tap the 

larger volumes of gas shown lower in the resource triangle, greater expense and advanced technology are required. Practically all of the gas that has been produced to 

date as well as the remaining recoverable resources from 

"conventional" rock (shallower than 25,000 ft) are shown 

at the top of the triangle. Beneath that is an almost unlimited amount of natural gas from "unconventional" sources. 

Natural gas is currently being produced from some of 

these unconventional sources, particularly from tight formations, shales, and coal seams. The United States in particular has done extensive evaluation of unconventional 

sources of gas. Although the quantity of deep gas in place 

is probably large, it has received relatively little attention 

~II 

I 

LIQUIDS GASIFICATION 

COAL SEAMS 

WASTES 

COAL GASIFICATION 

PEAT 

AQUIFERS 

ULTRAOEEP 

HYDRATES 

BIOMASS ( Renewable source of methane ) 

Figure 1. Resource triangle for natural gas. Volume of resources 

available increases toward base of triangle. Arrows at base indicate a virtually unlimited source of methane from renewable 

biomass. 

because of the difficult technical problems and anticipated 

high drilling costs. Deep-gas potential needs serious investigation, when considering the economic and national security of the energy resources in the United States. 

Sedimentary deposits are believed to exist to at least 

50,000 ft depth in some areas of the United States. Research to date indicates that methane would remain stable 

under expected environmental conditions at depths of at 

least 40,000 ft and probably beyond (see Dyman and others, this volume). The temperatures at this depth, in excess 

of 600°F, suggest that any oil will already have been broken down to methane. At depths below 25,000 ft, limitations to drilling equipment, evaluation tools, tubulars (for 

example, borehole casing, production tubing, or liners), 

and safety devices become severe. The problems of production are compounded by high temperatures and the 

probability of encountering hydrogen sulfide, carbon dioxide, hydrogen, and corrosive salt-saturated fluids. 

The overall success ratio for wells drilled deeper than 

15,000 ft in the United States and around the world is 

close to 50 percent (Moore, 1992). Although the United 

States has more wells and a higher density of drilling than 

any country in the world, only a small fraction of the deep 

sedimentary deposits have been explored with a drill bit. 

Yet huge natural gas resources have already been identified. For example, the deep Anadarko Basin alone may 

contain between 60 and 360 trillion cubic feet (Tcf). The 

Tuscalousa trend in the Gulf Coast has been estimated to 

contain 60 Tcf; another 200 Tcf may be in the deep Rocky 

Mountain Overthrust Belt. Although these resources, generally located between 15,000 and 25,000 ft, do not meet 

the ultradeep classification (below 25,000 ft), the implication is that there are large sources of ultradeep gas. 

Further research is needed to better understand the 

role of organic matter in producing very large amounts of 

gas at great depths. Additional interest in deep-gas potential has been sparked by theories of inorganic sources of 

gas. The key to successful ultradeep drilling is finding 

rocks with the necessary porosity and permeability that 

can act as reservoirs and will allow economically feasible 

production rates (see Burruss, this volume; Apps and van 

de Kamp, this volume; and Gold, this volume). 

Intensive investigations and research in geology, geophysics, geochemistry, and engineering are very important 

to deep drilling programs and cannot be overemphasized. 

Specific areas of investigation suggested by a panel of industry, academic, and government experts are outlined in 

this report (see "Acknowledgments"). When the basic technical problems have been solved, the creation of a sustained 

deep-drilling program will depend largely on economics. 

By far the largest factor in ultradeep exploration and 

production activity will be high drilling costs; new technology to reduce these costs will be of primary importance. The investigations necessary to conquer the 

challenges of deep drilling will also have profound ef-
CHALLENGES OF ULTRADEEP DRILLING 207 

fects on the more conventional oil and gas exploration 

and production programs. 

Over the past decade many ultradeep wells have been 

drilled for scientific investigation. Although scientific ultradeep wells do not share the same potential hazards of 

oil and gas wells, many of the drilling technologies developed in this program would directly benefit scientific drilling programs. 

GEOLOGY 

There is relatively little understanding of the distribution and geologic characteristics of deep gas-bearing rock 

packages. Potential occurrences range from unconventional settings, such as subduction zones, to the deeper 

portions of mature hydrocarbon basins (fig. 2). Implicit in 

this concept is the assumption that the gas is organic rather than inorganic in origin (see Stevenson, this volume). 

Available databases can be used to prepare maps that 

identify and show the distribution of these rock packages. 

Conceptual models can be developed that characterize the 

geologic history and habitat of deep gas accumulations. 

From these models, the hydrocarbon potential of the 

identified rock packages can be assessed. However, testing of these models will ultimately require deep drilling 

operations. 

Western 

Overthrust Belt 

RECOMMENDED RESEARCH STRATEGY 

1. Identify the spatial distribution of packages of sedimentary rocks using available data including seismic 

reflection, magnetotellurics, potential fields (gravity and 

magnetics), and extrapolation of borehole petrophysical 

and geological data. 

2. Undertake preliminary geohistorical analysis of all 

identified rock packages. On the basis of the above geophysical data and known geologic relations from appropriate regional data, the structure and tectonic framework can 

be developed, .which will provide a basis for interpreting 

the stratigraphic and sedimentological character of deep 

rock packages. 

3. Using the above geohistorical analysis, integrated 

geologic models can be constructed for determining hydrocarbon potential based on kinetic estimates of hydrocarbon generation potential. These integrated geologic 

models should include an assessment of the source beds, 

maturation and thermal history, and a characterization of 

potential reservoirs. Preservation of porosity is essential to 

maintaining high reservoir potential. Therefore, understanding of the interrelationships of porosity, permeability, 

fluid pressures, diagenesis, burial mechanisms, and subsequent tectonic activity is vital. 

4. Additional data acquisition will be required for sitespecific recommendations to test the geologic models. Our 

,... 

Cordilleran 

Subduction 

Margin 

I' 

I I - -, --

Great 

Valley 

Basin 

Ventura 

Basin 

I 

r- - - -1. 

' ' 

' l 

I 

' I 

I I 

L _____ l 

I ', 

- - -, Wind , l \. \ 

~River __ ;- - -- - ·- __ 

:Basin ·-, .' - - ...l I ~ 

~·Green 

River 

Basin 

Delaware 

Val Verde 

Basins 

I 'r --- .r 

r--~---'\ ' I 

I 

I 

;--L- -<,----;~ ----'/!.. - - -. I I 1 ---; I 

I I l I I 

I .... """' '' .,.._ ..... ~ I 1 ' 

L. .... - _( I "\ 

I Anadarko 1 ,' ' ~. 

Basin 'I I--, ' - - -

Louisiana 

Offshore 

Figure 2. Potential deep-gas locations in United States. 

,_ Baltimore 

Canyon 

Trough 
208 THE FUTURE OF ENERGY GASES 

current knowledge is limited by our inability to project 

reservoir characteristics to depths below 25,000 ft. A detailed seismic-data acquisition program, including 3-dimensional data, will be important to define the parameter 

of any prospect. 

GEOPHYSICS 

RESERVOIR DELINEATION 

There are certain geological frameworks that are 

tho.ught to be preferable in the search for deep gas. To 

delineate the best "prospects," it is necessary that reconnaissance work be done using geophysical techniques. The 

use of all geophysical methods is desirable, but the selection of methods would depend upon local conditions. 

The seismic reflection method has the highest resolving power for delineating structures at depth and indicating other physical properties of the rock mass. Further, 

under certain conditions we can expect to delineate the 

physical properties of the rocks, which can in turn be used 

to infer the existence of porosity and the presence of natural gas in pores. The electrical resistivity of deep sedimentary rocks is a key parameter used to infer the existence of 

gas (in the absence of drilling); for assessing the total volume of sedimentary rocks below a depth of 25,000 ft, this 

measurement must be relied upon to delineate deep sedimentary-rock packages where they have not been drilled. 

Magnetotelluric (MT) sounding surveys are essential for 

deep-gas studies in frontier regions, especially those where 

volcanic rocks or other conditions limit the effectiveness 

of seismic surveying. Specific research items recommended are MT surveys along existing deep reflection transects 

to verify existence of postulated deep sedimentary rocks 

and their possible fluid/temperature environment. Laboratory study of resistivities and other parameters of sedimentary rocks at high pressure is also an essential research 

item. Other geophysical methods such as gravity and mag- · 

netic techniques can be used to furnish additional input in 

defining sedimentary systems and aid in planning for deep 

seismic and MT surveys. 

SEISMIC ATTRIBUTES OF REFLECTIVITY AND 

ELECTROMAGNETICS 

After locating deep sediment packages, it is necessary 

to outline specific horizons of high porosity charged with 

gas. It would also be useful to estimate the hydraulic permeability in such packages prior to drilling. The most 

informative method, short of drilling, to infer these properties is to use geophysical data. In order to use these data 

(for example, seismic-impedance and seismic-amplitude 

information and electromagnetic impedance) it is necessary to understand how geophysical properties are influenced by porosity, pore pressure, gas saturation, fractures, 

and overburden pressure. In general, lower temperature 

gradients and younger rocks are more favorable to porosity preservation (see fig. 3). However, any gradient can 

abruptly shift toward higher porosity, especially if hydrocarbons were trapped from earlier migration; this would 

be expected with geopressured oil or gas. 

Research is needed to better relate reservoir rock 

properties to parameters measured geophysically (for example, seismic velocities and electrical resistivity). This 

research must include laboratory measurements of rock 

properties utilizing the in-place conditions (for example, 

temperature and pressure) that prevail in deep gas environments. Rock property variables that affect geophysical 

measurements include mineralogy, porosity, fluid content, 

pore pressure, and temperature. In potential source rocks, 

carbon content, maturation, and other chemical components become important. Modern basin-modeling programs should assist in the studies of variables. In addition, 

studies will be needed to calibrate in-place geophysical 

0 

2 

3 

0 

0 

0 4 

X 

i=' 5 lL 

I 

fa.. 6 LlJ 

0 

7 

MACKENZIE 

DELTA 

TERTIARY AND 

Acoustic Velocity Increases 

(Porosity Decreases) 

ALBERTA 

DEEP BASIN CRETACEOUS TO 

Figure 3. Trend curves of sand porosity in different geological 

provinces. Indicated trends are from water-bearing sands. Generally, younger formations will have higher porosity at a given 

depth. 
CHALLENGES OF ULTRADEEP DRILLING 209 

measurements to reservoir characteristics. Field measurements should utilize two new developments in reservoir 

seismology: (1) the use of drilling bits as a seismic source 

for doing wide-angle, continuous vertical seismic profiling 

of the rock mass around and beneath the borehole during 

drilling, and (2) the use of powerful downhole seismic 

sources and many surface receivers to describe the rock 

mass in the vicinity of the borehole after drilling has been 

completed. 

PROCESSES 

Important constraints on the presence and quality of 

natural gas reservoirs at great depth can also be obtained 

from better understanding of the processes that affect gas 

reservoirs. These include the inelastic reduction of porosity over time, development of pore pressure and naturally 

induced fracturing, reduction of permeability, and the maturation or migration of hydrocarbons under extreme pressure and temperature conditions. 

Laboratory investigations are needed to better understand processes that cause porosity reduction over time 

and temperature and stress effects on porous rocks with 

reactive pore fluids. The results from these investigations 

can be compared with exhumed rock masses that are 

analogous or representative of deep sedimentary-rock 

packages. Engineers require data on the compressibility of 

reservoir rocks and fluids at high pressures and temperatures, on the solubilities of the relevant rock-forming minerals, and on the pore fluids that may exist in deep gas 

reservoirs (see Hefner, this volume). 

Presently, even with observations from drill cores, we 

can only predict the behavior of some monomineralic 

rocks under different pressure, temperature, time conditions that are macroscopically unfractured, in limited 

stress states, and in chemically inert environments. The 

current needs, therefore, are to (1) extend our knowledge 

of the mechanical behavior of some rocks at depth to other 

rock types, both fractured and unfractured, and to other 

environmental conditions, (2) relate this mechanical behavior to composition, texture, and fabric, and (3) develop 

the geophysical technology to deduce rock composition, 

texture, and fabric so as to predict mechanical behavior. 

Specifically, the above investigations need to be undertaken to extend our knowledge of inelastic properties to 

polymineralic partially clay-bearing rocks at high temperatures and pressures. These polymineralic rocks constitute 

about 40 percent of sedimentary rocks, and understanding 

their roles is critical in modeling the geologic deformation 

and mechanical characteristics of deep sedimentary-rock 

packages. The influence of chemically active fluids on 

deep sedimentary-rock packages requires laboratory study, 

as these effects may dominate other conditions. The timedependent behavior of chemical changes and compressibility at the expected temperatures and pressures is still unknown. Additionally, the effects of existing fractures on 

the mechanical response of the rock mass remains largely 

undefined. Further theoretical and experimental studies 

will be needed to understand the geophysical responses of 

sedimentary-rock packages to deep burial. 

GEOCHEMISTRY 

In general, the basic geological and geochemical principles involved in the creation of natural gas (mainly 

methane) are known. In the near surface environment, 

methane forms as a result of biological processes in which 

anaerobic microbes digest organic molecules. Bacterially 

generated methane has been recognized in shallow reservoirs as old as the Cretaceous, and, in fact, 20 percent of 

the known methane deposits are believed to be of bacterial 

origin (see Rice, this volume). 

As sediment burial depth increases, temperature and 

pressure increase. Methane forms under these conditions 

by processes involving the thermal alteration of organic 

matter in sediments (Barker, 1990). This generation process results because organic matter is thermodynamically 

unstable under the pressure and temperature conditions of 

the subsurface environment. Some organic matter survives 

deep burial only because the reactions that convert it to 

methane are very slow. Such reactions will leave behind 

an organic residue. As temperatures increase, however, the 

reactions proceed more quickly, approximately doubling 

for every 10°C increment. The kinetically controlled reactions tend toward them1odynamically stable end products 

of methane and graphite. During this alteration process, 

some kinds of organic matter are converted to oil, which 

is later transformed to methane during deeper burial, 

whereas other organic matter in the form of kerogen is 

changed, in part, to methane. 

In deep reservoirs (greater than 25,000 ft), most of the 

methane should result from the high temperature alteration of kerogen and, possibly, hydrolysis of graphite 

(2C+2H20-+CH4+C02). Methane from the thermal alteration of oil may also be present in deep reservoirs; however, it would represent an inherited product from the 

reservoir's burial history. Indeed, biologically derived 

methane also may survive in deep reservoirs, but the 

amount of methane would undoubtedly be small because 

most of this methane would be lost during the deep burial 

process. To date, no deep gas has been found that has an 

unequivocal isotopic signature of biogenic gas. 

SOURCE REQUIREMENTS FOR METHANE 

Although the origin of methane in most natural 

gas deposits seems to be understood, the limits to the 
210 THE FUTURE OF ENERGY GASES 

chemical reactions that are taking place in the unique 

pressure-temperature regime found in sedimentary rock 

packages at depths greater than 25,000 ft have not been 

clearly defined or quantified. For example, it is not clear 

how much organic matter must initially enter the system 

in order for significant methane to result after deep burial. 

Perhaps low-grade organic deposits, such as pelagic sediments and carbonates, may not contain enough organic 

matter to serve as a source of gas at greater depths. Highgrade organic deposits such as oil shales and coals may 

be necessary; however, intermediate-grade organic deposits could also be sufficient. It has been shown that 3,000 

to 4,000 ft3 of natural gas can be produced from one barrel of oil (Barker, 1990). Thus, it is important to define 

what initial concentration of organic matter is necessary 

to create methane at great depths. 

Besides defining the characteristics of source materials for methane formation by thermal processes, stu.dies 

should also be directed toward understanding the chemical 

reactions that are transforming organic matter to methane 

at subsurface conditions found at depths greater than 

25,000 ft The discussion thus far has been concerned with 

methane derived from the alteration of organic matter. It 

should also be mentioned that methane originating from 

inorganic sources, such as the mantle, could occur in deep 

reservoirs (see Gold, this volume). 

GEOCHEMICAL CONSTRAINTS ON 

METHANE PRESERVATION 

Previous evaluations of the stability of natural gas in 

the deep subsurface have considered simple systems involving pure methane. Methane alone in an inert dry reservoir can survive very high temperatures and pressures. For 

example even at 40,000 ft more than 99 percent of the 

methane survives (Dyman and others, this volume). However, the stability of pure methane is not of great practical 

interest, because gas reservoirs generally contain reactive 

substances such as water and mineral phases. In order to 

understand what really happens in nature, it is important to 

investigate in greater detail the chemical reactions affecting methane and the fate of methane through solubility, 

mass transport, and diffusion. Research toward this goal is 

progressing (Takach and others, 1987). 

THERMODYNAMICS 

Any attempt to predict the stability of methane in the 

deep crust must consider the associated mineral assemblages. Thermodynamic data for gas species and minerals 

are needed to quantify the stability of methane in the lithosphere. Little is known about the thermodynamic properties of fluids at subsurface conditions below 25,000 ft. 

With the present state of knowledge it is not possible to 

extrapolate what is currently known to higher temperatures 

and pressures. It is expected that higher temperatures rather than higher pressures will have the greatest effect upon 

gas compositions (Hefner and others, 1973). Thus, detailed 

experimental studies are called for which will focus on gas 

mixtures at appropriate conditions where deviation from 

the ideal state is greatest. 

KINETICS 

The rates of reactions, such as CH4+2H20=C02+4H2 

are another important aspect of methane stability. Prelimi~ 

nary data suggest that methane is quite unreactive in laboratory experiments below 500°C. However, rate laws, rate 

constants, energies, and catalytic effects on the kinetics of 

methane are unknown, and experimental work is needed to 

clarify these issues. 

SOLUBILITY 

The ability of methane to dissolve in brines is poorly 

understood, particularly at the extremes of salinities, temperatures, and pressures encountered at depths below 

25,000 ft. Previous studies of methane solubility in NaC1 

brine at conditions up to 25,000 psi and 400°F are in good 

agreement. Further experimental work on this problem is 

required at higher pressures and temperatures, as well as 

for other salts and gases (especially C02). 

ENGINEERING 

Engineering problems to be expected in drilling, 

evaluation, and production of deep gas will result from 

( 1) higher in-place stresses, (2) higher formation temperatures, (3) the increased chances of encountering highpressure/high-temperature hydrogen,' carbon dioxidtr, 

hydrogen sulphide, and corrosive fluids, and (4) longei- ·. 

lengths of drill string, subjected to high temperatures and 

pressures. 

ROCK MECHANICS 

At high pressure and high temperature, rock 'behavior 

can transform from brittle to ductile. High lithostatic stress 

states in a formation are translated to high shear stresses 

with removal of rock at the well bore during drilling and 

the fracturing process. Furthermore, the change of stress 

can result in creep, which can be further compounded by 

rock/fluid interaction with muds, fracturing fluids, and 

completion fluids. Borehole failure and creep at the bore-
CHALLENGES OF ULTRADEEP DRILLING 211 

hole wall can result in complications, such as sticking of 

the drill string or hole collapse, with the accompanying 

possibility of "drill-string twist off." 

Formation evaluation, completion, and production can 

be impaired by pore collapse, perforation collapse or plugging, and even casing collapse as pore pressure is reduced 

and the rock is subjected to higher effective confining 

stress. 

If stimulation such as hydraulic fracturing is attempted 

at great depths, severe complications could occur. These 

may include failure of tubulars, difficulty of propagating 

the fracture owing to the high formation stresses, and 

complications owing to rock/fluid interaction. 

Laboratory rock-mechanics research is required to 

evaluate some of these potential problems. Rock-mechanics facilities capable of duplicating confining pressures to 

50,000 psi, controlled pore pressures to approximately 

50,000 psi, and temperatures to 600°F (350°C) are recommended to investigate creep and stress-strain failure. The 

effect of fluid/rock interaction on the mechanical response 

can be evaluated by including the fluid of interest as pore 

fluid. Pore volume changes, permeability, and fracture 

propagation at these high pressure/temperature states are 

not well understood and need to be investigated. 

DRILLING 

Drilling at great depths will be challenging because 

of the hostile environment. At great depth, rocks may 

change from brittle to ductile; if rocks become too ductile, they can profoundly affect drilling penetration rates. 

One approach to mitigate this problem would be to develop drilling muds that not only withstand the high temperature/pressure but could change the surface physics of 

the rock being drilled while maintaining borehole stability. This would maintain brittle behavior during drilling. 

With increased depth, transferring of torque to the drill 

bit by use of downhole motors may be necessary to 

avoid the problems of friction that would be caused by 

rotating long drill strings. Drill bits, downhole motors, 

and drill strings need to be developed to operate at high 

temperatures in the presence of hydrogen gas or corrosive fluids. Drilling materials exhibiting high strength, 

high hardness, high fracture resistance, and appropriate 

ductility at high temperatures, along with resistance to 

corrosion and embrittlement in the presence of hydrogen 

gas and corrosive fluids must be substituted for the standard materials used by the gas industry; however, the 

combination of these properties are often mutually exclusive (for example, high hardness and high fracture toughness). Creating this combination of properties may 

require basic metallurgical research. If possible, the materials selected should be fabricated by techniques presently in use by the industry to control the costs of the final 

components. Prototype components need to be tested in 

the laboratory under simulated field conditions. 

FORMATION EVALUATION 

Most current technologies for formation evaluation 

from the borehole are limited to depths of less than 20,000 

ft because of the high temperatures at these depths. These 

temperatures affect the ( 1) operation of electronic components essential to most wireline logging tools, and (2) elastomers essential to proper operation of packers, core 

barrels, and downhole reservoir sampling. 

Some of the needed research is in progress as a part of 

other energy programs. For example, geothermal-reservoir 

evaluation problems are bringing about substantial advances in high-temperature electronics and elastomers; however, the tools are not being packaged for the high pressures 

associated with ultradeep drilling. 

Laboratory research on sedimentary rocks under high 

pressure/temperature conditions is needed to address (1) 

methods to measure in-place stress, (2) the relationship between dynamic elastic properties deduced from sonic data 

and the static properties needed for well completion engineering, (3) the relationship between sonic, electrical properties, and nuclear log responses to reservoir properties 

(porosity, permeability, and fluid saturations), and (4) calibration' of borehole measurements with remote geophysical measurements. 

Research on field evaluation of deep-gas reservoirs is 

also essential. The stress, complex fluid interactions, and 

temperature cycling that are difficult to simulate in laboratory analysis of rock samples inevitably leave doubts 

regarding the applicability of lab results. Also, lab samples 

are minuscule and do not reflect the significant dimensions 

of reservoir heterogeneity. These problems are compounded 

in the drill stem by uncertainties with logging tool response. 

Other hardware development topics include ( 1) core and 

fluid sample collection hardware, including pressure core 

barrels, sidewall samples, and fluid sampling devices; (2) 

perfecting vertical seismic profiling in which the drill bit 

provides the acoustic source for a large array of surface 

receivers (looking up to 100ft ahead of the bit is particularly 

important to anticipate potential reservoirs, high pressures, 

and changes in lithology or pore fluids); and (3) measurement while drilling, with emphasis on the depth and 

temperature/pressure requirements for deep-gas exploration. 

WELL COMPLETIONS 

In general, the technology available to explore for gas 

and drill wells deeper than 25,000 ft is more advanced 

than the technology required to complete, stimulate, and 

produce the gas: 
212 THE FUTURE OF ENERGY GASES 

I. Current limits: Temperature is usually the limiting 

factor to our technology. For example, the following items 

have been identified at critical barriers: (1) fracture fluid 

stability (350°F), (2) fracture proppants (30,000 ft), (3) 

pumping pressures (20,000 psi), (4) perforating systems 

(400-500°F), and (5) cementing (1,000°F). When necessary, the gas industry can extend present technology to 

complete wells down to ±25,000 ft; however, such systems are very expensive, risky, and unreliable as the bottom-hole temperature approaches 400°F. 

2. Technology needs: To make significant progress in 

well completion technology, we must improve the reliability of our systems at high temperature and pressure, as 

well as significantly reducing the costs of these systems. 

Specific research needs for deep-well completions are 

as follows: 

1. Fracture fluids: Completely new polymer (or other) 

systems need to be developed that will be stable at high 

temperatures (+600°F) for long time periods (4-6 hours). 

In addition, research is needed to reduce the friction created by pumping these viscous fluids down long tubular 

strings and into the fractures. 

2. Fracture stimulation: Most deep wells will require 

fracture stimulation to maximize deliverability. Substantial improvement in fracturing technology is considered a 

high-priority item if one plans to economically produce 

deep gas. 

3. Rock mechanics: Research will be required to better 

understand rock failure during hydraulic fracturing, calculation of fracture dimensions, perforation stability, borehole stability during production, and bulk compressibility 

of the formation and fluids to improve our ability to predict long-term production performance. 

4. Metallurgy: Research is needed to improve downhole equipment, such as tubular materials to withstand 

higher burst and collapse pressures (given limits on size 

and density), tubular goods that are more corrosion resistant, and better downhole tools and packers (to include 

sealing elements). 

5. Miscellaneous: Several other research items have 

been identified that should be addressed are perforating 

systems, corrosion inhibition, scaling inhibition, and sealing elements for packers. 

ECONOMICS 

In an effort to determine the feasibility of exploring 

for deep gas, a rough approximation of costs and required 

reservoir characteristics are outlined. Because of the sizable costs, a feasibility study would probably have to be 

funded by a consortium of companies or by a government 

interested in defining deep-gas potential. We have divided 

our proposed research into two phases-(1) an initial feasibility study and (2) field-based research. 

FEASIBILITY STUDY ESTIMATED COSTS 

The following table summarizes the estimated costs of 

conducting an initial feasibility study: 

Fea<ibility study topics 

(I) Geology: 

Identify rock packages-----------------------------------

Str-atigraphic analysis (4 areas) (review and 

extrapolation of existing data plus allowance 

for sampling and analysis of additional rocks 

from outcrops or borehole data)--------------------

Review existing know ledge of reservoir character 

(for example, porosity and permeability) with 

pertinent variables (for example, depth, 

geological timing of burial, temperature, and 

pressure) and draw conclusions and make best 

estimates of extrapolations to ultra-deep 

sed ime n t s -----------------------------------------------

Integrated geological, geochemical, and 

Cost($) 

200,000 

2,000,000 

500,000 

geophysical models----------------------------------- 500,000 

Subtotal ---------------------------------------------- ---,3",2"'00","000"" 

(2) Geochemistry: 

Source rock requirements -------------------------------

Geochemical constraints on methane in presence 

500,000 

of other gases and expected minerals-------------- 600,000 

Occurrence (theoretical and laboratory studies) ----- 2,500,000 

Subtotal ---------------------------------------------- ---,3',6'""00",""000""' 

(3) Geophysics: 

Summary of current technology------------------------

Laboratory work (such as acoustical 

measurements of rock samples under in place 

200,000 

conditions) --------------------------------------------- 1,000, 000 

Reprocess existing data---------------------------------- 1,000,000 

New seismic (4 areas) ----------------------------------- 4,000,000 

Subtotal ---------------------------------------------- ----,6.:,,2"'00","ooo"" 

(4) Engineering: 

Rock mechanics------------------------------------------- 2,000,000 

Metallurgy ------------------------------------------------- 1,000,000 

Drilling and completion fluids-------------------------- 1,000,000 

Formation evaluation------------------------------------- 1,000,000 

Subtotal ---------------------------------------------- -----,5,:.,,o"'oo""',o""oo" 

Contingency fund -------------------------------------------- 2,000,000 

Total-------------------------------------------------- --,2"'0",o"'oo""',oo""o" 

FIELD-BASED RESEARCH 

To prove the concepts of and to improve the technology for deep-gas drilling, field-based research will be necessary. The cost of this work will be significantly greater than 

the $20 million needed to establish the feasibility of deepgas drilling. 

The deep Anadarko Basin has provided drilling experience below 25,000 ft. (Hefner and others, 1973). Modern 

drilling practices in this basin show that wells can be 

drilled to 25,000 ft in about one year (Koenig, 1991); the 

geological section, drilling curves, and casing program are 
CHALLENGES OF ULTRADEEP DRILLING 213 

shown in figures 4 and 5. A round-number estimate of the 

cost to drill a well to 25,000 ft would be about $10 million. Assuming costs increase proportional to the square of 

the depth drilled, a well drilled to 40,000 ft could cost 

anywhere from $25 to $50 million. A reasonable projection of costs to promote an ultradeep-drilling test, along 

with associated research and development activities, would 

be $50 to $60 million. 

RESERVE REQUIREMENTS 

It is important to determine what size geologic target is 

needed to justify the costs involved with deep-gas drilling. 

To get a feel for the magnitude of the required resource, the 

following simple assumptions are made: (1) Average well 

density will be 1 well/section (640 acre spacing), (2) necessary undiscounted return on investment is 5 to l, (3) cost to 

drill and complete a 40,000-ft well is $50 million, (4) initial 

-25,000' 

-30,000' 

flow rates would be at least 20 million cubic feet (MMcf) 

per day, (5) gas formation volume factor is 0.002 cubic ft of 

gas at reservoir conditions per cubic foot of gas at atmospheric conditions, (6) porosity is 7 percent, (7) water saturation is 30 percent, and (8) average gas recovery will be 65 

percent of the original gas in place. 

Using these assumptions, the following reserves and 

gas-in-place values can be computed: 

Net gas price to Needed reserves Gas in place Net thickness of 

producer per well producing interval 

($/Mcf) (Bcf) (Bcf/section) (ft) 

2.00 125 192 312 

3.00 83 127 207 

5.00 50 77 125 

7.00 35 54 88 

9.00 28 43 70 

Mcf=thousands of cubic feet 

Bcf=bill ions of cubic feet 

Figure 4. Generalized geological cross section of Anadarko Basin showing location of Northeast Mayfield well. From American 

Association of Petroleum Geologist (1989) and Koenig ( 1991 ). 
214 THE FUTURE OF ENERGY GASES 

Days Drilling versus Depth 

0 

Drilling Fluids 

Fresh water 

& gel system 

Fresh water & 

gel system 

Wellbore 

Schematic 

~l4o" hole I 

4 -

~ (High chlorides & 

calcium encountered) L 

30" at 400' 

120.5 hole I 

16" at 5250' - ....... 

-

Q) 8 Q) - - f--- Contingency 

--0 

II) 

"0 12 

-\ _ _ WALNE -

-

-\~ . 

1-34 J 

,_ ~ Fresh waterextended 

bentonite system 

9 718" tieback 

114 3/4" hole I c as 

II) 

::I 

0 

.s:; 

....... 

.s:; 

-

-a. 

Q) 

0 

16 

20 

24 

I 

0 

"' f-- 1-- \~HOWELL 1-2 

':-~ "" I 

I 

100 

\ ~'\. 

I ''~ 200 

Days 

I I 1-

I 

300 

I 

400 

·Mineral Oil 

base system 

12 1/16" at 

16900' 

l1o 5ta" hole I 

9 7ta" at 22500' 

181/2" hole 

7 3t4 • at 25500' 

Figure S. Days to complete versus depth, including drilling fluids and well bore schematic, for deep wells in Northeast Mayfield, 

Anadarko Basin. From Koenig (1991). 

One can conclude the following from these data: ( 1) 

Substantial reduction in drilling costs through improved 

technology can have a major impact upon the economic 

viability of drilling deep-gas prospects, (2) higher gas prices would provide needed incentives to look for deep gas, 

and (3) if the net gas price to the producer is $3.00/Mcf, 

then one would need to successfully complete about 200 ft 

of producing interval given the assumptions above (this assumes that the preliminary research has been successfully 

completed). 

SUMMARY 

Drilling costs will be high and therefore giant fields 

must be found to justify deep-gas exploration. All aspects 

of geology, geochemistry, geophysics, and engineering pertinent to deep drilling must be carefully investigated in 

order to enhance the probability of locating profitable targets. Research in drilling technology to substantially reduce 

drilling costs is perhaps the single most important aspect 

needed to achieve success with ultradeep drilling. Any 

progress made with this technology will undoubtedly benefit more conventional drilling. The spin-off value of all the 

geoscience an·d engineering research effort necessary to accomplish ultradeep drilling should prove of great value to 

the oil and gas industry. 

ACKNOWLEDGMENTS 

The contents of this paper were for the most part 

pulled together at a U.S. Department of Energy workshop 

on Deep Gas at Woodlands, Texas in May of 1987. Participants in this workshop were George Claypool, Bill 

Gwilliam, Steve Holditch, David Howell, Arfon Jones, 
CHALLENGES OF ULTRADEEP DRILLING 215 

Jim Jorden, Syd Kaufmann, Keith Kvenvolden, John 

Logan, Amos Nur, Phil Randolph, John Roen, Joan 

Spaw, Dal Stanley, Cheryl Wilgus, and the author. Also, 

Hans von der Dick, Ross Clark, and Murray Grigg have 

provided invaluable comments in their reviews of this 

subject. 

REFERENCES CITED 

Barker, C., 1990, Calculated volume and pressure changes during 

the thermal cracking of oil to gas in reservoirs: American 

Association of Petroleum Geologists Bulletin, v. 74, no. 8, 

p. 1254-1261. 

Hefner, R.A., III, Wheeler, R., and Kinchloc, R., 1973, The drilling and production of ultradeep natural gas accumulations 

occurring below 20,000 ft in the Anadarko Basin: 12th 

World Gas Conference, Nice, IGU/A 5-73. 

Koenig, R.L., 1991, An extraordinary drilling challenge in the 

Anadarko Basin: 1991 Society of Petroleum Engineers Annual Technical Conference, SPE paper 22575. 

Moore, S.D., 1992, International deep wells hit new high: Petroleum Engineer International, v. 64, no 6, p. 28-32. 

Shirley, K., 1989, Anadarko's Arbuckle play heats up: American 

Association of Petroleum Geologists Explorer, v. 10, no. 7. 

Takach, N.E., Barker, C., and Kemp, M.K., 1987, Stability of 

natural gas in the deep subsurface-Thermodynamic calculation of equilibrium compositions: American Association of 

Petroleum Geologists Bulletin, v. 71, no. 3, p. 322-333. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Empirical Observations Regarding Methane Deadlines 

in Deep Basins and Thrust Belts 

By David W. Houseknecht1 and Christoph Spot1 1

•

2 

CONTENTS 

Abstract . ... ..... . . .. .. . . .. .. . . . . ... .. ... .. ...... .... .. .. .. . . ... . . ............... 217 

Introduction ................................................................... 217 

Thermal Maturity and Hydrocarbon Occurrence .. .. ... .. 218 

Origins of Methane ....................................................... 219 

Preservation of Deep-Seated Methane ......................... 219 

Theoretical Considerations of Thermal Stability .... 219 

Experimental and Empirical Evidence from Coals . 220 

Empirical Evidence from Conventional 

Natural-Gas Exploration ........................................ 221 

Methane at High Thermal Maturities in the Arkoma 

Basin-Ouachita Thrust Belt .......................................... 222 

Regional Thermal Maturity ................................... 222 

Local Thermal Maturity ......................................... 222 

Natural-Gas Occurrences ....................................... 226 

Red Oak Field .. .... .... .. ............. ......... ...... ....... .. 226 

Wilburton Field . . .. .. .. .. ... ... .. ...... ...... ... .............. 226 

Ouachita Frontal Thrust Belt .......................... 226 

Discussion ..................................................................... 227 

Conclusions . .. .. . . .... . . .. . .. . ... .. ... .. .. ... ... .. . . .. .. . . ... ............. ... . 228 

Acknowledgments ........................................................ 228 

References Cited . . .. .. . . . .. .. . .. .. .. .. ... . . ... . .. ... .. ..... . . ... .. . . ..... .. 229 

ABSTRACT 

Deep parts of many sedimentary basins and thrust belts 

have large natural-gas potential, but exploration in these 

settings has been limited by the widely held perception that 

1

U.S. Geological Survey, National Center, 12201 Sunrise Valley Dr., 

Reston, VA 22092. 2University of Missouri, Columbia, MO 65203. 

natural gas and (or) reservoir quality are not preserved in 

strata of high thermal maturity. Review of pertinent literature plus new data from the deep Arkoma Basin and Ouachita thrust belt (Arkansas and Oklahoma) indicates that 

methane is not chemically destroyed by temperatures that 

produce vitrinite reflectance of 4 to 5 percent. In some settings, however, methane becomes diluted to noneconomic 

concentrations by nitrogen and carbon dioxide at vitrinitereflectance levels above 4 percent. 

Methane production in the Arkoma Basin and Ouachita thrust belt occurs in strata with up to at least 4 percent 

vitrinite reflectance, and prolific methane production from 

wells located near the presently defined upper thermal 

maturity limit of production suggests that economic methane resources are likely to be discovered in strata of still 

higher thermal maturity. Excellent reservoir quality has 

been preserved in this natural-gas province, partly because 

reservoired hydrocarbons inhibited high-temperature diagenetic reactions that destroyed porosity below hydrocarbon-water contacts. 

Although these observations suggest that strata of high 

thermal maturity have vast natural-gas potential, many geologic processes that influence the fate of methane during 

exposure to deep burial, high temperatures, and tectonic 

deformation are poorly understood. Concerted research on 

metagenesis of methane and nonhydrocarbon gases and on 

high-temperature diagenesis of reservoir and seal rocks is 

necessary for better evaluation of natural-gas potential in 

high thermal maturity provinces and for development of 

exploration strategies to test the potential of those provinces. 

INTRODUCTION 

Natural gas is viewed as a significant energy resource 

whose use may increase because it is thought to be 

217 
218 THE FUTURE OF ENERGY GASES 

domestically abundant in the United States (Gautier and 

Brown, this volume; Howell, Wiese, and Swinchatt, this 

volume) and because its use in place of coal and oil-based 

fuels would reduce substantially the emission of greenhouse gases and toxic elements to the atmosphere (Cole, 

this volume). However, increased use of natural gas is inhibited by the economically induced oil emphasis that has 

dominated the U.S. petroleum industry (see Hefner, this 

volume). In fact, natural-gas exploration and development 

strategies are, in essence, those that have been developed 

for oil, and our research-based knowledge of natural gas is 

less comprehensive than that of oil. 

During the past decade, a relatively small segment of 

industry has focused on exploration and development of 

nonassociated natural gas (that is, natural gas not associated with oil accumulations). As a result, there is a growing 

realization that much (perhaps most) natural gas is not associated with oil and may be distributed differently 

through the earth's crust than oiL For example, discovery 

and development of deep-basin natural-gas accumulations, 

natural gas in tight sandstone reservoirs, and widespread 

coalbed methane accumulations have demonstrated the existence of significant resources that are not associated with 

oil and occur in very different settings than oil. 

Among the many geologic habitats in which natural 

gas occurs, deep parts of sedimentary basins and thrust 

belts appear to have large potential. Exploration in these 

::l c8300 

tel 8300· 

~ 11.000 

0 11.000· 

:: 13.000 

w 

(!) 

< 

1-

z 

w 

0 

a: 

w 

c.. 

z 

0 

Ill 

a: 

< 

0 

c 

w 

X 

LC 

13.000-

14.000 

60 

70 

80 

90 

100 

HEAVY OIL AND GAS FIELDS 

OIL AND GAS FIELDS 

LIGHT OIL AND GAS FIELDS 

INCREASING % OF GAS FIELDS 

OIL PHASE-OUT ZONE 

GAS PREDOMINANT 

GAS ONLY. 

VOLUME 

DECREASES 

DOWNWARD 

CURRENT LOWER LIMIT 

-------------------- OF COMMERCIAL GAS 

INADEQUATE POROSITY 

GRAPHITE FROM ENTRAPPED GAS? 

settings, however, has been inhibited by economic factors 

and by the poorly understood nature of natural-gas preservation at elevated temperatures. The purpose of this paper 

is to review empirical observations regarding the existence 

of a thermally controlled natural-gas deadline and to 

present data from recent exploration and research activity 

in the Arkoma Basin-Ouachita thrust belt that contributes 

to our understanding of the occurrence of natural gas in 

strata with elevated thermal maturity (see also Burruss; 

Wyman; and Dyman and others, this volume). 

THERMAL MATURITY AND 

HYDROCARBON OCCURRENCE 

Since the landmark work of David White (1915), it 

has been known that thermal maturity is a fundamental 

control of hydrocarbon distribution. White (1915) demonstrated that low, intermediate, and high coal rank (that is, 

thermal maturity) coincided with oil, gas, and no hydrocarbon production, respectively, in the Appalachian Basin. 

The relationships observed by White became a working 

paradigm to the petroleum industry and were summarized, 

along with additional examples, by Landes (1967), whose 

synopsis is shown in figure I. A more comprehensive history of thermal maturity and hydrocarbon relationships 

was provided in tabular form by Bostick ( 1979). 

ZONES OF PETROLEUM 

GENERATION AND DESTRUCTION 

ORGANIC MATTER TYPE 

AMORPHOUS (OIL) MIXED COALY (GAS) 

I I I 

I I 

PEAK OIL GENERATION 

I 

I 

I 

I 

I 

PQ!i_ I WET-GAS GEN 

DRY 

GAS 

Figure 1. Relationship between thermal maturity and economic occurrence of hydrocarbons. Left half of figure 

summarizes knowledge as of I 967 (modified from Landes, 1967). Right half of figure summarizes more recent 

concepts of hydrocarbon windows, zones of thermal maturity in which oil, wet gas, and dry gas are chemically stable 

in economic volumes in reservoirs (modified from Dow, 1977). Note that dry-gas preservation limit likely is not valid 

in at least some geologic settings (see text for explanation). FIXED CARBON, total carbon content; GEN, generation; MOIST BTU, calorific value in British thermal units determined from moist samples (as mined); LV, low 

volatile; MV, medium volatile; HV, high volatile; R0 , reflectance in oil. Dashed lines indicate gradational boundaries. 
EMPIRICAL OBSERVATIONS REGARDING METHANE DEADLINES IN DEEP BASINS AND THRUST BELTS 219 

During the past two decades, research in organic geo-. 

chemistry has emphasized thermal generation and thermal 

destruction of hydrocarbons. This emphasis resulted in the 

concept of hydrocarbon windows, specific ranges of thermal maturity within which oil, wet gas (gaseous hydrocarbons heavier than CH4), and dry gas occur (for example, 

see fig. I). The hydrocarbon-window concept is based 

both on theoretical and experimental organic geochemistry 

of hydrocarbon generation and destruction, and on empirical relationships between thermal maturity and the occurrence of commercial hydrocarbon accumulations in the 

Earth's crust. This body of research has demonstrated that 

oil and wet gas have thermal-maturity deadlines, levels of 

thermal maturity above which those phases do not commonly occur in economic volumes, although those deadlines vary somewhat in absolute value depending upon the 

specific origin and composition of the hydrocarbons. Despite slight variations in oil and wet-gas deadlines, they 

are a powerful tool for predicting whether unexplored 

areas might contain oil or wet gas. Most organic geochemists agree that oil and wet-gas deadlines are fundamentally 

controlled by the thermal stability of the various organic 

geochemical compounds of which the hydrocarbons are 

composed, and are mostly independent of inorganic diagenesis of reservoir and seal rocks. An alternative point of 

view is expounded by Price (in press; and in Dyman and 

others, this volume), who presents evidence that hydrocarbons are chemically stable to much higher levels of thermal maturity in closed systems, such as fine-grained rocks. 

Price (in press; and in Dyman and others, this volume) 

suggests that the distribution of hydrocarbons is more a 

function of subsurface physical environment, pore-fluid 

pressure, and fluid dynamics than a function of chemical 

stability of hydrocarbon compounds. 

Little consensus applies to a dry-gas (methane) deadline. In fact, various authors have suggested that methane 

deadlines span a wide range. The economic deadline for 

methane, defined by vitrinite reflectance or equivalent vitrinite reflectance from another scale of thermal maturity, 

has been placed at 2 percent by Landes (1967), 3 percent 

by Dow (1977) and Saxby (1982), 3.2 percent by Dow 

and O'Connor (1982), 3 to 3.5 percent by Teichmi.iller and 

others (1979), and 5 percent by Hood and others (1975). 

Although Saxby ( 1982) placed the economic deadline for 

methane at 3 percent, he suggested a tentative methane 

preservation deadline of 5 percent. The disparity of these 

estimates suggests that the existence of a methane deadline is in doubt. Moreover, the limited volume of literature 

that addresses this problem suggests that a variety of processes may influence the existence of a methane deadline, 

and that the preservation of methane exposed to elevated 

thermal regimes may be geographically and (or) stratigraphically variable depending upon specific temperature, 

pressure, and chemical histories of reservoirs, seals, and 

pore fluids. The methane deadline is the focus of this 

paper, and following sections provide an overview of research results that address this problem. 

ORIGINS OF METHANE 

Methane can be generated in several ways. Biogenic 

methane (also known as microbial methane and bacterial 

methane) is generated during diagenesis at temperatures 

generally lower than those for oil generation ( <50°C; locally up to 11 0°C) by bacterial degradation of organic 

matter (Rice and Claypool, 1981; Coleman and others, 

1988; Schoell, 1988; Tissot and Welte, 1984). 

Thermogenic methane is generated by temperature-induced reactions during catagenesis at temperatures generally corresponding to oil generation· (roughly 50-150°C) 

and during metagenesis at temperatures generally higher 

than oil generation (> 150°C). In systems that contain 

humic kerogen, thermogenic methane is generated directly 

from kerogen ("primary cracking" of Welte and others, 

1988) during catagenesis and metagenesis. In systems that 

contain sapropelic kerogen, thermogenic methane is generated during catagenesis as a by-product of oil and (or) 

wet-gas generation (primary cracking), and in greater volumes during metagenesis, as the result of cracking of 

heavier hydrocarbons that previously had been generated 

during catagenesis ("secondary cracking" of Welte and 

others, 1988). 

Abiogenic methane originates from inorganic sources, 

commonly as the result of deep crustal reactions involving 

graphite (C) and water (H20) (see Burruss, this volume). It is 

generally thought to be present in concentrations insufficient 

to be considered of economic importance (see, for example, 

Tissot and Welte, 1984), although some authors disagree 

with that perspective (for example, Gold, this volume). 

·PRESERVATION OF 

DEEP-SEATED METHANE 

Preservation of economic volumes of deep-seated 

methane is the focus of this paper, regardless of the methane's origin. The following sections address the chemical 

stability of methane at elevated temperature and the empirical evidence bearing on the preservation and destruction 

of methane accumulations exposed to high temperatures 

and (or) deep burial. 

THEORETICAL CONSIDERATIONS OF 

THERMAL STABILITY 

The chemical stability of methane at elevated temperature has been calculated on the basis of thermodynamics 
220 THE FUTURE OF ENERGY GASES 

by Hunt (1975), Takach and others (1987), and Barker and 

Takach (1992). Takach and others (1987) determined that 

most methane would be preserved in an inert reservoir up 

to at least 320°C (the upper limit of their calculations), 

and Hunt (1975) calculated that methane is chemically stable in inert, dry reservoirs up to 550°C. However, Hunt 

(1975) pointed out that if water and a source of sulfur are 

present, methane can be destroyed by oxidation to yield 

H2S and C02. Both Hunt (1975) and Takach and others 

(1987) concluded that reservoir diagenesis, and specifically the preservation of porosity, is probably more critical 

than the thermal stability of methane for deep natural-gas 

resources. 

Barker and Takach (1992) calculated that reservoir 

mineralogy and the presence or absence of graphite (residue of thermally degraded oil) exert a significant influence on equilibrium gas composition in the deep subsurface (3,000 to 12,000 m; corresponding to 96 to 

325°C). Their work suggests that methane can be totally 

destroyed by oxidation in reservoirs of certain composition, whereas it can be preserved to at least 12,000 m and 

325°C in others, and that the presence of graphite generally extends the maximum depth to which methane persists. 

The results of Barker and Takach ( 1992) are influenced by 

the assumption of an initial water saturation of 40 percent 

in the pores of the reservoir, which results in dramatic 

increases in C02 and hydrogen content at the expense 

of methane (CH4+2H20--+C02+4H2), even at relatively 

shallow depths (3,000 m) and low temperatures (96°C). 

This assumption may be valid in some deep basins, but is 

not consistent with generally lower water saturations in 

many deep-basin gas accumulations. 

EXPERIMENTAL AND EMPIRICAL 

EVIDENCE FROM COALS 

The methane content of coalbeds has been of interest 

for decades, partly because of the explosion hazard posed 

by methane in coal mines and partly because of the resource potential of coalbed gas. Consequently, a relatively 

large experimental and empirical data base that relates gas 

content and composition to coal rank has been assembled. 

Experimental work has shown that C02, CH4, and N2 

are the major gases generated from coal as it matures thermally, although specific products of coalification and their 

relative proportions are dependent upon the maceral composition, and therefore the elemental composition of the 

coal (Karweil, 1969; Hunt, 1979; Tissot and Welte, 1984). 

At low temperatures (diagenesis), biogenic methane is 

commonly generated from peat and lignite. As temperatures increase during burial (catagenesis), typical vitriniterich coals generate a large volume of thermogenic C02, 

followed by an even larger volume of thermogenic CH4. 

Although peak methane generation occurs at about 150°C, 

typically corresponding to bituminous rank, methane continues to be generated from coal at temperatures in excess 

of 220°C, corresponding to anthracite rank (Karweil, 

1969; also summarized by Hunt, 1979). Thermogenic N2 

commonly is generated in much smaller volumes during 

catagenesis, and a large volume of H20 is expelled from 

coal throughout diagenesis and catagenesis. 

Although C02 is the principal constituent of early 

thermogenic gas generated from coals, C02 is only a 

minor and extremely variable constituent of most gas in 

bituminous and anthracite coals. Rightmire (1984) suggested that the high solubility of C02 in water facilitates 

its mobility and that both C02 and water are flushed from 

coalbeds by the large volume of methane generated during 

later stages of catagenesis. 

Methane is stored in coalbeds in three ways. It is estimated that about 90 percent of the gas is adsorbed onto 

the internal surfaces of pores, and the remainder is stored 

in fractures and macropores either as free gas or dissolved 

in groundwater (Rice, this volume). The adsorptive capacity, and therefore the potential gas content of coal, increases with rank (at least through anthracite) and depth 

(Jtintgen and Karweil, 1966a, b; Kim, 1977, 1978). 

The gas content of high-rank coalbeds provides evidence for the retention of gases and for the dilution of 

methane by other gases in incipient metamorphic rocks. 

An example of the influence of increasing thermal maturity on coalbed gas has been documented in the DnieperDonets Basin and the Donbas foldbelt of Ukraine, an area 

that displays increasing thermal maturity in coeval strata 

from the basin into the foldbelt (Lapchinsky and Dzhamalova, 1987; Ulmishek and others, in press). Coalbed gas 

in the eastern part of the foldbelt is a mixture of CH4, N2, 

and C02. The coals are high metamorphic anthracite 

(meta-anthracite) in rank, corresponding to equivalent vitrinite-reflectance values of at least 5 percent and perhaps 

as high as 6 percent. Although the coals of the Donbas 

foldbelt provide evidence of an overall dilution of methane at meta-anthracite rank, gas compositions vary significantly by location. Among the coalbed gases, the CH4 

content varies from 40 to 80 percent, the N2 content varies 

from 20 to 60 percent, and the C02 content varies from 1 

to 17 percent (Lapchinsky and Dzhamalova, 1987). 

Similarly, coalbeds penetrated in the Saar #1 borehole 

in northwestern Germany contain gas in which the concentration of methane decreases almost linearly with increasing depth and coal rank. At thermal maturities higher 

than about 4.5 percent vitrinite reflectance, the sum of N2 

plus C02 is greater than the CH4 content (Wehner and 

others, 1976; Teichmtiller and others, 1983). 

To summarize existing knowledge regarding gas in 

high-rank coals, methane is generated in large volumes 

during catagenesis of coal and continues to be generated 

in smaller volumes during metagenesis. The capacity of 

coal to retain methane by adsorption increases with ther-
EMPIRICAL OBSERVATIONS REGARDING METHANE DEADLINES lN DEEP BASINS AND THRUST BELTS 221 

mal maturity at least into anthracite rank. Little is known 

about methane generation and retention into meta-anthracite rank because of the paucity of economically important 

coals of such high rank. Limited evidence suggests a tendency for methane to be diluted by nitrogen and carbon 

dioxide in coalbeds above approximately 4.5 percent vitrinite reflectance. 

EMPIRICAL EVIDENCE FROM CONVENTIONAL 

NATURAL-GAS EXPLORATION 

Exploration for natural gas in strata known to be characterized by elevated thermal maturities (vitrinite reflectance >2 percent) has been conducted in relatively few 

locations worldwide. This section summarizes the occurrence of methane resources in a few geologic provinces 

where information is available. 

The north-central European gas province includes 

northern Germany, a large part of the Netherlands, and the 

southern portion of the North Sea. Reservoirs are mostly 

sandstones of the Permian Rotliegendes Formation, and 

source beds are considered to be underlying Carboniferous 

coal measures, which mostly are characterized by thermal 

maturities in the range of 1.2 to 3.2 percent vitrinite reflectance (Boigk and others, 1976; Van Wijhe and others, 

1980; Cornford, 1986). Teichmtiller and others (1979, 

1984) have shown that Rotliegendes gas fields in northwestern Germany mostly are characterized by thermal maturities of 1 to 2 percent vitrinite reflectance, but thermal 

maturity in a few gas fields reaches 2.5 to 2.8 percent vitrinite reflectance, and in one gas field reaches 4.4 to 4.7 

percent vitrinite reflectance (Uchte field). Igneous intrusions are thought to underlie those gas fields that display 

highest thermal maturities. Methane generally becomes diluted by increasing nitrogen content in higher-thermal-maturity reservoirs of northwestern Germany gas fields (Van 

Wijhe and others, 1980; Everlien and Hoffmann, 1991), a 

pattern similar to that observed in coalbed gases. 

The Pripyat and Dnieper-Donets Basins and Donbas 

foldbelt of Byelarus and Ukraine represent northwestsoutheast elongate accumulations of strata deposited in 

Devonian rift basins and Carboniferous through Permian 

sag basins (Ulmishek and others, in press). Oil production 

in the Pripyat Basin in the northwest gives way to gas production in the Dnieper-Donets Basin, and there is no hydrocarbon production in the Donbas foldbelt in the 

southeast, apparently as a consequence of increasing thermal maturity from northwest to southeast. Conventional 

gas is produced from strata whose thermal maturity extends up to at least 3.5 to 4.0 percent vitrinite reflectance 

in the Dnieper-Donets Basin. No commercial gas production has been discovered in the anthracite to meta-anthracite (5 to 6 percent vitrinite reflectance) strata in the 

Donbas foldbelt, and gas from coal mines suggests dilution of methane by nitrogen and carbon dioxide (Ulmishek 

and others, in press). These observations suggest that there 

may be limited natural-gas preservation in the thermal-maturity range of 4 to 6 percent vitrinite reflectance, although 

no specific methane deadline is indicated. 

Gas is produced from several fields irt the Kuangsi 

and South Sichuan provinces of China from great depths 

(as much as 7 km; 23,000 ft), and from strata characterized by thermal maturities between 3.8 and 4.8 percent reflectance (Mo and others, 1984). Little is known in the 

Western· literature about these prolific gas occurrences, 

other than that the reservoirs are Precambrian and Devonian carbonates. 

Some of the deepest wells in the United States have 

been drilled into Paleozoic strata in the Anadarko Basin of 

Oklahoma and Texas. Data from many of those wells suggest that the deep Anadarko Basin contains some of the 

most thermally mature strata in the world from which prolific gas production occurs. In fact, the Chevron-Freeport 

#1 Ruth Ledbetter well (Wheeler County, Tex.) holds the 

world record for gas production from the greatest depth, 

7,330-7,955 m (24,435-26,5 18 ft) (Jemison, 1979; Hunt, 

1984; Cardott and Lambert, 1985; Cardott, 1989; Davis 

and Northcutt, 1989). On the basis of a depth-versus-vitrinite-reflectance regression equation determined for the 

Woodford Shale in the Anadarko Basin, it has been estimated that vitrinite reflectance of the productive strata is 

in the range of 5.2 percent (Cardott and Lambert, 1985) to 

5.4 percent (Cardott, 1989). However, these estimates are 

equivocal, and other researchers have. suggested lower 

thermal maturities for the productive interval (Tarafa and 

others, 1988). Such controversy is not uncommon in samples of extreme thermal maturity because of the difficulties 

involved in measuring reflectance of dispersed kerogen 

that has been subjected to metagenesis (see Houseknecht 

and others, 1993). Moreover, gas production from this and 

many of the other deepest wells in the Anadarko Basin 

comes from Ordovician or Silurian strata, none of which 

contains indigenous vitrinite. Thus, vitrinite reflectance 

must be measured in younger strata, including the Devonian and Mississippian Woodford Shale, and projected to 

depths representative of production from older reservoirs. 

Several other authors have documented gas production 

at elevated thermal maturities in the deep Anadarko Basin 

(see Hefner, this volume). Waples (1980) reported 3.8 percent vitrinite reflectance for a gas-producing zone in the 

Socal #1 James (Wheeler County, Tex.) and 4.8 percent 

vitrinite reflectance for a gas producing zone in the Union 

of California #1-33 Bruner (Beckham County, Okla.). The 

latter represents the highest thermal maturity gas production reported by Waples (1980). Using their empirically 

derived depth-versus-vitrinite-reflectance regression equation, Card ott and Lambert ( 1985) calculated vitrinite reflectance values of 4.2 to 4.6 for producing zones in some 

deep wells of the deep Anadarko Basin. 
222 THE FUTURE OF ENERGY GASES 

Despite controversy regarding exact vitrinite-reflectance levels in specific wells, numerous gas fields have 

been developed within the deep Anadarko Basin where 

strata clearly display regional patterns of high thermal maturity (Hood and others, 1975; Waples, 1980; Price and 

others, 1981; Hunt, 1984; Katz and others, 1982; Cardott 

and Lambert, 1985; Cardott, 1989). Moreover, patterns of 

natural-gas productivity do not correspond closely with 

patterns of thermal maturity, suggesting that an abrupt 

methane deadline cannot be defined on the basis of thermal maturity alone. 

METHANE AT HIGH THERMAL 

MATURITIES IN THE ARKOMA BASINOUACHITA THRUST BELT 

The deep Arkoma Basin and frontal thrust belt of the 

Ouachita Mountains in Arkansas and Oklahoma recently 

have been the focus of one of the most active gas-exploration plays in the United States. This activity has been 

stimulated by numerous and prolific discoveries in strata 

characterized by high vitrinite reflectance (Houseknecht 

and others, 1992). The region provides a natural laboratory 

in which to evaluate the concept of a methane deadline. 

This section summarizes relationships between thermal 

maturity and methane production in this prolific gas basin. 

The Arkoma Basin is a foreland basin that formed in 

response to convergent tectonism along the Ouachita 

thrust belt. The geology has been summarized recently by 

several authors (for example, Houseknecht, 1986, 1987; 

Viele and Thomas, 1989; Arbenz, 1989; Meckel and others, 1992). Geology of the Oklahoma portion of the deep 

Arkoma Basin and Ouachita frontal thrust belt recently 

has been discussed in Suneson and others (1990). 

REGIONAL THERMAL MATURITY 

The high thermal maturity of the Arkoma Basin has 

been known since publication of White's (1915) map of 

coal rank. That map also documented the increase in thermal maturity from west to east in strata at the surface and 

in the shallow subsurface, with thermal maturity contours 

oriented approximately perpendicular to stratigraphic and 

structural strike. Subsequently, several authors have refined, but not substantially changed, the pattern of thermal 

maturity defined by White in the Arkoma Basin and have 

determined the pattern of thermal maturity at the surface 

in the Ouachita Mountains (Croneis, 1927; Hendricks, 

1935; Branner, 1937; Wilson, 1961, 1971; Burgess, 1974; 

Curiale, 1983; Houseknecht, 1984; Houseknecht and Matthews, 1985; Hathon and Houseknecht, 1987; Underwood 

and others, 1988; Arne, 1992; Houseknecht and others, 

1992). The regional thermal maturity map shown in 

figure 2 is a compilation of all that work. 

Interpretation of the regional thermal history responsible for the pattern of thermal maturity illustrated in 

figure 2 remains a topic of ongoing research and is beyond 

the scope of this paper. Although not completely understood, these patterns apparently reflect the combined influences of stratigraphic burial, tectonic burial, hydrothermal 

fluid flow, and igneous intrusion, with the relative role of 

each in determining thermal maturity varying geographically and stratigraphically (Houseknecht and Matthews, 

1985; Underwood and others, 1988; Arne, 1992; Houseknecht and others, 1992). 

Although gas exploration has been conducted in many 

parts of the deep Arkoma Basin and Ouachita frontal thrust 

belt, concentrated activity that bears on the topic of this 

paper mostly has occurred in Latimer and LeFlore Counties, eastern Oklahoma (fig. 3). This is a prolific gas-producing area tqat includes the giant Red Oak and Wilburton 

gas fields, each of which have cumulative production in 

excess of 1 trillion cubic feet (28 billion cubic meters), 

several smaller gas fields, and numerous recent gas discoveries in the Ouachita frontal thrust belt (fig. 3). The following sections discuss thermal maturity and gas productivity 

within this area. 

LOCAL THERMAL MATURITY 

Vitrinite-reflectance analyses were performed on shale 

samples from many wells in this area by Hathon and 

Houseknecht ( 1987), whose isoreflectance contour map of 

the basal Atokan (Middle Pennsylvanian) Spiro sandstone 

(widely used informal name for quartzose sandstone at 

base of Atoka Formation; Branan, 1968), one of the most 

prolific reservoirs in the region, appeared in Houseknecht 

and McGilvery (1990). That map shows that vitrinite reflectance increases from less than 2.0 percent in Wilburton 

gas field to more than 3.5 percent at the northeast end of 

Red Oak gas field (fig. 3), a pattern of increase that parallels that of the Hartshorne coalbed (within lowermost portion of Desmoinesian·McAlester Formation; Wilson, 1935; 

Oakes and Knechtel, l948) at shallow depths in the same 

area (fig. 2). As mean vitrinite reflectance increases to the 

east, the vitrinite refl:ectance populations of individual 

samples become more multimodal and their standard deviations increase significantly, phenomena that are thought 

to result from the increase in vitrinite anisotropy that is 

known to accompany increases in thermal maturity 

(Houseknecht and Matthews, 1985; Houseknecht and others, 1993). 

In an attempt to resolve the uncertainties involved in 

measuring reflectance of dispersed vitrinite at these levels 

of thermal maturity, a microscope has been modified to 

measure rotational reflectance of dispersed vitrinite. This 
: "',' 

!MUSK.<'J(';~~'A I \) : ·., : ,. ) --~. 

I ,' \'" · r·. :,' r- l.- v··--, 

:---·---...1 

' j 

:.___ ___ ..-- __ _..:. 

MciNTOSH 

.~._., _j L----~-~· ____ __, (-- •w~....._ ' •• -. J I ~ /" ! ' ' . _ _j ••• ,.o i '--- 1 c--·--./ ., HASI):-l'LL : ; __.....-~ r--1~ i ~0 ," , ___ _j 

.L._ ... / -· l-----· ,•' 

r·) 

' ~---+--------- ( 

I 

,. 

i 

L_ 

Area of 

figure 3 

~- ~ 7 l.:K~AR/ t AREA~--\ 

rt·-·-- • ' . i: I 

PUSHMATAHA 

! ' i I • 

: i r ____ j_ ___________________ _ 

--------· ~ '--··-, 1-' 

i 

! 

i 

i'----

:··-------- --f----··-··--·------ 1 HOWARD ' ~.ll ' 1~ 

EXPLANATION 

Surface trace of thrust fault 

Vitrinite reflectance (percent) contours in: -- 1.0 Surface and near-surface strata - - - - - 2.0 Basal Atoka Formation in subsurface 

--...... 

~\ 

··--.... 

25 mi 

-=..:.-=----

---

-~~::.~·-·=~- 50km 

Figure 2. Regional map of Arkoma Basin and Ouachita Mountains showing vitrinite reflectance contours (solid lines) based on analyses of surface and near-surface samples 

(compiled from Houseknecht, 1984; Houseknecht and Matthews, 1985; Hathon and Houseknecht, 1987; and previously unpublished data), and approximate vitrinite reflectance of 

basal Atokan strata (approximately equivalent to Spiro sandstone at base of Atoka Formation; Branan, 1968) in subsurface (heavy, dashed contours). Thrust faults that trend west to 

east across center of map define Ouachita frontal thrust belt. Northernmost thrust fault of significant displacement (Choctaw thrust fault in Oklahoma and Ross Creek thrust fault in 

Arkansas) defines boundary between Arkoma Basin (north) and Ouachita orogenic belt (south). Rectangle in Oklahoma shows area of figure 3. 

N 

N 

VJ 
N 

t 

OKLAIIOMA 

AREA OF MAP 

- • - - 5mi - - -lOkm 

Wilburton • 

2% field • 

···································· ·-~·-················· ··· ·············~············ ···················~·~-- -~--- :.: ... 

EXPLANATION 

@ Generalized outline of gas field 

J 

c 

A 

Selected tests of Spiro sandstone: 

Productive 

Nonproductive 

Selected production from strata older 

than Spiro sandstone: 

Jackfork Sandstone (Morrowan) 

Cromwell sandstone (Morrowan) 

Arbuckle Group (Ordovician) 

······~~ Rotational-vitrinite-reflectance contour at Spiro sandstone horizon 

- Surface trace of thrust fault 

Thermal-maturity control locations: 

Rotational reflectance data: 

e Cuttings 

0 Cores 

Conventional r eflectance data: 

• Cuttings 

D Cores 

Figure 3. Map of deep Arkoma Basin and Ouachita frontal thrust belt in eastern Oklahoma showing generalized contours of mean rotational vitrinite reflectance and locations of 

natural-gas production from Spiro sandstone at base of Atoka Formation (Branan, 1968) or older strata. General outlines of Red Oak and Wilburton gas fields are shown, as well as 

large productive area south and west of Wilburton field. Results of most test wells drilled in the Spiro east of the 3-percent isoreftectance contour and selected wells drilled in the 

Spiro between the 2-percent and 3-percent isoreflectance contours are shown; sections in whi.:h the Spiro is productive and nonproductive are shown with patterns, and sections 

where the Spiro has not been tested are not patterned. Sections in which production has been established from strata older than the Spiro are patterned and labeled with bold letter 

indicating productive formation. Vitrinite-reflectance control points also are shown. 
EMPIRICAL OBSERVATIONS REGARDING METHANE DEADLINES IN DEEP BASINS AND THRUST BELTS 225 

new methoq facilitates collection of reflectance data while 

the microscope polarizer is rotated 360°, thereby allowing 

vitrinite anisotropy to be measured and more accurate estimates of thermal maturity to be made (Houseknecht and 

others, 1993). For a single particle of dispersed vitrinite, the 

polarizer is rotated 360°, stopping at 200 equally angled 

orientations to collect a reflectance measurement. The mean 

of those 200 measurements is the rotational reflectance for 

that particle. The mean rotational reflectance is the mean of 

rotational reflectance for all particles (usually 50) measured 

in a sample. 

This new technique has been used to characterize thermal maturity of samples from several wells within the area 

shown on figure 3. Resultant data clearly show increasing 

vitrinite anisotropy with increasing thermal maturity, as 

illustrated by the increasing difference between mean maximum and mean minimum reflectance with depth on figure 4. 

For each sample, this technique yields several variables that 

can be used to evaluate thermal maturity, including mean 

maximum reflectance (essentially equivalent to the reflectance parameter commonly reported by coal petrographers), 

mean rotational reflectance, and mean minimum reflectance. At reflectance values below 2 percent there is little 

difference among these three parameters. However, as reflectance values increase above 2 percent these three parameters increasingly diverge (fig. 4), a direct indication of an 

increase in vitrinite anisotropy. We have chosen to use mean 

rotational reflectance as the optimum index of thermal maturity because that parameter displays low standard deviations and mostly unimodal histograms in our data sets, and 

because it is theoretically equal to reflectance measured in 

nonpolarized light, a technique used in many dispersed organic studies (Houseknecht and others, 1993). 

Comparison of old and new data from several samples 

from the study area shows that mean vitrinite reflectance 

reported by Hathon and Houseknecht (1987) is virtuaiJy 

identical to mean minimum reflectance measured using the 

new technique. There is little difference between old and 

new data at vitrinite reflectance values less than 2 percent, 

but the difference becomes increasingly larger as reflectance values increase above 2 percent. Thus, the Spiro vitrinite reflectance map published by Houseknecht and 

McGilvery (I 990) is accurate in the area of Wilburton gas 

field but depicts conservatively low values of reflectance 

to the east, in the area of Red Oak gas field. 

In figure 3 is shown the vitrinite reflectance of the 

Spiro reservoir horizon in the deep basin and frontal thrust 

belt based on measurement of rotational reflectance of 

samples from 13 wells, and using the larger base of 

conventional vttnmte reflectance data (Hathon and 

Houseknecht, 1987) to constrain locations of boundaries 

between reflectance classes. In the deep basin, north of the 

Choctaw thrust fault, mean rotational reflectance of the 

Spiro horizon is about 2 percent in Wilburton gas field and 

increases to more than 4 percent in eastern Red Oak gas 

o-.---------------ro 

4l 

4l 

Latimer County, Oklahoma 

Sec. 10, T. 4 N., R. 20 E. 

Anson Golden #1-10 

cP-. 1 ~CP 

0 

0 

0 

:I: 

f.-

c.. 

UJ 

Cl 

5 

10 

/!#c ~otational 

Minimum ~11• c <!--Maximum 

thrust--------------------------••••• -.--

11•c 

11•c 

thrust-----------------------------------

11•c 

15 

2 

3 

0 

0 

0 

:I: 

f.-

c.. 

UJ 

4 Cl 

Spiro-----------A-1;-.c. c---

CP _... thrust------------------------ --i.-.--c··- 5 +-- CP 

11 • c ro-----------~~~ 

20 --~--~~--.------r-~--~ 6 

0.0 1.0 2.0 3.0 4.0 

VITRINITE REFLECTANCE (%) 

Figure 4. Plot of depth versus mean minimum, mean rotational, 

and mean maximum vitrinite reflectance for well located near the 

present eastern termination of production from the Spiro sandstone (base of Atoka Formation; Branan, 1968) in the Ouachita 

frontal thrust belt. An initial production potential of 32 million 

cubic feet (900,000 cubic meters) of natural gas per day from the 

thrusted Spiro reservoir at a depth of about 4,880 m (16,000 ft) 

was reported for this well. Note the increased divergence of the 

three reflectance parameters as vitrinite reflectance values increase above 2 percent. Arrows labeled "CP" indicate casing 

points. TD, total depth. 

field (fig. 3). Reflectance in the frontal thrust belt shows a 

similar eastward increase, but absolute values are higher 

than in adjacent areas in the deep basin. Mean rotational 

reflectance is about 2.5 percent in the frontal thrust belt at 

the western edge of the map and increases to more than 4 

percent in the easternmost wells analyzed (fig. 3). 

Thermal-maturity data for one of the easternmost productive wells in the Ouachita frontal thrust belt is shown 

in figure 4. Mean rotational vitrinite reflectance of shales 

immediately above and immediately below the reservoir 

are 2.9 percent and 3.1 percent, respectively. 
226 THE FUTURE OF ENERGY GASES 

NATURAL-GAS OCCURRENCES 

RED OAK FIELD 

The area depicted in figure 3 is characterized by prolific natural gas production. Natural gas originally was 

discovered in shallow reservoirs (400-550 m depth) in 

Red Oak field in I 912, and deep and more prolific production was discovered in 1959 (Houseknecht and 

McGilvery, 1990). Cumulative production from Red Oak 

field has surpassed 1 trillion cubic feet (28 billion cubic 

meters), and ultimate recoveries may exceed 3 trillion 

cubic feet (85 billion cubic meters). Although there are 

numerous productive reservoirs in Red Oak field, most 

production is from the middle Atokan Red Oak sandstone 

(2,000-2,500 m depth) and the basal Atokan Spiro sandstone (3,300-4,000 m depth). From west to east, production from the Spiro sandstone in Red Oak field spans a 

range of vitrinite reflectance values from about 3 percent 

to more than 4 percent (fig. 3). Although productivity of 

the Spiro in individual wells varies widely throughout 

Red Oak field, most of that variability can be attributed 

to a combination of structural position and facies-selective diagenesis of the reservoir prior to hydrocarbon accumulation (Houseknecht and McGilvery, 1990). Moreover, 

the relative ages of pyrobitumen and late-stage cements at 

the base of the productive gas column indicate that reservoired hydrocarbons (at least partly liquid) were thermally cracked and that most porosity in the water leg was 

destroyed subsequently by high-temperature diagenesis. 

These observations provide evidence that reservoir quality was established largely by facies-selective diagenesis 

prior to hydrocarbon accumulation, and that the presence 

of reservoired hydrocarbons preserved that range of reservoir quality as elevated thermal maturities were attained 

(Houseknecht and McGilvery, 1990). Reservoir quality 

of the Spiro ranges up to 24 percent porosity and 800 

millidarcies permeability, and lateral patterns of reservoir 

quality do not appear to be related to thermal maturity 

(see Branner, 1937; Houseknecht, 1984; Houseknecht and 

others, 1992; and Hayes, 1991, for additional discussion 

of thermal maturity-porosity relationships in this region). 

The eastern termination of production from the Spiro in 

Red Oak field corresponds to rotational reflectance of 4.0 

to 4.5 percent. Unfortunately, this margin of Red Oak 

field is structurally unfavorable for prospecting (see Spiro 

structural map in Houseknecht and McGilvery, 1990), and 

consequently a lack of borehole data and accompanying 

samples precludes further evaluation of the relationship 

between thermal maturity and methane occurrence. 

Significantly, a well drilled near the eastern margin of 

Red Oak field (sec. 4, T. 6 N., R. 23 E.) in 1986 established 

natural-gas production from the Ordovician Arbuckle 

Group, about 600 m deeper than the Spiro sandstone. The 

thermal maturity of the Arbuckle Group reservoir at that 

location exceeds 4 percent equivalent vitrinite reflectance 

(no indigenous vitrinite is present in the Arbuckle because 

of age), and may be as high as 5 percent. Conodonts from 

the Arbuckle in that well are characterized by color alteration index of 5, which corresponds to vitrinite reflectance 

values greater than 3.6 percent, according to Epstein and 

others (1977). Natural gas production ceased after a few 

months because of increasing water production, but that 

well confirmed the preservation of both methane and reservoir quality in the Spiro sandstone and older reservoirs at 

extreme thermal maturity in Red Oak field. 

WILBURTON FIELD 

Natural gas was discovered originally in shallow reservoirs at Wilburton field in 1925 (600-1,000 m depth; 

sandstones in middle and upper part of the Atoka Formation), deeper and more prolific reservoirs were discovered 

in 1960 (2,100-2,700 m depth; mostly Spiro sandstone in 

thrust sheets), and still deeper and even more prolific reservoirs were discovered in 1987 (3,600-4,600 m depth; 

Spiro sandstone and Arbuckle Group carbonates on subthrust horst). Cumulative production from Wilburton field 

has surpassed 1 trillion cubic feet (28 billion cubic meters), and ultimate recoveries likely will exceed 2 trillion 

cubic feet (57 billion cubic meters). 

The most recent drilling activity in Wilburton field has 

established production from the Spiro sandstone and Arbuckle Group on a subthrust horst structure. Vitrinite reflectance of the Spiro horizon ranges from 2.0 to 2.3 

percent, and Devonian through Mississippian shale beneath the Spiro have yielded vitrinite reflectance values 

between 2.5 and 3.0 percent. These values suggest that 

prolific production in the Arbuckle Group occurs from reservoirs that are characterized by thermal maturities in excess of 3 percent equivalent vitrinite reflectance. Hendrick 

(1992) estimated the thermal maturity of Arbuckle reservoir rocks to be equivalent to a vitrinite reflectance between 3.5 and 3.8 percent. Considering these levels of 

thermal maturity, the performance of the Arbuckle reservoir is remarkable, with initial potentials commonly reported to be in the range of 10 to 35 million cubic feet 

(0.3 to 1.0 million cubic meters) of natural gasper day! 

OUACHITA FRONTAL THRUST BELT 

Exploration drilling in the Ouachita frontal thrust belt 

has established natural-gas production along a trend extending throughout the central and western part of the 

study area (fig. 3) (Suneson and Campbell, 1990). The 

thrusted Spiro reservoir horizon in this area is characterized by mean rotational vitrinite reflectance values that 

range from about 2.5 percent to more than 4.0 percent. 
EMPIRICAL OBSERVATIONS REGARDING METHANE DEADLINES IN DEEP BASINS AND THRUST BELTS 227 

Reservoir quality and productivity of the Spiro are locally 

variable along this trend; it is not uncommon for one location to be nonproductive or marginally productive whereas 

the adjacent location may have an initial potential of I O's 

of million cubic feet (millions of cubic meters) per day. 

Presently, production from the Spiro sandstone in the 

thrust belt ends at the eastern edge of R. 20 E., corresponding to a vitrinite reflectance around 4 percent (fig. 3). 

The easternmost wells, however, are among the most highly productive wells drilled in the Spiro in the thrust belt.. 

For example, initial potentials of 32 and 3 million cubic 

feet (900,000 and 90,000 cubic meters) per day were reported for wells in sections 10 and 12, respectively, ofT. 4 

N., R. 20 E., and a calculated absolute open flow of 162 

million cubic feet (4.6 million cubic meters) per day during testing was reported for, a well in section 14 of the 

same township! 

Only a few wells have been drilled in the thrust belt 

east of R. 20 E. Two wells have tested the Spiro sandstone 

in T. 4 N., R. 21 E. (sections 4 and 8), and both encountered nonporous sandstone. Mean rotational reflectance of 

core samples from the Spiro in section 4 is 4.05 percent. 

One well has tested the Spiro sandstone in T. 4 N., R. 22 

E. (section 5); it encountered nonporous Spiro sandstone 

but established production from a younger sandstone in 

the lower part of the Atoka Formation at a depth of 4,470 

m. Two wells drilled still farther east (sec. 8, T. 4 N., R. 

23 E. and sec. 31, T. 5 N., R. 24 E.) penetrated into the 

Ordovician Arbuckle Group on a subthrust horst, but the 

Spiro sandstone was absent in both wells because of thrust 

decapitation of the horst, and no production was established from either well. Mean rotational reflectance values 

of cutting samples from those two wells are more than 4 

percent in strata superjacent and subjacent to the Spiro 

sandstone. 

Significantly, three weJJs drilled in the thrust belt have 

established production from the Morrowan (Lower Pennsylvanian) Jackfork Sandstone, a deep-water-facies sandstone deposited in the Ouachita trough prior to uplift of 

the orogenic belt. These wells (sec. 20, T. 4 N., R. 20 E.; 

sec. 4, T. 3 N., R. 20 E.; and sec. 28, T. 4 N., R. 21 E.) 

have tested up to 3.5 million cubic feet (99,000 cubic meters) per day (initial potential), and their discoveries suggest that natural-gas production will be extended beyond 

the eastern and southern limits thus far defined in the 

Ouachita frontal thrust belt. Although no thermal-maturity 

data are available from these wells, regional patterns 

(fig. 2) suggest that production is from strata whose vitrinite reflectance must be in the range of 3.5 to 4.5 percent. 

DISCUSSION 

Three poorly understood geologic phenomena emerge 

as critical elements to the economic preservation of natural 

gas in strata of high thermal maturity (vitrinite reflectance 

>3 percent): dilution of methane by nonhydrocarbon 

gases, preservation of reservoir quality, and preservation 

of effective seals. 

The information presented in this paper demonstrates 

that methane is not destroyed chemically, at least in many 

reservoirs, when exposed to temperatures high enough to 

produce vitrinite reflectance in the 4 to 5 percent range. 

Exceptions may occur in reservoirs with high water saturations, where methane may react with water to yield carbon dioxide and hydrogen (Barker and Takach, 1992). 

Evidence from both coalbeds and conventional reservoirs, 

however, demonstrates that in some geologic settings 

methane is diluted to marginally economic or noneconomic concentrations at elevated thermal maturities. Dilution 

by N2 and C02 appears to be most common. 

Although dilution of methane by nitrogen at elevated 

temperature and thermal maturity has been documented in 

both coalbeds and conventional reservoirs, the origin of 

the nitrogen is not well understood. Nitrogen generation 

during coal maturation has been documented by Karweil 

(1969) and Jiintgen and Klein (1975), and the cracking of 

organic nitrogen compounds has been suggested as the 

source of N2. In conventional reservoirs, the origin of N2 

has been attributed to cracking of organic nitrogen compounds dispersed in shales (Lutz and others, 197 5), reaction of ferric oxides with organic nitrogen compounds 

(Guseva and Fayngersh, 1973), reaction of ammonia generated during coal maturation with ferric iron (Getz, 

1977), decomposition of ammonium-bearing clay minerals 

and feldspars (Everlien and Hoffmann, 1991 ), and degassing of crystalline basement rocks (Beebe and Curtis, 

1968; Petersil'ye and others, 1970). The prominent role of 

ferric oxides in many of these hypotheses stems from the 

fact that gases containing high nitrogen concentrations are 

commonly found in red beds, or in reservoirs that are underlain by red beds. 

Carbon dioxide at elevated thermal maturity appears 

to have multiple origins. C02 may be a by-product of catagenesis and metagenesis of organic matter, particularly 

where humic (type III) kerogen is involved. Although recent literature emphasizes the pulse of C02 expelled 

during early catagenesis (see, Hunt, 1979, his fig. 5-6), 

C02 continues to be generated from humic organic matter 

throughout catagenesis and into metagenesis, to at least 

thermal maturity levels corresponding to anthracite coal 

rank (see, Karweil, 1969). Some authors have suggested 

that C02 occurrences in areas of high thermal maturity 

may be the result of thermal decomposition of carbonates 

(see discussion in Hunt, 1979). This may be particularly 

true in areas of igneous intrusion into carbonate strata 

(Holmquest, 1965). 

For several decades, geologists have proposed that 

high-temperature diagenetic destruction of reservoir quality may define the ultimate methane deadline (Branner, 
228 THE FUTURE OF ENERGY GASES 

1937; Landes, 1967; Hunt, 1979; Houseknecht, 1984). 

However, in recent years many researchers have shown 

that diagenetic reactions are commonly inhibited by the 

presence of reservoired hydrocarbons (for example, Dixon 

and others, 1989) because inorganic chemical reactions 

that commonly destroy porosity are inhibited (or cease 

completely) where water is displaced from the pore system as hydrocarbons accumulate. Houseknecht and Hathon 

(I 987) and Houseknecht and McGilvery (1990) attributed 

preservation of excellent reservoir quality at elevated thermal maturity in the Spiro sandstone in the Arkoma Basin 

to this process. They demonstrated that porosity was mostly destroyed by high-temperature chemical reactions 

below hydrocarbon-water contacts (that is, in the water 

leg), whereas those same reactions were ineffective in reducing porosity above hydrocarbon-water contacts. 

If natural gas is to be trapped for long intervals of 

geologic time and if reservoir quality is to be preserved by 

the presence of reservoired hydrocarbons, then the effectiveness and longevity of seals become significant elements in preserving natural gas in strata of high thermal 

maturity. This is particularly true in deep basins and thrust 

belts where sealing strata may be exposed to high-temperature mineral transformations and tectonic deformations 

that influence sealing properties. Seal effectiveness has 

been the topic of numerous papers, including recent overviews by Downey (1984) and Vavra and others (1992), but 

the emphasis has been placed on capillary properties as 

they now exist in seals. Seal longevity also has received 

considerable attention in recent years, with the emphasis 

on hydrocarbon diffusion through seals and consequences 

to gas leakage from reservoirs (Leythaeuser and others, 

1982; Krooss and others, 1992; Nelson and Simmons, 

1992). Despite these research achievements that have 

enhanced our understanding of seals, there has been no 

concentrated effort devoted to determining how the effectiveness and longevity of seals are influenced by elevated 

temperatures, abnormal fluid pressures, and high confining 

and (or) tectonic pressures that accompany deep burial in 

sedimentary basins and thrust belts. 

Evaluation of the potential of natural-gas resources in 

areas of extreme thermal maturity and development of exploration strategies to test that potential require a better 

understanding of geologic processes that influence natural 

gas in deep reservoirs, under high-temperature conditions. 

Research is needed in at least three fundamental topics: 

( 1) Dilution of methane by natural nonhydrocarbon gases 

at high temperatures and thermal maturities, including 

considerations of the origin, migration, and accumulation 

of methane, nitrogen, and carbon dioxide. (2) Deep-burial, 

high-temperature diagenesis of reservoir rocks, including 

considerations of the timing of hydrocarbon migration and 

accumulation relative to diagenetic events that destroy or 

enhance porosity and the roles of subsurface pressures and 

fluid migration (both water and hydrocarbons) on reservoir 

porosity histories. (3) Deep-burial, high-temperature diagenesis of seals, including interdependence of high-temperature mineral transformations, evolution of capillary 

properties, influence of dynamic fluid-pressure regimes, 

and response to tectonic deformation. 

CONCLUSIONS 

Theoretical, experimental, and empirical evidence indicates that methane is not chemically destroyed by temperatures high enough to produce vitrinite reflectance in 

the 4 to 5 percent range, although in reservoirs with high 

water saturation, methane may be consumed in a reaction 

with water to yield carbon dioxide and hydrogen. Methane 

may be diluted to noneconomic concentrations by nitrogen 

and carbon dioxide in certain geologic settings and at vitrinite reflectance levels above 4 percent. 

Prolific methane production in the Arkoma Basin and 

Ouachita frontal thrust belt occurs in strata with thermal 

maturities of up to at least 4 percent vitrinite reflectance. 

Wells drilled in strata near the presently defined upper 

thermal-maturity limit of methane production are some of 

the most prolific in the region, suggesting that economic 

methane production will be extended to strata with thermal maturities above 4 percent vitrinite reflectance with 

additional drilling. This natural-gas province provides evidence that excellent reservoir quality has been preserved 

to extreme levels of thermal maturity because reservoired 

hydrocarbons inhibited inorganic diagenetic reactions. 

Geologic processes that influence natural gas and its 

habitat during exposure to deep burial, high temperatures, 

and tectonic deformation are poorly understood. Evaluation of the potential of natural-gas resources in geologic 

provinces characterized by extreme thermal maturity and 

development of exploration strategies to test that potential 

require focused research on (I) the origin, migration, and 

accumulation of methane and nonhydrocarbon gases during metagenesis; (2) diagenesis of reservoir rocks exposed 

to deep burial and high temperatures; and (3) effectiveness 

and longevity of seals exposed to deep burial, high temperatures, and tectonic deformation. 

ACKNOWLEDGMENTS 

Much of this work was performed at the University of 

Missouri as part of the Arkoma Basin Thermal Maturity 

Research Program, funded by Amoco, Anadarko, Arco, 

Arkla, Conoco, Exxon, Maxus, Mobil, Nomeco, Oxy, Pennzoil, Shell, Texaco, Weyerhaeuser, and Yates petroleum 

companies. D.W. Houseknecht thanks the following 

former and current students who contributed to data collection: Lori Hathon, Paul Kastens, Chris Weesner, and 
EMPIRICAL OBSERVATIONS REGARDING METHANE DEADLINES IN DEEP BASINS AND THRUST BELTS 229 

Robert Jaques. We thank Neil Suneson (Oklahoma Geological Survey), Russ Cunningham (GHK Corp.), and Dan 

Patterson (Arco) for providing information from recent 

drilling activities, and Gregory Ulmishek for translating 

pertinent Russian literature. The manuscript was improved 

as the result of constructive reviews by Ed Pittman, David 

Howell, and Frances Cole. 

REFERENCES CITED 

Arbenz, J.K., 1989, The Ouachita system, in Bally, A.W., and 

Palmer, A.R., eds., The Geology of North America; An overview: Boulder, Colo., Geological Society of America, The 

Geology of North America, v. A, p. 371-396. 

Arne, D.C., 1992, Evidence from apatite fission-track analysis 

for regional Cretaceous cooling in the Ouachita Mountain 

fold belt and Arkoma Basin of Arkansas: American Association of Petroleum Geologists Bulletin, v. 76, p. 392-402. 

Barker, C., and Takach, N.E., 1992, Prediction of natural gas 

composition in ultradeep sandstone reservoirs: American Association of Petroleum Geologists Bulletin, v. 76, p. 1859-

1873. 

Beebe, B.W., and Curtis, B.F., 1968, Natural gases of North 

America-A summary, in Beebe, B.W., and Curtis, B.F., eds., 

Natural gases of North America: American Association of 

Petroleum Geologists Memoir 9, v. 2, p. 2245-2355. 

Boigk, H., Hagemann, H.W., Stahl, W., and Wollanke, G., 1976, 

lsotopenphysikalische Untersuchungen zur Herkunft und 

Migration des Stickstoffs nordwestdeutscher Erdgase aus 

Oberkarbon und Rotliegend: Erdol und Kohle, Erdgas, Petrochemie, v. 29, p. I 03-112. 

Bostick, N.H., 1979, Microscopic measurement of the level of 

catagenesis of solid organic matter in sedimentary rocks to 

aid exploration for petroleum and to determine former burial temperatures-A review, in Scholle, P.A., and Schluger, 

P.R., eds., Aspects of diagenesis: Society of Economic Paleontologists and Mineralogists Special Publication 26, p. 17-

43. 

Branan, C.B., Jr., 1968, Natural gas in Arkoma Basin of Oklahoma and Arkansas, in Beebe, B.W., and Curtis, B.F., eds., 

Natural gases of North America: American Association of 

Petroleum Geologists Memoir 9, v. 2, p. 1616-1635. 

Branner, G.C., 1937, Sandstone porosities in Paleozoic region in 

Arkansas: American Association of Petroleum Geologists 

Bulletin, v. 21, p. 67-79. 

Burgess, J.D., 1974, Microscopic examination of kerogen (dispersed organic matter) in petroleum exploration, in Dutcher, 

R.R., Hacquebard, P.A., Schopt, J.M., and Simon, J.A. eds., 

Carbonaceous materials as indicators of metamorphism: 

Geological Society of America Special Paper 153, p. 19-30. 

Cardott, B.J ., 1989, Thermal maturation of the Woodford Shale 

. in the Anadarko Basin, in Johnson, K.S., ed., Anadarko 

Basin Symposium, 1988: Oklahoma Geological Survey, Circular 90, p. 32-46. 

Cardott, B.J., and Lambert, M.W., 1985, Thermal maturation by 

vitrinite reflectance of Woodford Shale, Anadarko Basin, 

Oklahoma: American Association of Petroleum Geologists 

Bulletin, v. 69, p. 1982-1998. 

Coleman, D.O., Liu, C.L., and Riley, K.M., 1988, Microbial 

methane in the shallow Paleozoic sediments and glacial deposits of Illinois, U.S.A.: Chemical Geology, v. 71, p. 23-40. 

Cornford, C., 1986, Source rocks and hydrocarbons of the North 

Sea, in Glennie, K.W., ed., Introduction to the petroleum geology of the North Sea: Oxford, Blackwell, p. 197-236. 

Croneis, C., 1927, Oil and gas possibilities in the Arkansas 

Ozarks: American Association of Petroleum Geologists Bulletin, v. 11, p. 279-297. 

Curiale, J .A., 1983, Petroleum occurrences and source-rock potent)al of the Ouachita Mountains, southeastern Oklahoma: 

Oklahoma Geological Survey Bulletin 135, 65 p. 

Davis, H.G., and Northcutt, R.A., 1989, The greater Anadarko 

Basin-An overview of petroleum exploration and development, in Johnson, K.S., ed., Anadarko Basin Symposium, 

Oklahoma Geological Survey Circular 90, p. 13-24. 

Dixon, S.A., Summers, D.M., and Surdam, R.C., 1989, Diagenesis and preservation of porosity in the Norphlet Formation 

(Upper Jurassic), southern Alabama: American Association 

of Petroleum Geologists Bulletin, v. 73, p. 707-728. 

Dow, W.G ., 1977, Kerogen studies and geological interpretations: 

Journal of Geochemical Exploration, v .. 7, p. 79-99. 

Dow, W.G., and O'Connor, D.I., 1982, Kerogen maturity and 

type by reflected light microscopy applied to petroleum exploration, in Staplin, F.L., Dow, W.G., Milner, C.W.O., 

O'Connor, D.I., Pocock, S.A.J., Gijzel, P. van, Welte, D.H., 

and Yi.ikler, M.A., How to assess maturation and paleotemperatures: Society of Economic Paleontologists and Mineralogists Short Course 7, p. 133-157. 

Downey, M.W., 1984, Evaluating seals for hydrocarbon accumulations: American Association of Petroleum Geologists Bulletin, v. 68, p. 1752-1763. 

Epstein, A.G., Epstein, J.B., and Harris, L.D., 1977, Conodont 

color alteration-An index to organic metamorphism: U.S. 

Geological Survey Professional Paper 995, 27 p. 

Everlien, G., and Hoffmann, U., 1991, Nitrogen in natural gas: 

ErdOI, Erdgas, Kohle, Petrochemie, v. 44, p. 166-172. 

Getz, F.A., 1977, Molecular nitrogen-Clue in coal-derivedmethane hunt: Oil and Gas Journal, v. 75, p. 220-221. 

Guseva, A.N., and Fayngersh, L.A., 1973, Conditions of accumulation of nitrogen in natural gases as illustrated by the central European and Chu-Sarysu oil-gas basins: Transactions 

(Doklady) of the USSR Academy of Sciences, Earth Science 

Section (Dokl. Akad. Nauk SSSR), v. 209, p. 210-212. 

Hathon, L.A., and Houseknecht, D.W., 1987, Hydrocarbons in an 

overmature basin, I. Thermal maturity of Atoka and Hartshorne Formations, Arkoma Basin [abs.]: American Association of Petroleum Geologists Bulletin, v. 71, p. 993-994. 

Hayes, J.B., 1991, Porosity evolution of sandstones related to vitrinite reflectance: Organic Geochemistry, v. 17, p. 117-129. 

Hendrick, S.J., 1992, Vitrinite reflectance and deep Arbuckle 

maturation at Wilburton field, Latimer County, Oklahoma: 

Oklahoma Geological Survey Circular 93, p. 176-184. 

Hendricks, T.A., 1935, Carbon ratios in part of Arkansas-Oklahoma coal field: American Association of Petroleum Geologists Bulletin, v. 19, p. 937-947. 

Holmquest, H.J., 1965, Deep pays in Delaware and Val Verde 

basins, in Young, A., and Galley, J.E., eds., Fluids in subsurface environments: American Association of Petroleum Geologists Memoir 4, p. 257-279. 
230 THE FUTURE OF ENERGY GASES 

Hood, A., Gutjahr, C.C.M., and Heacock, R.L., 1975, Organic 

metamorphism and the generation of petroleum: American 

Association of Petroleum Geologists Bulletin, v. 59, p. 986-

996. 

Houseknecht, D.W., 1984, Influence of grain size and temperature 

on intergranular pressure solution, quartz cementation, and 

porosity in a quartzose sandstone: Journal of Sedimentary 

Petrology, v. 54, p. 348-361. 

---1986, Evolution from passive margin to foreland basinThe Atoka Formation of the Arkoma Basin, south-central 

U.S.A., in Allen, P.A., and Homewood, P., eds., Foreland basins: International Association of Sedimentologists Special 

Publication 8, p. 327-345. 

---1987, The Atoka Foimation of the Arkoma Basin-Tectonics, sedimentology, thermal maturity, sandstone petrology: 

Tulsa Geological Society, Short Course Notes, 72 p. 

Houseknecht, D.W., Bensley, D.F., Hathon, L.A., and Kastens, 

P.H., 1993, Rotational reflectance properties of Arkoma Basin 

dispersed vitrinite-Insights for understanding reflectance 

populations in high thermal maturity regions: Organic Geochemistry, v. 20, p. 187-196. 

Houseknecht, D.W., and Hathon, L.A., 1987, Hydrocarbons in an 

overmature basin, II. Is there a thermal maturity limit to 

methane production in the Arkoma Basin [abs.]: American 

Association of Petroleum Geologists Bulletin, v. 71, p. 994. 

Houseknecht, D.W., Hathon, L.A., and McGilvery, T.A., 1992, 

Thermal maturity of Paleozoic strata in the Arkoma Basin: 

Oklahoma Geological Survey Circular 93, p. 122-132. 

Houseknecht, D.W., and Matthews, S.M., 1985, Thermal maturity 

of Carboniferous strata, Ouachita Mountains: American Association of Petroleum Geologists Bulletin, v. 69, p. 335-345. 

Houseknecht, D.W., and McGilvery, T.A., 1990, Red Oak gas 

field, Arkoma Basin, Oklahoma, U.S.A., in Beaumont, E.A., 

and Foster, N.H., eds., Structural traps II, Treatise of petroleum geology, Atlas of oil and gas fields: American Association of Petroleum Geologists, p. 201-225. 

Hunt, J.M., 1975, Is there a geochemical depth limit for hydrocarbons?: Petroleum Engineer, March 1975, p. 112-127. 

---1979, Petroleum geochemistry and geology: Freeman, San 

Francisco, 617 p. 

---1984, Generation and migration of light hydrocarbons: 

Science, v. 226, p. 1265-1270. 

Jemison, R.M., 1979, Geology and development of Mills Ranch 

complex-World's deepest field: American Association of 

Petroleum Geologists Bulletin, v. 63, p. 804-809. 

Jiintgen, H., and Karweil, J., 1966a, Gasbildung und Gasspeicherung in Steinkohlenftozen. I. Gasbildung: Erdtil und 

Kohle, Erdgas, Petrochemie, v. 19, p. 251-258. 

---1966b, Gasbildung und Gasspeicherung in Steinkohlenflozen. II. Gasspeicherung: Erdtil und Kohle, Erdgas, Petrochemie, v. 19, p. 339-344. 

Jiintgen, H., and Klein, 1 ., 1975, Origin of natural gas from coaly 

sediments: Erdtil und Kohle, v. 28, p. 65-73. 

Karweil, 1 ., 1969, Aktuelle Probleme der Geochemie der Kohle, in 

Schenck, P.A., and Havenaar, I., eds., Advances in organic 

geochemistry 1968: Oxford, Pergamon Press, p. 59-84. 

Katz, B.J., Liro, L.M., Lacey, J.E., and White, H.W., 1982, Time 

and temperature in petroleum formation-Application of Lopatin's method to petroleum exploration-Discussion: American Association Petroleum of Geologists Bulletin, v. 66, 

p. 1150-1151. 

Kim, A.G., 1977, Estimating methane content of bituminous 

coal beds from adsorption data: U.S. Bureau of Mines Report of Investigations 8245, 22 p. 

---1978, Experimental studies on the origin and accumulation of coal bed gas: U.S. Bureau of Mines Report of Investigations 8317, 18 p. 

Krooss, B.M., Leythaeuser, D., and Schaefer, R.G., 1992, The 

quantification of diffuse hydrocarbon losses through cap 

rocks of natural gas reservoirs-A reevaluation: American 

Association Petroleum of Geologists Bulletin, v. 76, p. 403-

406. 

Landes, K.K., 1967, Eometamorphism, and oil and gas in time 

and space: American Association Petroleum of Geologists 

Bulletin, v. 51, p. 828-841. 

Lapchinsky, Yu.G., and Dzhamalova, Kh.F., 1987, Gas productivity and geochemical properties of gases in coal-bearing 

areas of the eastern Ukraine, in Trofimuk, A.A., Nesterov, 

1.1., and Zhabrev, J.P., eds., Regularities in distribution of 

hydro-carbon gases and associated components [Zakohomernosti razmeshcheniya uglevodorodnyky gazov i soputstruyushchikh im komponentov]: Moscow, Nauka, p. 98-

104. 

Leythaeuser, D., Schaefer, R.G., and Yiikler, A., 1982, Role of 

diffusion in primary migration of hydrocarbons: American 

Association of Petroleum Geologists Bulletin, v. 66, p. 408-

429. 

Lutz, M., Kaasschieter, J.P.H., and Van Wijhe, D.H., 1975, Geological factors controlling Rotliegend gas accumulations in 

the mid-European Basin, in 7th World Petroleum Congress 

Proceedings (Mexico): London, Elsevier, v. 2, p. 47-60. 

Meckel, L.D., Jr., Smith, D.O., and Wells, L.A., 1992, Ouachita 

foredeep basins-Regional paleogeography and habitat of 

hydrocarbons, in Macqueen, R.W., and Leckie, D.A., eds., 

Foreland basins and fold belts: American Association of Petroleum Geologists Memoir 55, p. 427-444. 

Mo, F.J., Han, L.D., Fen, J.R., and Ding, D.Y., 1984, Distribution 

and origin of hydrocarbons in carbonate rocks (Precambrian 

to Triassic) in China, in Palacas, J.G., ed., Petroleum geochemistry and source rock potential of carbonate rocks: 

American Association of Petroleum Geologists Studies in 

Geology 18, p. 1-12. 

Nelson, J .S., and Simmons, E.C., 1992, The quantification of diffusive hydrocarbon losses through cap rocks of natural gas 

reservoirs-A reevaluation-Discussion: American Association of Petroleum Geologists Bulletin, v. 76, p. 1839-1841. 

Oakes, M.C., and Knechtel, M.M., 1948, Geology and mineral 

resources of Haskell County, Oklahoma: Oklahoma Geological Survey Bulletin 67, 136 p. 

Petersil'ye, I.A., Kozlov, Ye.K., Belyayev, K.D., Sholokhnev, 

V.V., and Dokuchayeva, V.S., 1970, Nitrogen and hydrocarbon gases in ultramafic rocks of the Sopcha stock of the 

Monchegorsk pluton, Kola Peninsula: Transactions (Doklady) of the USSR Academy of Sciences, Earth Science Section (Dokl. Akad. Nauk SSSR), v. 194, p. 200-203. 

Price, L.C., in press, Hydrocarbon thermal stability in natureLimits, evidence, characteristics, and possible controls: 

Geochimica et Cosmochimica Acta. 
EMPIRICAL OBSERVATIONS REGARDING METHANE DEADLINES IN DEEP BASINS AND THRUST BELTS 231 

Price, L.C., Clayton, J.L., and Rumen, L.L., 1981, Organic 

geochemistry of the 9.6 km Bertha Rogers No.I well, Oklahoma: Organic Geochemistry, v. 3, p. 59-77. 

Rice, D.O., and Claypool, G.E., 1981, Generation, accumulation, 

and resource potential of biogenic gas: American Association of Petroleum Geologists Bulletin, v. 65, p. 5-25. 

Rightmire, C.T., 1984, Coal bed methane resources, in Rightmire, C.T., Eddy, G.E., and Kirr, J.N., eds., Coal bed methane resources of the United States: American Association of 

Petroleum Geologists Studies in Geology 17, p. 1-13. 

Saxby, J.D., 1982, A reassessment of the range of kerogen maturities in which hydrocarbons are generated: Journal of Petroleum Geology, v. 5, p. 117-128. 

Schoell, M., 1988, Multiple origins of methane in the earth: 

Chemical Geology, v. 71, p. 1-10. 

Suneson, N.H., and Campbell, J.A., 1990, Oil and gas exploration in the western Ouachita region, Oklahoma: Oil and Gas 

Journal, v. 88, no. 15, p. 65-69, and no. 16, p. 85-87. 

Suneson, N.H., Campbell, J.A., and Tilford, M.J., 1990, Geology 

and resources of the frontal belt of the western Ouachita 

Mountains, Oklahoma: Oklahoma Geological Survey Special 

Publication 90-1, 196 p. 

Takach, N.E., Barker, C., and Kemp, M.K., 1987, Stability of 

natural gas in the deep subsurface-Thermodynamic calculation of equilibrium compositions: American Association of 

Petroleum Geologists Bulletin, v. 71, p. 322-333. 

Tarafa, M.E., Whelan, J.K., and Farrington, J.W., 1988, Investigation on the effects of organic solvent extraction on wholerock pyrolysis-Multiple-lobed and symmetrical P2 peaks: 

Organic Geochemistry, v. 12, p. 137-149. 

Teichmi.iller, M., Teichmi.iller, R., and Hartenstein, H., 1979, 

Inkohlung und Erdgas in Nordwestdeutschland. Eine 

Inkohlungskarte der Oberfliiche des Oberkarbons: Fortschritte Geologie Rheinland und Westfalen, v. 27, p. 137-170. 

---1984, Inkohlung und Erdgas-Eine neue Inkohlungskarte 

der Karbon-Oberfliiche in Nordwestdeutschland: Fortschritte 

Geologie Rheinland uud Westfalen, v. 32, p. 11-34. 

Teichmi.iller, M., Teichmi.iller, R., and Lorenz, V., 1983, 

Inkohlung und Inkohlungsgradienten im Permokarbon der 

Saar-Nahe-Senke: Zeitschrift der Deutschen Geologischen 

Gesellschaft, v. 134, p. 153-210. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and occurrence: New York, Springer-Verlag, 699 p. 

Ulmishek, G.F., Bogino, V.A., Keller, M.B., and Poznyakevich, 

Z.L., in press, Structure, stratigraphy, and petroleum geology 

of the Pripyat and Dnieper-Donets basins, Byelarus and 

Ukraine: American Association of Petroleum Geologists 

Memoir. 

Underwood, M.B., Fulton, D.A., and McDonald, K.W., 1988, 

Thrust control on thermal maturity of the frontal Ouachita 

Mountains, central Arkansas, USA: Journal of Petroleum 

Geology, v. II, p. 325-340. 

Van Wijhe, D.H., Lutz, M., Kaasschieter, J.P.H., 1980, The Rotliegend in the Netherlands and its gas accumulations: Geologie en Mijnbouw, v. 59, p. 3-24. 

Vavra, C.L., Kaldi, J.G., and Sneider, R.M., 1992, Geological applications of capillary pressure-A review: American Association of Petroleum Geologist Bulletin, v. 76, p. 840-850. 

Viele, G.W., and Thomas, W.A., 1989, Tectonic synthesis of the 

Ouachita orogenic belt, in Hatcher, R.D., Jr., Thomas, W.A., 

and Viele, G.W., eds., The Appalachian-Ouachita Orogen in 

the United States: Boulder, Colo., Geological Society of 

America, The Geology of North America, v. F-2, p. 695-728. 

Waples, D.W., 1980, Time and temperature in petroleum formation-Application of Lopatin's method to petroleum exploration: American Association of Petroleum Geologists 

Bulletin, v. 64, p. 916-926. 

Wehner, H., Damberger, H., Leythaeuser D., Welte, D.H., 1976, 

Organisch-geochemische Untersuchungen an Kohlen, Gesteinen und Restgasen aus der Bohrung Saar 1: Geologisches 

Jahrbuch, v. A27, p. 455-488. 

Welte, D.H., Schaefer, R.G., and Yal~in, M.N., 1988, Gas generation from source rocks-Aspects of a quantitative treatment: Chemical Geology, v. 71, p. I 05-116. 

White, D., 1915, Some relations in origin between coal and petroleum: Journal of the Washington Academy of Sciences: 

v. 5, p. 189-212. 

Wilson, C.W., Jr., 1935, Age and correlation of Pennsylvanian 

surface formations and of oil nad gas sands of Muskogee 

County, Oklahoma: American Association of Petroleum Geologists Bulletin, v. 19, no. 4, p. 503-520. 

Wilson, L.R., 1961, Palynological fossil response to low-grade 

metamorphism in the Arkoma Basin: Tulsa Geological Society Digest, v. 29, p. 131-140. 

---1971, Palynological techniques in deep-basin stratigraphy: Shale Shaker, v. 21, p. 124-139. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Gas in Tight Reservoirs-An Emerging Major Source of Energy 

By Ben E. Law1 and Charles W. Spence? 

CONTENTS 

Abstract ......................................................................... 233 

Introduction ................................................................... 233 

Characteristics of Tight Reservoirs ............................. 234 

Gas Quality and Source ................................................ 236 

Drilling and Completion Practices ............................... 237 

Estimates of Gas Resources ......................................... 238 

Selected Examples of Tight-Reservoir Gas 

Accumulations ... .. .. ... .. ...... ...... .... .. ... . . ........ ..... ... . .... .. .. .. 240 

Northern Great Plains ............................................ 240 

Greater Green River Basin .................................... 242 

Appalachian Basin ................................................. 244 

East Texas and North Louisiana Basins ................ 247 

Summary .. . ... .. .. ..... ... ... . .. .. .. .... .. .. .. .... ... . .. ... ..... .. .. .. . ..... .. . 249 

Acknowledgments ........................................................ 249 

References Cited ... ... .... .. .... ...... .... ..... ... .. ... . .... .. .. .. . ... .. . .. 250 

ABSTRACT 

Low-permeability (tight) gas reservoirs are gas-bearing rocks that usually have an in-situ permeability to gas, 

exclusive of fracture permeability, of less than 0.1 millidarcy (mD). In the United States these reservoirs are estimated to contain in-place gas resources of at least 420 

trillion cubic feet (Tcf) and possibly more than 5,000 Tcf. 

Estimates of recoverable gas in the United States range 

from less than 200 to more than 550 Tcf. 

1

U.S. Geological Survey, MS 971, P.O. Box 25046, Denver, CO 

80225. 2U.S. Geological Survey, MS 940, P.O. Box 25046, Denver, CO 

80225. 

Tight gas reservoirs occur in nearly all petroleum 

provinces. They occur at virtually all depths and in a variety of rock types that include sandstone, siltstone, shale, 

sandy carbonate rocks, limestone, dolomite, and chalk. 

Tight gas reservoirs may be thick and areally extensive or 

thin and areally limited. In contrast to normal (conventional) gas accumulations where the gas is concentrated in 

structural or stratigraphic traps, gas in tight reservoirs occurs as regionally pervasive accumulations that are usually 

abnormally pressured and are mostly independent of structural and stratigraphic traps. Artificial stimulation, such as 

hydraulic fracturing, is usually needed in order to produce 

the gas unless extensive fracturing is present. As a consequence of an improved understanding of tight gas reservoirs and improved drilling and completion practices, gas 

from these reservoirs is rapidly emerging as a major 

source of energy. 

INTRODUCTION 

Despite the widespread occurrence of tight gas reservoirs around the world, the development of this resource 

has been largely limited to the United States and Canada. 

The geographic distribution and geologic nature of these 

accumulations are not well known outside North America. 

Therefore, much of the information on tight reservoirs is 

from the North American experience. Although the presence of gas in tight rocks has been known for more than 30 

years, only within the last 10 to 15 years has there been 

any concerted research efforts to geologically characterize 

these rocks. Prior to the oil embargo of 1973, the United 

States had become accustomed to seemingly unlimited 

sources of cheap energy. In 1973, that complacency abruptly ended, and the Nation suddenly became aware of its 

vulnerability to disruptions in the supply of oil and gas. As 

a consequence of the embargo, a major research effort was 

233 
234 THE FUTURE OF ENERGY GASES 

initiated to conserve energy as well as to develop additional sources of energy. As part of that effort, the Department 

of Energy (DOE), then known as the Energy Research and 

Development Administration (ERDA), launched a comprehensive study of tight gas reservoirs in the United States. 

With the support of the DOE, the U.S. Geological Survey 

initiated geologic studies of tight gas reservoirs in the 

Rocky Mountain region. Since then, additional geologic investigations supported by the Gas Research Institute and 

the Texas Bureau of Economic Geology have been conducted in the Texas Gulf Coast area, as well as in the 

Rocky Mountain region. In addition, Canadian Hunter and 

the Canadian Geological Survey have conducted extensive 

research on tight reservoirs in Canada and the United 

States. As a result of this research, there is currently a 

much better understanding of the nature of gas accumulations in tight reservoirs. The objectives of this report are to 

provide information on the nature of occurrence of gas in 

tight reservoirs, to geologically characterize the reservoir, 

and to summarize much of the research that has been conducted on tight gas reservoirs. 

CHARACTERISTICS OF TIGHT 

RESERVOIRS 

The distribution of the principal tight gas reservoirs in 

North America are shown on figure I. Within these areas 

there are three main types of tight gas reservoirs as defined by geologic and engineering parameters. The three 

types are (1) marginal-marine blanket, (2) deep-lenticular, 

and (3) shallow-blanket reservoirs. Many areas have more 

0 

I I I 

MILES 

than one type. These reservoirs are commonly abnormally 

pressured; they are either under- or overpressured with respect to hydrostatic pressures. They also occur at shallow 

to very great depths, ranging from 1 ,000 to more than 

15,000 ft (305-4,575 m). 

Marginal-marine blanket reservoirs may be carbonates 

or sandstones that were deposited in shallow-marine or 

marginal-marine environments (Finley, 1984, 1986; Dutton 

and others, 1993). Examples of marginal-marine reservoirs 

include sandstones such as the Upper Cretaceous Rollins 

Sandstone Member of the lies Formation in the Piceance 

Basin of western Colorado and the Upper Cretaceous Almond Formation in the Green River Basin of Wyoming. 

Marginal-marine blanket reservoirs usually respond to artificial fracturing in a more predictable manner (Spencer, 

1985) than other types of tight reservoirs. 

Lenticular reservoirs include sandstone deposited by 

stream systems. Examples of lenticular reservoirs include 

the Upper Cretaceous Rock Springs and Lance Formations 

in the Green River Basin of Wyoming and the Upper Cretaceous Williams Fork Formation in the Piceance Basin of 

western Colorado. The distribution and nature of individual lenticular reservoirs is difficult to determine, and the effectiveness of artificial stimulation of these rocks is rarely 

predictable using current technology (Spencer, 1985). The 

results of stimulation in this type of reservoir range from 

poor to good. Marginal-marine and lenticular type reservoirs are nearly always abnormally under- or overpressured and commonly occur at depths greater than 7,000 ft 

(2,135 m). 

Shallow-blanket reservoirs, exclusive of gas-bearing 

shales in the eastern United States, consist of very fine 

500 

I 

Figure 1. Principal gas-bearing, tight-reservoir regions (shaded) in the United 

States. 
GAS IN TIGHT RESERVOIRS-AN EMERGING MAJOR SOURCE OF ENERGY 235 

grained sandstone, siltstone, silty shale, and chalk that 

were deposited in open-marine or marine-shelf environments (Rice and Shurr, I980; Spencer, I985). They occur 

at shallow depths, less than 4,000 ft (1 ,220 m), and many 

of these reservoirs have subnormal pressure. Subsurface 

correlation of these strata is usually easy. Shallow-blanket 

reservoirs are being actively developed in the southern 

plains area of Alberta and Saskatchewan, Canada, and to a 

lesser extent in eastern Montana. In the United States 

these tight reservoirs are present in the northern Great 

Plains and eastern Plains regions (fig. I). Shallow-blanket 

reservoirs in the United States are estimated to contain recoverable resources of about I 00 trillion cubic feet (Tcf) 

of gas (National Petroleum Council, I980; Rice and Shurr, 

I980). 

It is generally accepted that tight gas reservoirs are 

rocks that have an in-situ permeability to gas of 0.1 millidarcy (mD) or less, exclusive of fracture permeability. 

However, there is a full continuum of permeabilities ranging from those of conventional reservoirs to those of very 

tight reservoirs (from >500 mD to <0.0005 mD). Rocks 

with intermediate permeabilities in this continuum are 

commonly described as "near tight" (fig. 2). In some basins, slight differences in sedimentology, diagenetic histories, and natural fracturing have created local areas of 

enhanced permeability, referred to as "sweet spots," in an 

otherwise tight reservoir. Identifying these "sweet spots" 

is, therefore, a prime exploration objective. 

The porosity of tight reservoirs can range from less 

than 5 percent in sandstones, shales, and carbonates to 

more than 25 percent in chalks. Spencer (I985) has identified two main porosity types. One type has low porosity 

(generally <I2 percent), low permeability, and high capillary pressure as the result of postdepositional cementation 

(diagenesis) of conventional reservoir rocks. The second 

type has high porosity (15 to >35 percent) and low permeability to gas because the rock is very fine grained. The 

fine grain size causes the reservoir rock to have a high 

pore-wall surface area and abundant very small (generally 

<IO micrometers) intergranular pore spaces coated with 

CONVENTIONAL 

RESERVOIRS 

100.0 10.0 

UNCONVENTIONAL 

RESERVOIRS 

1.0 0.1 0.01 0.001 0.0001 

IN-SITU PERMEABILITY TO GAS, IN MILLIDARCIES 

Figure 2. Permeability continuum in conventional through unconventional gas reservoirs. 

water. These rocks generally have high capillary pressures 

because of their fine grain size. 

The lenticular and marginal-marine blanket rocks are 

the low-porosity type, and the shallow-blanket reservoirs 

are the high-porosity type. The low-porosity reservoirs are 

usually found at depths greater than 7,000 ft (2, 135 m), 

whereas shallow-blanket reservoirs are found at depths 

generally less than 4,000 ft (<1,220 m). 

A photomicrograph of a conventional sandstone reservoir from the Lower Cretaceous Muddy Sandstone in the 

Powder River Basin of Wyoming is shown in figure 3. In 

these conventional reservoirs it is easy to visualize how 

gas can move freely from the pores (blue color) into a 

wellbore. In contrast, a photomicrograph of a typical lowporosity sandstone reservoir from the Upper Cretaceous 

Ericson Sandstone, Green River Basin, Wyoming, is 

shown in figure 4. In this type of reservoir, the pores are 

Figure 3. Photomicrograph of conventional sandstone reservoir 

that has been impregnated with blue epoxy. The epoxy fills the 

rock pore space. In the subsurface, this pore space is mostly 

filled with gas and the grains are coated with water. Sample is 

from the Lower Cretaceous Muddy Sandstone, Powder River 

Basin, Wyoming. 
236 THE FUTURE OF ENERGY GASES 

Figure 4. Photomicrograph of low-porosity-type, tight gas reservoir. The pores have been impregnated with blue epoxy. In the 

subsurface the gas resides in the blue areas, and these widely 

scattered pores (mostly secondary) are poorly connected by 

sheet-like capillaries. The pore walls are coated with water, and 

most of the capillaries are completely filled with water. Sample 

is from the Upper Cretaceous Almond Sandstone, Washakie 

Basin, Wyoming. 

poorly connected and fluid flow is difficult. In low-porosity reservoirs, much of the porosity is secondary and developed as a consequence of dissolution of rock framework 

grains or cement. In contrast, primary (intergranular) pores 

characterize the high-porosity reservoirs. The low-porosity 

reservoirs are almost always naturally fractured, and the 

fractures have permeability orders of magnitude greater 

than that of the rock matrix. 

In conventional gas traps, gas normally migrates to 

structurally higher areas because of the very high buoyancy of gas in water. Consequently, discrete gas/water contacts develop in conventional gas accumulations. Most 

tight reservoirs, however, have such low permeabilities 

that gas cannot migrate by buoyancy, and gas accumulations are, therefore, widely distributed through the reservoir with no discrete gas/water contact. Indeed, tight gas 

GAS-BEARING 

Figure 5. Schematic illustration showing relation between gas 

and water occurrence in basin-centered gas accumulation. Abnormally pressured, gas-bearing reservoir occupies deeper parts of 

basin and is downdip from water-bearing, normally pressured 

reservoir. Note gas- and water-bearing transition zone between 

the downdip, gas-bearing tight reservoir and the updip, waterbearing conventional reservoir. Modified from Masters (I 979). 

accumulations of the deeper, basin-center type are characterized by being downdip from water-bearing reservoirs. 

Typically, the updip water-bearing reservoirs are separated 

from the downdip gas-bearing reservoirs by an interval as 

thick as 2,000 ft (610 m) of mixed gas- and water-bearing 

reservoirs (fig. 5). As a consequence of the low permeability and the inability of the gas to accumulate by buoyancy, 

structural and stratigraphic traps are of secondary importance in tight reservoirs. 

GAS QUALITY AND SOURCE 

The gas contained in tight reservoirs is predominantly 

methane, typically more than 85 percent, with very low 

amounts of ethane and higher molecular weight hydrocarbons. Condensate is less common, and oil is rarely found. 

Carbon dioxide is generally present in amounts less than 2 

percent. In most cases the gas is derived from humic, type 

II, or type III organic matter in interbedded coal and shale 

or from disseminated organic matter in the gas reservoir. 

In the deeper tight reservoirs, where the source rocks have 

been exposed to temperatures in excess of 100°C, the gas 

is of a thermogenic origin, and in shallow reservoirs, 

where temperatures have not exceeded I 00°C, the gas is 

commonly of a bacterial origin. 

In nearly all cases where there are sufficient data, the 

source of gas has been determined to be interbedded with or 

adjacent to the reservoir. In tight reservoirs in the western 

United States, interbedded coal, shale, and dispersed organic matter within the reservoir are the most likely sources of 

gas (Law, 1984; Meissner, 1984; Johnson and Rice, 1990). 

In some cases, however, the gas is inferred to have undergone appreciable migration distances from source rocks that 
GAS IN TIGHT RESERVOIRS-AN EMERGING MAJOR SOURCE OF ENERGY 237 

are not interbedded with the reservoir. For example, according to Dutton and others (1987), the source rock for gas in 

tight reservoirs of the Travis Peak Formation in the East 

Texas Basin may have been underlying shales in the Jurassic Bossier Formation or carbonates of the Jurassic Smackover Formation, or both. Dutton and others (1987) further 

speculated that the gas may have been derived directly from 

these source rocks or that the gas may have been derived 

indirectly from these source rocks by the thermal cracking 

of oil, subsequent to the accumulation of oil in the Travis 

Peak Formation. 

DRILLING AND COMPLETION 

PRACTICES 

Tight reservoirs almost always need some type of artificial stimulation or special drilling and completion method in order to produce gas in commercial .quantities. As 

noted earlier, production from tight reservoirs is strongly 

dependent on the presence of natural fractures. The open 

natural fractures are almost always vertical. The ideal 

completion technique is one that will connect the wellbore 

to the natural fracture system in the least damaging manner. The most commonly used technique has been artificial 

hydraulic fracturing. Hydraulic fracturing involves injecting a slurry of a proppant (usually well-sorted, clean sand) 

suspended in a liquid carrying medium. The mixture is injected at a pressure higher than the natural fracture gradient of the reservoir rock so that cracks will propagate 

away from the wellbore in two directions (commonly 

called wings); the wings are oriented 90° to the minimum 

horizontal stress direction. 

This stimulation method has worked reasonably well 

in blanket reservoirs and near-tight reservoirs. The method, however, has generally not worked in a predictable 

manner in shale or lenticular sandstone reservoirs. In other 

words, the actual results of the stimulation do not conform 

to the design model. One of the problems encountered 

during fracture treatment is the inability to create crossfractures that effectively connect the dominant, throughgoing fracture set. The fractures created during artificial 

stimulation are usually parallel to the dominant fracture 

set, with minimal development of cross-fractures connecting the principal fracture set. This results in an anisotropic 

drainage pattern with little or no gas production perpendicular to the dominant fracture direction. 

Historically, drilling and completion practices have 

evolved parallel with our improved understanding of the 

nature of gas accumulations in tight reservoirs. Some of 

the earliest attempts to economically produce gas from 

tight reservoirs used nuclear explosives to fracture gas reservoirs. Information concerning these nuclear tests are 

found in articles by Randolph (1973, 1974a, b, c). The 

first nuclear stimulation was referred to as the Gasbuggy 

Project, conducted in 1967 in the San Juan Basin of New 

Mexico. In that effort, a 29-kiloton explosive was detonated at a depth of 4,240 ft (l ,290 m) in the Upper Cretaceous Lewis Shale/Pictured Cliffs Sandstone interval. Two 

more such projects, the Rulison Project (1969) and the Rio 

Blanco Project (1973), were conducted in the Piceance 

Basin of western Colorado. These projects used explosive 

forces of 43 and 30 kilotons, respectively, and were detonated in the Upper Cretaceous Mesaverde Group and the 

Tertiary Fort Union Formation. A fourth nuclear stimulation, referred to as the Wagon Wheel Project, in the Green 

River Basin of southwestern Wyoming was planned but 

never materialized because of disappointing production 

tests from the first three wells and the concern about 

health issues related to radioactive contamination. 

As an alternative to nuclear stimulation, several very 

large, massive hydraulic fracturing experiments were attempted. The objective of these experiments was to create 

very large hydraulic fractures and stimulate great thicknesses of tight rocks, thereby producing more gas at higher 

rates. 

The definition of massive fracturing varies somewhat, 

but the intention was to create fractures of combined wing 

lengths of 2,000 to 4,000 ft (610-1,220 m). Proppant volumes (measured by weight) of more than 300,000 lbs 

(136,050 kg) were typical. After much research and practical field testing, it was determined that these stimulations 

work fairly well where the reservoir is bounded above and 

below by shales that have a much higher fracture gradient 

(resistance to fracturing) than the fracture gradient of the 

objective reservoir. Under these bounding conditions, the 

artificial fractures could then be contained within the reservoir by the shales. Such reservoirs were called "blanket" 

reservoirs by stimulation engineers because they responded to fracturing in a predictable manner. 

The massive fracture techniques have not worked well 

in thick sequences of lenticular rocks because the fractures 

"grow out of zone," that is, they do not propagate away 

from the wellbore in a predictable manner and they tend to 

be short and tall. Proppant embedment into the interb~dded shales during fracturing also tends to decrease gas 

flow rates (Spencer, 1989a). 

Finally, the general recognition of the importance of 

natural fractures to commercial gas recovery has focused 

attention on attempts to intersect the fracture system with 

horizontal or slant (inclined) wells. Horizontal and (or) 

slant wellbores can intersect more open, vertical fractures 

than a vertical well. This deviated well technology is currently being evaluated at the U.S. DOE Multiwell Experiment site in the Piceance Basin of western Colorado (fig. 

1). At this site, a slant hole was drilled through lenticular 

tight gas reservoirs. The hole was then deviated to horizontal in a blanket reservoir. In the slant-hole portion of 

the hole, 266 ft (81 m) of core was taken and 52 fractures 

were reported, many open to partially open (Lorenz and 
238 THE FUTURE OF ENERGY GASES 

Hill, 1991 ). In comparison, a nearby vertical hole, drilled 

through the same interval, encountered one fracture. In the 

horizontal portion of the hole, 115 ft (35 m) of core was 

recovered. This horizontal core contained 37 vertical extension fractures, most of which were open (Lorenz and 

Hill, 1991). 

Deviated drilling in tight gas reservoirs is at a very 

early stage of development but will likely be used much 

more extensively in the future. Slant-hole drilling probably 

will be the method of choice for developing lenticular reservoirs, and horizontal drilling will be the best method in 

many blanket-like, marginal-marine and marine sandstones 

(Karl-Heinz Frohne, oral commun., 1987). Improved gas 

prices ahd lower completion costs will make deviated 

drilling more economic. 

ESTIMATES OF GAS RESOURCES 

The spot shortages of natural gas in the early 1970's 

focused attention on the large unconventional gas resources in the United States and, in particular, on tight gas reservoirs. Estimates of the in-place gas resources in tight 

reservoirs in the United States range from 335 to 5,486 

Tcf (table 1 ). Estimates of recoverable gas from these reservoirs in the United States range from less than 200 to 

more than 550 Tcf. The wide range of estimates is primarily due to uncertainties about the nature of the gas accumulations, differences in assessment methodologies, and 

the number of basins, formations, and wells evaluated. 

However, regardless of the large range of estimates, the 

resource is very large. Annual production from this large 

gas resource has been increasing for several years. For example, production of gas from tight reservoirs in 1990 was 

about 1. 7 Tcf, or about 10 percent of the total gas produced in the United States (National Petroleum Council, 

1992). The National Petroleum Council (1992) projected 

that by the year 2000 the proportion of gas produced from 

tight reservoirs would increase to about 11 percent of the 

total ga_s produced in the United States. 

The first attempt to determine the magnitude of the 

resource was conducted in 1973, by the Federal Power 

Commission (FPC). The FPC estimated in-place gas resources of 596 Tcf from only three Rocky Mountain area 

basins (Supply-Technical Advisory Task Force, 1973). The 

basins analyzed were the Greater Green River, Piceance, 

and Uinta (table 1). No estimates were made of the 

amount of gas recoverable from each basin. However, various scenarios were presented relative to recovery from 

hypothetical wells, including wells stimulated with nuclear 

explosives. 

Kuuskraa and others (1978) studied the gas resources 

in tight reservoirs in 13 basins in the western United States, 

and they estimated in-place gas resources in the 13 basins 

of 411 Tcf (table 1). They considered that 211 Tcf, or about 

50 percent, of the gas in place was technically recoverable 

from the study basins using future technology. They considered that somewhat less than this volume, however, should 

actually be considered recoverable. In this regard, Kuuskraa and others ( 1978) assessed the recoverable resource 

Table 1. Comparison of estimates of in-place gas resources in tight reservoirs in the United States. 

[Values in trillion cubic feet. Sources: FERC, Federal Energy Regulatory Commission (Supply-Technical Advisory Task Force. 1978); FPC. Federal Power 

Commission (Supply-Technical Advisory Task Force. 1973); JCF, ICF-Lewin, Inc. (Haas, 1990); NPC. National Petroleum Council (1980); USGS, U.S. 

Geological Survey (Johnson and others, 1987; Law and others. 1989). ···,not determined. Modified from National Petroleum Council (1992)] 

Source 

Basin 

Northern Great Plains/Williston·· 

Greater Green River···············-

Uinta ···········-······················ 

Piceance······························ 

Wind River ·················-········ 

Big Horn-········-··················· 

Douglas Creek-······················ 

Denver-······························· 

San Juan---··························· 

Ozona---···········-·················· 

Sonora ·············-·-················ 

Edwards Lime-·····················-

Cotton Valley Sweet-····-·········· 

Cotton Valley Sour ········-········ 

Ouachita---·······-····-···-···-······ 

Other··············----················ 

Total ---··········-·········-···-

FPC 

(1973) 

240 

207 

149 

596 

FERC 

(1978) 

130 

240 

210 

ISO 

63 

793 

Kuuskraa and others 

(1978) 

74 

91 

50 

36 

3 

24 

3 

19 

15 

24 

53 

14 

5 

411 

NPC 

(1980) 

148 

136 

20 

49 

34 

13 

3 

4 

14 

22 

481 

925 

USGS 

(1987. 1989) 

5,063 

423 

5,486 

ICF 

(1990) 

287 

17 

31 

335 
GAS IN TIGHT RESERVOIRS-AN EMERGING MAJOR SOURCE OF ENERGY 239 

using two models: (1) base-case technology and (2) advanced-case technology. Their base-case model assumed 

the level of technology anticipated to be developed by industry from 1979 to 1984 without additional Federal technological research. Their advanced case was based on "the 

level of the technology expected to be attained by virtue of 

active federal-industry collaboration" (Kuuskraa and others, 1978). The maximum price for gas considered was 

$4.50 per thousand cubic feet (Mcf) in 1978 dollars. Using 

the base case, tight gas reservoirs in the basins studied were 

estimated to ultimately yield 107.5 Tcf, and the advancedcase estimate was 187.7 Tcf (Kuuskraa and others, 1978). 

The tight gas reservoirs were not well defined at the time of 

the study by Kuuskraa and others ( 1978), and a small but 

poorly defined amount of the reservoir volume they studied 

has permeability higher than 0.1 mD. 

In 1978, the Federal Energy Regulatory Commission 

(FERC) studied gas resources from various unconventional sources (Supply-Technical Advisory Task Force, 1978). 

The FERC accepted the tight-sandstone formation gas estimates of about 600 Tcf of in-place gas resources in three 

basins appraised by the previous Supply-Technical Advisory Task Force (1973) and added 63 Tcf of in-place gas 

in the San Juan Basin, New Mexico, and an additional 130 

Tcf of in-place gas for the northern Great Plains shallow 

gas in Montana and North Dakota. These additions yield a 

total in-place gas resource estimate of 793 Tcf for the five 

basins and areas. 

In 1980, the National Petroleum Council Committee 

on Unconventional Gas Resources published estimates of 

recoverable resources in tight gas reservoirs in 1 r'3 gasproducing provinces and basins in the United States, both 

onshore and offshore in the lower 48 States (National Petroleum Council, 1980). However, only 12 basins, also in 

the western United States, were appraised in detail. The 

data from these 12 basins were then extrapolated to provide a resource figure for the other I 01 areas, resulting in 

a total estimate of 925 Tcf of in-place gas in the 113 basins (table 1). The National Petroleum Council estimated 

that there were 12 Tcf of already proven (identified) reserves and 574 Tcf of economically recoverable undiscovered tight gas in the 113 areas and basins. The 574 Tcf 

estimate was derived assuming advanced technology and 

using a gas price of $9.00/Mcf in 1979 dollars and a ISpercent rate of return on investment. 

The National Petroleum Council (1992) subsequently 

published an extensive report of all sources of natural gas 

in the United States. The report included both conventional and unconventional sources of natural gas. The National 

Petroleum Council estimated that tight gas reservoirs (not 

including eastern United States gas shales) in the lower 48 

States contained 349 Tcf of technically recoverable gas. 

However, some areas were excluded in this assessment. 

The northern Great Plains was the most notable omission. 

Independent studies by the U.S. Geological Survey (Rice 

and Shurr, 1980) and the National Petroleum Council 

( 1980) estimated about I 00 Tcf of undiscovered recoverable gas in this area. 

The term "undiscovered," as applied to gas in tight 

reservoirs, is misleading since most of the areas included 

in the resource assessment have dry holes drilled through 

at least part of the potential tight reservoir section. These 

wells commonly had encountered gas shows and (or) tested noncommercial volumes of gas on drillstem tests or 

through perforations. Analysis of these dry holes forms the 

data base upon which much of the assessments were predicated, not only by the National Petroleum Council (1980, 

1992) but also by Kuuskraa and others (1978) and the 

U.S. Geological Survey (Rice, 1980). 

In another assessment of gas in tight reservoirs, the 

U.S. Geological Survey estimated in-place gas resources 

for two basins. The Survey estimated 423 Tcf for the 

Piceance Basin (Johnson and others, 1987) and 5,063 Tcf 

for the Greater Green River Basin (Law and others, 1989). 

The combined estimate of 5,483 Tcf for the Piceance and 

Greater Green River Basins is several times greater than 

the largest previous estimate of in-place gas for the entire 

United States. These estimates were based on extensive 

geologic studies that relied heavily on empirically derived 

relations between the occurrence of gas-bearing tight reservoirs and abnormal pressures. In the northern Great 

Plains, the U.S. Geological Survey (Rice and Shurr, 1980) 

estimated recoverable gas from shallow, tight reservoirs at 

more than 100 Tcf. The Survey did not estimate the inplace gas resources. The National Petroleum Council 

(1980) estimated in-place gas resources in the northern 

Great Plains at 147.7 Tcf. 

The wide variation between the lowest estimate of recoverable gas in the United States (187.7 Tcf; Kuuskraa 

and others, 1978) and the highest estimate (574 Tcf; National Petroleum Council, 1980) is partly related to differences in methods of study, economic factors used, and 

interpreted lateral and vertical extent of the potential reservoir rocks. Another significant factor is the number of basins and formations considered to have potential for 

resources of tight gas. Kuuskraa and others (1978) based 

their resource estimate on 13 such areas, whereas the National Petroleum Council ( 1980) studied 12 western basins 

and extrapolated data to I 01 more basins for a total of 113 

basins. Kuuskraa and others (1978) did not assess gas resources deeper than 12,700 ft (3,870 m), and the National 

Petroleum Council (1980) did not include gas resources 

deeper than 15,000 ft (4,575 m). Tight gas reservoirs are 

present in some basins in excess of 20,000 ft (6,100 m). 

However, 13 western basins and areas studied by Kuuskraa 

and others ( 1978) are essentially the same as the 12 examined by the National Petroleum Council (1980), but it is 

difficult to make a direct comparison of the work because 

of the different approaches to assessment and different 

methods of data presentation. The National Petroleum 
240 THE FUTURE OF ENERGY GASES 

Council (1980) included a very small amount of resources 

in reservoirs with up to 0.3 mD of matrix permeability, but 

most of the assessed gas was in rocks with permeabilities 

of <0.1 mD. For assessment of conventional gas accumulations, there are many productive analogs to draw from and 

a probabilistic methodology can be employed, but similar 

approaches are not entirely appropriate for assessment of 

tight gas reservoirs. The nature of the gas occurrence in 

tight reservoirs does not lend itself to a conventional assessment methodology, in that gas occurs in vertically 

stacked reservoirs that are regional in extent. In conventional reservoirs, the gas occurs in discreet traps. 

At this time, estimates of gas resources in tight reservoirs vary considerably; however, there has been sufficient 

research on these reservoirs in the United States to indicate that the in-place gas resources are large; it seems 

quite likely that currently available estimates of the inplace gas resources in the United States are conservative. 

However, the more important question of how much of 

this large gas resource is recoverable remains problematical. Promising new drilling and completion techniques, 

coupled with more favorable gas prices, may be the key to 

converting this large gas resource into a viable source of 

energy. 

SELECTED EXAMPLES OF TIGHTRESERVOIR GAS ACCUMULATIONS 

The principal regions containing tight gas reservoirs in 

the United States are shown on figure 1. In addition to 

these areas, there are many other areas where tight gas 

112" 110" 108" --------.!__ __ ----l ___ _ 

SWEETGRASS 

HILLS 

PRYOR 

UPLIFT BIG 

HORN 

MTNS 

50 MILES 

SO KilOMETERS 

reservoirs of lesser significance occur. The following discussions of regions containing tight gas reservoirs are selected to provide examples of the different types of tight 

reservoirs. 

NORTHERN GREAT PLAINS 

The most thoroughly studied and best examples of 

shallow, tight gas reservoirs in the United States occur in 

Cretaceous rocks in the northern Great Plains (figs. 1, 6). 

In this region of approximately 120,000 mi2 (311 ,000 

km2), Cretaceous tight reservoirs occur at depths less than 

4,000 ft (1 ,220 m). The reservoirs, composed of sandstone, 

siltstone, shale, chalk, and limestone, were deposited on 

the shelf of the north-south-elongated Western Interior Seaway (Rice and Shurr, 1980). In ascending stratigraphic 

order, the reservoirs of primary importance include the 

Lower Cretaceous Mowry Shale and the Upper Cretaceous 

Belle Fourche Shale, Greenhorn Formation, Carlile Shale, 

Niobrara Formation, Gammon Shale, Eagle Sandstone, 

Claggett Shale, and Judith River Formation (fig. 7). The 

thickness of this interval is about 2,000 ft (610 m). Nearly 

all of the structural features in the area developed during 

the Laramide orogeny of Late Cretaceous and early Paleocene time (Rice and Shurr, 1980). 

Within the Cretaceous tight-reservoir interval, the primary tight reservoirs in this area are thin, discontinuous 

sandstone and siltstone beds less than 1 inch (2.5 em) thick 

that are interbedded with shale. Thin, low-permeability 

chalk and limestone reservoirs are of secondary importance. Reservoirs in the northern Great Plains are characterized by high porosity and low permeability; porosities 

47' 

w 

Figure 6. Northern Great Plains area and principal structural features. 
GAS IN TIGHT RESERVOIRS-AN EMERGING MAJOR SOURCE OF ENERGY 241 

range from 15 to 25 percent, and in-situ permeabilities to 

gas are less than 0.1 mD (Rice and Shurr, 1980; Rice and 

others, 1990). According to Rice and Shurr (1980), reservoirs developed in the shelf sandstone, siltstone, and chalk 

facies have the highest gas potential because they are enclosed by thick shales which are the source of the gas and 

also provide a good seal. The gas contained in these shallow reservoirs was generated from the interbedded marine 

shales at low temperatures and is of a bacterial origin (Rice 

and Shurr, 1980). The biogenic gas accumulated in the thin 

interbedded reservoirs. As a consequence of the interbedded nature of source and reservoir rock, the gas accumula-

(f) 

~ 

w 

1-

(f) 

>- (f) 

(f) 

w 

a: 

w 

(f) 

FORMATIONS 

TELEGRAPH CREEK 

FORMATION 

tion is regional in extent and is not dependent on structural 

or stratigraphic traps. 

Currently, gas production from this large area is from 

both conventional and unconventional reservoirs. In the 

western part of the area, in the nonmarine and coastal facies of these Cretaceous tight reservoirs, gas is produced 

from high-permeability, conventional reservoirs. Farther 

east, gas is produced from tight reservoirs in the shelf facies (fig. 8). By analogy with resource estimates in Canada, Rice and Shurr (1980) estimated that tight gas 

reservoirs in the northern Great Plains of the U.S. may 

contain recoverable gas of about 100 Tcf. The National 

PIERRE 

SHALE 

....J 

<{ 

> 

a: 

w 

1-

z 

a: 

6 

(f) 

::::> 

0 

w 

(.) 

<{ 

~~~~~~~~~~~~~~~~~~~ 

> 

a: 

w 

(f) 

w 

a: 

(f) 

<{ 

0 

II 

0 

f= 

tli 

a: 

(.) 

a: 

w 

~ 

0 

....J 

(.) a: i.i5 w (f) 0.. <{ 0.. a: ::::> ::::> 

...., 

..1.. ..1.. ..1.. ..1.. ..1. NIOBRARA FORMATION-'- ..1.. ..1.. ..1.. ..1.. 

~~~~~~~~~~~~~~~~~~~ 

CARLILE SHALE 

~~~~~~~~~~~~~~~~~~~ 

.................. ..L.. ~GREENHORN FORMATION ..L.. ..L.. ..L.. ...... 

~~~~~~~~~~~~~~~~~~~ 

BELLE FOURCHE SHALE 

MOWRY SHALE 

m Unconlormity 

c::J Coastal sandstones 

~ Calcareous rocks 

c:J Marine siltstones 

and shales 

Figure 7. Geologic column for northern Great Plains area showing principal 

tight gas reservoirs. Modified from Rice and Shurr (1980). 
242 THE FUTURE OF ENERGY GASES 

w 180 mi (290 km) 90 mi (1 45 km) 150 mi (240 km) 

GLACIER NATIONAL PARK 

CONVENTIONAL 

RESERVOIRS 

BEAR PAW MTNS. 

UNCONVENTIONAL 

TIGHT RESERVOIRS 

E 

...... Figure 8. Diagrammatic cross section extending 

eastward from Glacier National Park through the 

northern Great Plains area. Tight gas reservoirs include the interval from the Lower Cretaceous Mowry 

Shale through the Upper Cretaceous Judith River Formation. Within this rock interval, the area west of the 

Bearpaw Mountains contains conventional gas reservoirs and the area east of the Bearpaw Mountains 

contains tight gas reservoirs. Modified from Rice and 

Shurr ( 1980). 

METERS FEET 

50 roo 

0 0 

43° 

E'Z2J NONMARINE ROCKS 

c::::::J COASTAL SANDSTONE 

~~~ ~~ ~ CALCAREOUS SHALE 

110° 109° 

i2ZLJ Ms'1r~~~~~ALE AND 

IIII!] CHALK AND LIMESTONE 

108° 107° 

EXPLANATION 

.....A.._...A_ Thrust fault-Sawteeth 

on upper plate 

GREAT DIVIDE 

BASIN 

WAMSUTTER ARCH 

10 20 30 40 50 MILES ,·,,·I·, I I 

50 KILOMETERS 

Figure 9. Map of Greater Green River Basin showing major 

structural elements, subbasins, and location of cross sections AA' (fig. II) and B-B' (fig. 12). Modified from Law and others 

(1989). 

Petroleum Council (1980) assessed a similar volume of recoverable gas. 

GREATER GREEN RIVER BASIN 

The Greater Green River Basin of southwestern Wyoming (figs. 1, 9) is an example of a basin-centered gas 

accumulation. Common characteristics of this type of gas 

accumulation include the following: (1) gas is downdip 

from water-bearing reservoirs; (2) the reservoirs are either 

under- or overpressured; (3) water saturation is at irreducible (immobile) levels; (4) gas is the pressuring phase; (5) 

the gas is of a thermal origin. Other examples of this type 

of gas accumulation include the Piceance (Johnson and 

others, 1987, Spencer, 1989b), Uinta (Fouch and others, 

1992; Nuccio and others, 1992), Wind River, Hanna, San 

Juan (Meissner, 1978, 1984; Masters, 1979), Denver, 

Raton (Dolly and Meissner, 1977; Rose and others, 1986), 

Anadarko, Arkoma, and Appalachian (Davis, 1984; Zagorski, 1988) Basins in the United States and the Alberta 

Basin (Masters, 1979, 1984) in Canada. 

The Greater Green River Basin (fig. 9) is one of the 

largest (19,700 mi2) and better documented basin-centered 

gas accumulations in the United States. It is a composite 

of five smaller basins bounded on the west by the Wyoming Thrust Belt, on the north by the Wind River Moun-
>-

a: 

<{ 

i= 

a: 

UJ 

I-

(/) 

::J 

0 

UJ 

0 

<{ 

1-

UJ 

a: 

(.) 

a: 

UJ 

~ 

0 

_..J 

GAS IN TIGHT RESERVOIRS-AN EMERGING MAJOR SOURCE OF ENERGY 243 

WEST CENTRAL EAST & NORTHEAST SOUTHEAST 

Green River Basin Rock Springs Uplift Great Divide-Washakie Basin Sand Wash Basin 

Fort Union Formation Fort Union Formation Fort Union Formation Fort Union Formation 

~ -~~ - - -~ 

~~";! -~illllJ!flllfW!ru • .wiDJJlDl 

I) Lance Formation Lance Formation 

a: 

UJ 

a.. 

a.. 

::J 

( 

-

~ 

D "'- Fox Hills Sandstone 

) 

~Fox Hills 

~ewis Shale 

Fox Hills Sandstone 

Lewis Shale 

p Lance Formation - Z.... Almond Formation Almond Formation 

r 

"·'cs"" c.;,"""~"'- _,-.. ,PI!Jjj_ I-!IDge~allOSlQ[}£l _........ >x• ...... - ....,. ~CSJ<I.' I - - "': ·""' ~ )~ I - - - - r - 1----A_IIe_n_R_id....:g:....e_F_o_rm_a_ti_on __ _, 

)Sandstone 

~ 

San~stone Haystack Mounta1ns Format1on 

....... ~ 

) Rock 

D Springs 

Rock Springs ~ 

Formation ..&.....-i---:~~ 

) Format.~i':.._~n-4 _____ ,..:5;:----'""' 

-> Blair 

Formation 

Steele Shale 

Lew1s Shale 

Williams Fork Formation 

lies Formation 

-......... 

Mancos Shale 

Mancos (Main body) 

Shale 

Rock Springs 

Formation Baxter Shale 

Hilliard Shale 

Frontier Formation Frontier Formation ~ Frontier Forma~n...,... ~ F~ti~~ation...,..., 

~.fTlii[~~IIJlnll.llJWl p:tl~o~~ - - ~IJ..I,l.J).~ - ~ _, Mowry Shale 

CI: M Sh 1 M Sh 1 M dd s d V Dakota Sandstone 

~ > '-t=~~~o§w~ry~~a~e~~====j=~~~~ow~ry~~a=e~====~~;;~~~;u;;y==a=n~s~to=n=e======~~~~~~~~~~~~ Bear River Formation Thermoplis Shale ...n.. 

O Thermoplis Shale-=:--' - - ~ "" - _..J Cloverly Formation Cloverly Formation Cloverly Formation Cedar Mountain Formation 

Figure 10. Stratigraphic correlation chart of Cretaceous and lower Tertiary tight gas reservoirs in Greater Green River Basin. From 

Law and others (1989). 

tains, on the east by the Rawlins and Park Range uplifts, 

and on the south by the Axial Basin and Uinta Mountains 

uplifts (fig. 9). 

mation (fig. IO). They are composed of sandstone and siltstone that were deposited in fluvial and deltaic 

environments. The top of the tight, gas-bearing rocks has 

been determined to coincide with the top of overpressured 

rocks, at depths ranging from 8,000 to II ,000 ft (2,440-

3,350 m) (Law, I984). The relationship among structure, 

stratigraphy, overpressuring, and occurrence of gas in tight 

reservoirs is shown in figures 11 and I2. In-situ permeability to gas is less than 0.1 mD, and porosity ranges 

Gas occurs in Cretaceous and lower Tertiary rocks that 

are as thick as 14,000 ft (4,270 m). The reservoirs, in ascending order, include the Lower Cretaceous Dakota Formation; the Upper Cretaceous Frontier Formation, 

Mesaverde Group, Lewis Shale, Fox Hills Sandstone, 

Lance Formation, and the lower Tertiary Fort Union For-
244 THE FUTURE OF ENERGY GASES 

FEET 

15,000 

10,000 

5,000 

SEA LEVEL 

-5,000 

-10,000 

-15,000 

SW 

A 

LABARGE 

PLATFORM 

0 

0 2 

4 

10 KILOMETERS 

El Paso Natural Gas 

Wagon Wheel No. 1 

NE 

A' 

METERS 

4,000 

3, 000 

1,000 

SEA LEVEL 

-t ,OOO 

-2,000 

-3,000 

-4,000 

·5.000 

Figure 11. Cross section A-A' through northern part of Green River Basin, showing relationships among structure, stratigraphy, and top 

of overpressured, tight gas reservoirs. Location of section shown on figure 9. Wavy lines are unconformities; arrows show relative 

movement on faults, which are dashed where locations are uncertain; contacts are dashed where uncertain. Modified from Law (1984). 

from 3 to 12 percent (Law and others, 1986; Keighin and 

others, 1989). Porosity is mainly secondary, created by the 

dissolution of unstable framework grains and cements 

(Law and others, 1986; Keighin and others, 1989; Dutton, 

and others, 1992). 

The gas is sourced from interbedded carbonaceous 

shales and coals and is thermogenic (Law, 1984). Empirical relationships show that at temperatures of about 

l00°C and at levels of thermal maturity of about 0.8 percent vitrinite reflectance (percent R0 ), thermally generated 

gas begins to accumulate in the reservoirs at rates greater 

than it is lost. With continued gas generation, mobile 

water is forcibly expelled from the pore. network into 

overlying, normally pressured reservoirs, and a free-gas 

phase forms that eventually develops into an overpressured, gas-saturated reservoir system. The remaining 

water (irreducible water saturation) in the overpressured, 

gas-bearing reservoirs occupies the very small capillaries. 

These types of gas accumulations are not as dependent on 

structural and stratigraphic traps as are conventional gas accumulations. Indeed, the top of overpressured, gas-saturated 

reservoirs crosses structural and stratigraphic boundaries 

(figs. 11, 12). The in-place gas in these thick overpressured sequences is extremely large. The estimate of the 

in-place gas resources in tight overpressured reservoirs in 

the Greater Green River Basin is 5,063 Tcf (Law and 

others, 1989). 

APPALACHIAN BASIN 

The Appalachian Basin is, like the Greater Green 

River Basin, an example of a basin-centered gas accumulation. The Appalachian Basin, however, is different from 

the Greater Green River Basin in that the rocks are Paleozoic rather than Mesozoic and the reservoirs are underpressured rather than overpressured. The basin covers an 

area of about 230,000 mi2 (596,000 km2) and extends 

from New York southwestward to Alabama (fig. 13). The 

eastern edge of the basin is buried beneath the Piedmont 

thrust sheets. The western edge is defined by the Cincinnati and Findlay Arches (fig. 13). The deepest part of the 

basin is located in eastern Pennsylvania. Tight gas reservoirs occur in the Silurian Clinton and Medina sands, the 
GAS IN TIGHT RESERVOIRS-AN EMERGING MAJOR SOURCE OF ENERGY 245 

B 

Da~s 

Amoco 

Champlin 530 

Sec.5,T15N,R98W Koch Gary Sinclair 

1-J Fair Fed. 

B' 

1-Chick.en Springs 1 Adobe Town 

Sec 21,T1SN,R100W Sec.20,T15N,R97W 

Willow Rim 36-10 

Sec.36,T15N,R95W Sec.3,T14N,R92W 

FEET 

8,000 

6,000 

4,000 

2,000 

SEA LEVEL 

-2,000 

-4,000 

-6,000 

-8,000 

-10,000 

·12,000 

-14,000 

-16,000 0 10 

I 

-18,000 0 10 20 

-¢- -¢-

20 MILI;S 

30 KILOMETERS 

older 

FEET 

8,000 

6,000 

4,000 

2,000 

SEA LEVEL 

-2,000 

-4,000 

-B.OOO 

-8,000 

-10,000 

-12,000 

-14,000 

-16,000 

-18,000 

Figure 12. Cross section B-B' through Washakie Basin showing relationships among structure, stratigraphy, and top of overpressured, 

tight gas reservoirs. Location of section shown on figure 9. Wavy lines are unconformities; contacts are dashed where uncertain. 

Modified from Law and others ( 1989). 

Upper Devonian Bradford and Venango Groups of Harper 

and others (1982), and the Mississippian part of the Berea 

Sandstone (fig. 14). 

These rocks were generally derived from source terranes east, southeast, and north of the Appalachian Basin 

(Cotter, 1982; Martini, 1971; de Witt and McGrew, 1979; 

Potter and others, 1983) and deposited in fluvial, deltaic, 

and marginal marine environments (Martini, 1971; Laughrey, 1984; and Laughrey and Harper, 1986). The reservoirs 

are composed of interbedded conglomerate, sandstone and 

mudstone with minor amounts of carbonates. The Clinton 

and Medina sands are about 200 ft (61 m) thick in westem Pennsylvania, thinning to less than 120 ft (37 m) 

northwestward, beneath Lake Erie (Laughrey and Harper, 

1986). Cross section A-A' (fig. 15) shows the change of 

thickness of the Medina and its relationship to the Tuscarora Formation in western Pennsylvania. Upper Devonian 

rocks range from 0 to 5,000 ft (0-1 ,525 m) thick, and the 

Mississippian part of the Berea Sandstone is 20 to 60 ft 

(6-18 m) thick through most of the area where it is designated to be tight (Pepper and others, 1954) The depth to 

the Berea Sandstone ranges from 1,200 ft (366 m) in 

Ohio to 6,000 ft (1,830 m) in West Virginia (Finley, 

1984). 

Productive sandstones are composed of siliceous to dolomitic and calcitic subarkose, sublitharenite, and quartzarenite (Laughrey and Harper, 1986). Porosity is secondary and 

ranges from <2 percent to nearly 12 percent. Permeability 

ranges from 0.01 to 0.16 mD (Laughrey and Harper, 1986). 

The reservoirs are abnormally underpressured with respect 

to hydrostatic pressure gradients of 0.43 psi/ft (pounds per 

square inch per foot) (Russell, 1972; Davis, 1984 ). 

Gas fields producing from these tight reservoirs are 

generally considered to be stratigraphic accumulations 

where permeability discontinuities or facies changes provide the trap. Underpressured gas accumulations in these 

tight reservoirs may be similar to a basin-centered accumulation like the Elmworth Field in Canada (Davis, 1984; 

Zagorski, 1988). Indeed, many of the reservoir characteristics of tight reservoirs in the Appalachian Basin are similar 

to those in other basin-centered gas accumulations. The 

role of natural fractures in gas production is uncertain in 

the Appalachian Basin, although several studies have indicated that natural fractures may be very important to gas 

production (Laughrey and Harper, 1986; Dutton and others, 1993). Laughrey and Harper (1986) also suggested 

that natural fractures may have facilitated the migration of 

gas from source rocks. 
246 

88° 

I 

36°-

34°--!-

100 

I 

50 

I I I 

100 

86° 

I 

38°__:: 

0 

I I I I 

0 

40°-

I 

THE FUTURE OF ENERGY GASES 

82° 

84° 

I 

I 

42°-

~Approximate eastern 

edge of the Eastern 

Overthrust belt 

100 MILES 

I 

80° 

\ 

44°-

100 KILOMETERS 

78° 

\ 

76° 

\ 74° 

\ 

of thrusting 

~Approximate eastern 

edge of the Eastern 

Overthrust belt 

Figure 13. Map of Appalachian Basin (heavy outline) showing major structural elements. Modified from de Witt (1988). 
GAS IN TIGHT RESERVOIRS-AN EMERGING MAJOR SOURCE OF ENERGY 247 

SYSTEM SERIES FORMATION 

UPPER Maxville Limestone 

------ ....__ 

Logan Formation 

z 

<( 

a: 

c... Cuyahoga Formation 

U5 

C/) LOWER 

U5 

C/) 

Sunberry Shale ~ Berea Sandstone 

Bedford Shale 

Ohio I Venango Gp., CatsShale Bradford Gp., and Elk Gp. kill 

UPPER und1v1ded Fm. 

z Olenbngy 

.Ji!r"'Jil!!' m,...... 

.............. Jliiile!J.(m.....,- ::=; ·ulliif'm- ~ 

z Shale Hamilton 

0 MIDDLE ~ t. - Group > w Delaw~e Ls and ~cellusSh. 0 Columbus Ls., ,..., ........ undivided OnondagaGp:--

..J!!>isJ..Ians.J.s. t~~~.ntersvii~M~ 

LOWER ......... - 'Aka~ '!!llt;;m"~--..... 

Helderber.9 Is.- -

Bass lslan~1tel Keyser Ls. 

UPPER Salina Group 

Lockport Dolomite 

z MIDDLE 

<( Rochester Sh. Clinton 

a: Dayton Ls. Group 

:::J 

_..J 

U5 "Clinton" Medina ca<ll 

~c 

LOWER Sandstone eB 

and <lllll 

Group 0"'0 

Shale CllC 

=>ca 

1-(J) 

~ ? ........ Q~~~ton ~ _Jrrl~.....,. Shale Formation 

UPPER Reedsville Shale 

z 

~ !lea :sra e Trenton 

() Trenton Ls. Group 

> 0 

0 Black River 

a: MIDDLE Group 0 

Loysburg Fm. 

Wells Creek Beekmantown Gp. 

Formation (upper part) 

Figure 14. Geologic column of Ordovician through Mississippian rocks in the eastern Ohio and western Pennsylvania portion of 

the Appalachian Basin. Modified from Berg and others (1983), 

Patchen and others (1984), Milici and de Witt (1988), and Ryder 

and others (1992). (The stratigraphic nomenclature and unit age 

assignments used in this figure may not necessarily conform to 

current usage by the U.S. Geological Survey.) 

The source of gas in Appalachian tight reservoirs is 

unknown. There are good source rocks, however, in Ordovician, Devonian, and Mississippian rocks (Cole and others, 

1987; Wallace and Roen, 1989). On the basis of thermal 

maturity data presented by Cole and others (1987) for the 

Devonian Ohio Shale and the Ordovician Point Pleasant 

Formation in eastern Ohio, these rocks are probably in the 

oil window (0.6 to 1.3 percent vitrinite reflectance), although where they are more deeply buried along the eastern 

edge of the basin, they are most likely thermally overmature 

with respect to the oil window (> 1.3 percent vitrinite reflectance). Conodont alteration indices in Ordovician rocks indicate that these rocks are thermally mature (within the oil 

window) along the western edge of the Appalachian Basin 

and thermally overmature through most of the basin (Harris 

and others, 1978; Wallace and Roen, 1989). 

Estimates of gas-in-place are 69 Tcf for the Berea Sandstone (Dutton and others, 1993) and 94 Tcf for the Clinton 

and Medina sands (Dutton and others, 1993 ). However, 

these estimates are probably conservative. The estimates are 

only for reservoirs designated as tight by the Federal Energy 

Regulatory Commission and do not include the more deeply 

buried, stratigraphically equivalent rocks in the basin. 

EAST TEXAS AND NORTH LOUISIANA BASINS 

The East Texas and North Louisiana Basins (figs. I, 16) 

formed during Late Triassic rifting (Buffter and others, 

1980). These basins formed as a consequence of crustal 

extension and heating followed by cooling and subsidence 

during which Mesozoic and Cenozoic sediments accumulated (Dutton and others, 1993). The basins are bounded by 

down-to-the-basin faults (Finley, 1984 ). The Sabine Arch 

(fig. 16), which separates the two basins, formed during Late 

Cretaceous and Tertiary time (Jackson and Laubach, 1991). 

The principal tight gas reservoirs in these basins are 

the Upper Jurassic to Lower Cretaceous Cotton Valley Formation and the Lower Cretaceous Travis Peak Formation 

(Finley, 1986; Dutton and others, 1993). Other tight gas 

reservoirs include sandstones within the Smackover Formation, the Upper Jurassic Haynesville Formation, the 

Lower Cretaceous James Limestone, and the middle part of 

the Cockfield Sandstone, equivalent to the Eocene Yegua 

Formation in east Texas (fig. 17). 

The sandstones of the Cotton Valley and Travis Peak 

represent deposition of the first major clastic progradation 

into the East Texas and North Louisiana Basins after the 

opening of the Gulf of Mexico in the Jurassic (Seni and 

Jackson, 1983). They consist of interbedded conglomerate, 

sandstone, siltstone, and mudstone that were deposited in 

fluvial, deltaic, and nearshore marine environments associated with the ancestral Mississippi River (Coleman and Coleman, 1981; McGowan and Harris, 1984). The Cotton Valley 

ranges in thickness from 1,000 to 3,000 ft (305-915 m), and 
248 THE FUTURE OF ENERGY GASES 

N.W. 

21 00 

NO HORIZONTAL SCAL( 

VERTICAL SCALE 

'-I( TERS fEET 

200 

60 

30 100 

0 0 

A' S.E. 

1900 

. - . - - - -?- . - . - - . 

-2800 

Figure 15. Cross section showing stratigraphic correlations of geophysical well logs and relationships of the Medina Group (shaded) in 

western Pennsylvania. From Pietrowski (1981) in Laughrey and Harper (1986). 

the Travis Peak ranges in thickness from 1,400 to 3,200 ft 

(430-975 m). Both units increase in thickness from northwest to southeast (Dutton and others, 1991 ). Depth to the top 

of the Cotton Valley ranges from 5,000 to 8,000 ft (1 ,525-

2,440 m) in the northern parts of the basins and I 0,000 to 

11,000 ft (3,050-3,350 m) in the southern part of the area. 

Depth to the Travis Peak ranges from 4,000 to I 0,000 ft 

(1 ,220-3,050 m). 

Gas production from the Cotton Valley is from both 

conventional and unconventional reservoirs. In the shallower updip areas of the basins, gas production is typically 

from conventional, high-permeability reservoirs. Downdip 

from these areas, gas production is from low-permeability 

reservoirs (Collins, 1980). The reservoirs in the Cotton 

Valley and Travis Peak are normal to overpressured, with 

gradients of about 0.60 psi/ft in the Cotton Valley and 0.43 

to 0.59 psi/ft in the Travis Peak (Finley, 1984). Finley 

(1984) reported that porosity in the Cotton Valley ranges 

from 6 to 10 percent and the average permeability in 

Texas and Louisiana is 0.04 and 0.01 mD, respectively. 

Production from the Travis Peak is from structural 

and stratigraphic traps over the crest of the Sabine Arch 

and from combination traps associated with salt structures 

off the flanks of the uplift (Dutton and others, 1991 ). 

Both the Cotton Valley and Travis Peak are fractured 

(Finley, 1984; Laubach, 1989a, b). Finley (1984) concluded that the natural fractures seemed to enhance production. Porosity in the Travis Peak ranges from 1 to 21 

percent, generally decreasing with increasing depth of 

burial from a mean of 10.6 percent at 6,000 ft (1,830 m) 

to 4.4 percent at I 0,000 ft (3,050 m) (Dutton and Diggs, 

1992). Permeability also decreases with increasing depth; 

mean matrix permeability at a depth of 6,000 ft is 0.8 mD 

and at 10,000 ft is 0.0004 mD (Dutton and Diggs, 1992). 

Dutton and Diggs (1992) attributed the loss of porosity 

and permeability to increasing amounts of quartz cement, 

decreasing secondary porosity, and increasing overburden 

pressure. Estimates of in-place gas are 24.2 Tcf for the 

Cotton Valley Formation and 6.4 Tcf (Haas, 1990) for the 

Travis Peak. 
GAS IN TIGHT RESERVOIRS-AN EMERGING MAJOR SOURCE OF ENERGY 249 

+ 960 

+ 

+ 940 

+ 

SCAL[ 

0 

I ,•, I ,•, 0 

>0•" •' I I 

80•m 

+ 

+ 

+ 

g2° 

~ 

~ 

PICKENS + 

s:s.l% 

(' MISSISSIPPI 

J

V,+ SALT 

BASIN 

_f~ 

_? 

f L.___ -~S_?IfP_I __ _..... l LOUISIANA f 

+ 

g,o 

I 

\ 

+ 

goo 

\ 

+ 

ago 

Figure 16. Map of East Texas and North Louisiana Basins showing major structural elements. From Dutton and others (1993). 

SUMMARY 

Low-permeability (tight) gas reservoirs contain very 

large amounts of gas. In-place gas resources in the United 

States may exceed 5,000 Tcf, and recoverable gas is estimated to range from less than 200 Tcf to more than 550 

Tcf. Tight gas reservoirs are present in nearly every petroleum province. These reservoirs occur at very shallow to very 

deep depths and consist of a wide range of rock types. They 

are commonly abnormally pressured, and the gas accumulations, unlike conventional accumulations, are pervasive 

and independent of structural or stratigraphic traps. Tight 

gas reservoirs may be discrete, isolated thin beds a few feet 

thick, or they may be very thick, vertically stacked beds in 

intervals several thousand feet thick. Natural fractures play 

a prominent role in the economic production from these 

reservoirs. Wells drilled into tight gas reservoirs commonly 

require artificial hydraulic fracturing. However, currently 

used drilling and completion practices have resulted in 

mixed success. The use of slant and horizontal wells in 

tight-gas-reservoir sequences as an alternative to vertically 

drilled holes is in an early stage of evaluation. Because of 

the ability of slant and horizontal drilling techniques to intersect the natural fracture system, the gas industry is optimistic that deviated drilling will successfully exploit the 

very large gas resources in tight reservoirs. 

ACKNOWLEDGMENTS 

The U.S. Geological Survey research on tight gas reservoirs has been supported by the U.S. Department of Energy 

(DOE) since 1978. Karl-Heinz Frohne, C. Keith Westhusing, and Charles A. Komar of the U.S. DOE have provided 

valuable technical assistance and have been very supportive. U.S. Geological Survey programs on Onshore Oil and 

Gas, Oil Shale, and Evolution of Sedimentary Basins have 

also provided invaluable assistance and support. During our 

research, technical discussions with many individuals from 

industry and academic groups provided perspectives that in 
250 

:2: 

UJ 

t-

(/) 

>- (/) 

.._: 

<( 

::> 

0 

>- oc 

<( 

i= 

oc 

UJ 

I-

(/) 

::> 

0 

UJ 

0 

<( 

IUJ 

oc 

(.) 

Oo 

UJ-

-10 

<CN 

c.. 

(/),......_ 

UJUJ 

ii:CJ 

UJ<C 

(/)-

0 

w 

.....J 

<( 

0.. 

z 

<( 

u::: 

.....J 

:::> 

(!) 

z 

<( 

UJ 

J: 

() 

z 

<( 

:::! 

0 

() 

THE FUTURE OF ENERGY GASES 

EAST TEXAS 

BASIN 

WILCOX 

MIDWAY 

AUSTIN 

COK EAGLE 

FORD 

LEWISVILLE WOODDEXTER 

BINE 

BUDA 

GRAYSON 

GEORGETOWN 

FREDERICKSBURG 

PALUXY 

UPPER GLEN ROSE 

w MOORINGSPORT en 

0 MASSIVE ANHYDRITE a: 

z 

w 

--' 

(9 

OUACHITA FACIES 

..... Figure 17. Geologic column for East Texas Basin. The Cotton Valley Formation and Travis Peak Formation, the principal 

tight gas reservoirs, are shown in a shaded pattern. From Dutton 

and others (1993). 

many cases affected our research approach. Finally, the constructive reviews of this manuscript by Thomas D. Fouch, 

David D. Howell, and Laura Zink are appreciated. 

REFERENCES CITED 

Berg, T.M., Mcinerney, M.K., Way, J.H., and MacLachlan, D.B., 

1983, Stratigraphic correlation chart of Pennsylvania: Pennsylvanian Topographic and Geologic Survey, General Geology Report 75, 1 sheet. 

Buffler, R.T, Watkins, J .S., Shaub, F.J ., and Worzel, J.L., 1980, 

Structure and early geologic history of the deep central Gulf 

of Mexico, in Symposium on the origin of the Gulf of Mexico and the early opening of the central North Atlantic 

Ocean: Baton Rouge, Louisiana State University, School of 

Geoscience, p. 3-16. 

Collins, S.E., 1980, Jurassic Cotton Valley and Smackover reservoir trends, east Texas, north Louisiana, and south Arkansas: 

American Association of Petroleum Geologists Bulletin, 

v. 64, no. 7, p. 1004-1013. 

Cole, G.A., Drozd, R.J., Sedivy, R.A., and Halpern, H.I., 1987, 

Organic geochemistry and oil-source correlations, Paleozoic 

of Ohio: American Association of Petroleum Geologists Bulletin, v. 71, p. 788-809. 

Coleman, J.L., Jr., and Coleman, C.J., 1981, Stratigraphic, sedimentologic and diagenetic framework for the Jurassic Cotton Valley Terryville massive sandstone complex, northern 

Louisiana: Gulf Coast Association of Geological Societies 

Transactions, v. 31, p. 71-79. 

Cotter, E. 1982, Tuscarora Formation of Pennsylvania: Society of 

Petroleum and Mining Geologists, Eastern Section, 1982 

Fieldtrip Guidebook, 105 p. 

Davis, T.B., 1984, Subsurface pressure profiles in gas-saturated 

basins, in Master, J.A, ed., Elmworth-Case study of a deep 

basin gas field: American Association of Petroleum Geologists Memoir 38, p. 189-203. 

de Witt, Wallace, Jr., 1988, Principal oil and gas plays in the 

Appalachian Basin (Province 131): U.S. Geological Survey 

Open-File Report 88-450S, 54 p. 

de Witt, Wallace, Jr., and McGrew, L.W., 1979, Appalachian 

Basin region, in Craig, L.C., and Connor, C.W., eds., Paleotectonic investigations of the Mississippian System in the 

United States, Part !-Introduction and regional analyses of 

the Mississippian System: U.S. Geological Survey Professional Paper 1010, p. 13-48. 

Dolly, E.D., and Meissner, F.F., 1977, Geology and gas exploration potential, Upper Cretaceous and lower Tertiary strata, 

northern Raton Basin, Colorado, in Veal, H.K., ed., Exploration frontiers of the central and southern Rockies: Rocky 

Mountain Association of Geologists, p. 240-270. 
GAS IN TIGHT RESERVOIRS-AN EMERGING MAJOR SOURCE OF ENERGY 251 

Dutton, S.P., Clift, S.J., Hamilton, D.S., Hamlin, H.S., Hentz, 

T.F., Howard, W.E., Akhter, M.S., and Laubach, S.E., 1993, 

Atlas of major low-permeability gas reservoirs in the continental United States: Gas Research Institute Topical Report, 

GRI-93/0044, 470 p. 

Dutton, S.P., and Diggs, T.N., 1992, Evolution of porosity and 

permeability in the Lower Cretaceous Travis Peak Formation, East Texas: American Association of Petroleum Geologists Bulletin, v. 76, p. 252-269. 

Dutton, S.P., Finley, R.J., and Herrington, K.L., 1987, Organic 

geochemistry of the Lower Cretaceous Travis Peak Formation, East Texas Basin: Gulf Coast Association of Geological 

Societies Transactions, v. 37, p. 65-74. 

Dutton, S.P., Hamlin, H.S., and Laubach, S.Eo, 1992, Geologic 

controls on reservoir properties of low-permeability sandstone, Frontier Formation, Moxa Arch, southwest Wyoming: 

Gas Research Institute Topical Report GRI-92/0127, 199 p. 

Dutton, S.P., Laubach, S.E., Tye, R.S., 1991, Depositional, diagenetic, and structural controls on reservoir properties of lowpermeability sandstone, Travis Peak Formation, East Texas: 

Gulf Coast Association of Geological Societies Transactions, 

v. 41' p. 209-220. 

Finley, R.J ., 1984, Geology and engineering characteristics of selected low-permeability gas sandstones-A National survey: 

The University of Texas at Austin, Bureau of Economic Geology Report of Investigations No. 138, 220 p. 

---1986, An overview of selected blanket-geometry, lowpermeability gas sandstones in Texas, in Spencer, C.W., and 

Mast, R.F., eds., Geology of tight gas reservoirs: American 

Association of Petroleum Geologists Studies in Geology 

No. 24, p. 69-85. 

Fouch, T.D., Wandrey, C.J., Pitman, J.K., Nuccio, V.F., Schmoker, J.W., Rice, D.O., Johnson, R.C., and Dolton, G.L., 1992, 

Natural gas accumulations in low-permeability Tertiary and 

Cretaceous (Maastrichtian-Campanian) rock, Uinta Basin, 

Utah: U.S. Department of Energy Report DOE/MC/20422-

3051 (DE92001132), 81 p. 

Haas, M.R., 1990, Impact of improved technology on potential 

reserves of tight gas in East Texas and North Louisiana: 

lCF-Lewin, Inc., Topical Report GRI-90/0174, 119 p. 

Harper, J.A., Laughrey, C.D., and Lytle, W.S., 1982, Oil and gas 

fields of Pennsylvania: Pennsylvania Geological Survey, 4th 

Series, Map No. 3. 

Harris, A.G., Harris, L.D., and Epstein, J.B., 1978, Oil and gas 

data from Paleozoic rocks in the Appalachian basin; maps 

for assessing the hydrocarbon potential and thermal maturity 

(conodont color alteration isograds and overburden isopachs): U.S. Geological Survey Miscellaneous Investigations 

Map 1-917-E, scale 1:2,500,000 4 sheets. 

Jackson, M.L.W., and Laubach, S.E., 1991, Structural history and 

origin of the Sabine Arch, east Texas and northwest Louisiana: The University of Texas at Austin, Bureau of Economic 

Geology Geological Circular 91-3, 47 p. 

Johnson, R.C., Crovelli, R.A., Spencer, C.W., and Mast, R.F., 

1987, An assessment of gas resources in low-permeability 

sandstones of the Upper Cretaceous Mesaverde Group, 

Piceance Basin, Colorado: U.S. Geological Survey OpenFile Report 87-357, 165 p. 

Johnson, R.C., and Rice, D.O., 1990, Occurrence and geochemistry of natural gases, Piceance Basin, northwest Colorado: 

American Association of Petroleum Geologists Bulletin, 

v. 74, p. 805-829. 

Keighin, C.W., Law, B.E., and Pollastro, R.M., 1989, Petrology 

and reservoir characteristics of the Almond Formation, 

Greater Green River Basin, Wyoming: Rocky Mountain Association of Geologists, p. 281-298. 

Kuuskraa, V.A., Brashear, J.P., Doscher, T.M., and Elkins, L.E., 

1978, Enhanced recovery of unconventional gas, the program-Volume II: U.S. Department of Energy, HCP/T2705-

02, 537 p. 

Laubach, S.E., 1989a, Fracture analysis of the western flank of 

the Sabine Arch, East Texas: The University of Texas at 

Austin, Bureau of Economic Geology Report of Investigations No. 185, 55p. 

---1989b, Paleostress directions from the preferred orientation of closed microfractures (fluid-inclusion planes): Journal of Structural Geology, v. 11, no. 5, p. 603-611. 

Laughrey, C.D., 1984, Petrology and reservoir characteristics of 

the Lower Silurian Medina Group reservoir sandstones, Athens and Geneva fields, northwestern Pennsylvania: Pennsylvania Geological Survey, 4th series, Mineral Resource 

Report 85, 126 p. 

Laughrey, C.D., and Harper, J.A., 1986, Comparisons of Upper 

Devonian and Lower Silurian tight formations in Pennsylvania-Geological and engineering characteristics, in Spencer, 

C.W., and Mast, R.F., eds., Geology of tight gas reservoirs: 

American Association of Petroleum Geologists Studies in 

Geology no. 24, p. 9-43. 

Law, B.E., 1984, Relationships of source-rock, thermal maturity, 

and overpressuring to gas generation and occurrence in lowpermeability Upper Cretaceous and lower Tertiary rocks, 

Greater Green River Basin, Wyoming, Colorado, and Utah, 

in Woodward, 1., Meissner, F.F., and Clayton, J.L., eds., Hydrocarbon source rocks of the greater Rocky Mountain area: 

Rocky Mountain Association of Geologists, p. 469-490. 

Law, B.E., Pollastro, R.M., and Keighin, C.W., 1986, Geologic 

characterization of low-permeability gas reservoirs in selected wells, Greater Green River Basin, Wyoming, Colorado, 

and Utah, in Spencer, C.W., and Mast, R.F., eds., Geology 

of tight gas reservoirs: American Association of Petroleum 

Geologists Studies in Geology no. 24, p. 253-269. 

Law, B.E., Spencer, C.W., Charpentier, R.R., Crovelli, R.A., 

Mast, R.F., Dolton, G.L., and Wandrey, C.J., 1989, Estimates 

of gas resources in overpressured low-permeability Cretaceous and Tertiary sandstone reservoirs, Greater Green River 

Basin, Wyoming, Colorado, and Utah: 40th Annual Field 

Conference, Wyoming Geological Association Guidebook, 

p. 39-61. 

Lorenz, J.C., and Hill, R.E., 1991, Subsurface fracture spacingComparison of inferences from slant/horizontal core and 

vertical core in Mesaverde reservoirs, in Rocky Mountain 

Regional/Low Permeability Reservoirs Symposium and Exhibition: Society of Petroleum Engineers, p. 705-716. 

Martini, I.P., 1971, Regional analysis of sedimentology of Medina Formation (Silurian), Ontario and New York: American 

Association of Petroleum Geologists Bulletin, v. 55, 

p. 1249-1261. 

Masters, J.A., 1979, Deep basin gas trap, western Canada: American Association of Petroleum Geologists Bulletin, v. 63, 

p. 152-181. 
252 THE FUTURE OF ENERGY GASES 

---1984, Lower Cretaceous oil and gas in western Canada, 

in Masters, J.A., ed., Elmworth-Case study of a deep basin 

gas field: American Association of Petroleum Geologists 

Memoir 38, p. 1-33. 

McGowan, M.K., and Harris, D.W., 1984, Cotton Valley (Upper 

Jurassic) and Hosston (Upper Cretaceous) depositional systems and their influence on salt tectonics in the East Texas 

Basin: The University of Texas at Austin, Bureau of Economic Geology Geological Circular 84-5, 41 p. 

Meissner, F.F., 1978, Patterns of source-rock maturity in non-marine source rocks of some typical western interior basins in 

non-marine Tertiary and Upper Cretaceous source rocks and 

the occurrence of oil and gas in the west central U.S.: Rocky 

Mountain Association of Geologists Continuing Education 

Course Notes. 

---1984, Cretaceous and lower Tertiary coals as sources for 

gas accumulations in the Rocky Mountain area, in Woodward, J., Meissner, F.F., and Clayton, J.L., eds., Hydrocarbon source rocks of the greater Rocky Mountain region: 

Rocky Mountain Association of Geologists, p. 401-431. 

Milici, R.C., and de Witt, Wallace, Jr., 1988, The Appalachian 

Basin, in Sloss, L.L., ed., Sedimentary cover-North American craton: Boulder, Colo., Geological Society of America, 

The Geology of North America, v. D-2, p. 427-469. 

National Petroleum Council, 1980, Unconventional gas sources-Tight gas reservoirs, part I, in National Petroleum 

Council Unconventional Gas Resource: Washington, D.C., 

222 p. with appendixes. 

---1992, The potential for natural gas in the United StatesSource and supply, v. II: National Petroleum Council, Committee on Natural Gas, 330 p. with appendixes. 

Nuccio, V.F., Schmoker, J.W., and Fouch, T.D., 1992, Thermal 

maturity, porosity, and lithofacies relationships applied to 

gas generation and production in Tertiary and Cretaceous 

low-permeability (tight) sandstones, Uinta Basin, Utah, in 

Fouch, T.D., Nuccio, V.F., and Chidsey, T.C., Jr., eds., Hydrocarbon and mineral resources of the Uinta Basin, Utah 

and Colorado: Utah Geological Association Guidebook 20, 

p. 77-94. 

Patchen, D.G., Avary, K.L., and Erwin, R.B., coordinators, 1984, 

Correlation of stratigraphic units in North America, northern 

Appalachian region correlation chart: American Association 

of Petroleum Geologists. 

Pepper, J.F., de Witt, Wallace, Jr., and Demarest, D.F., 1954, Geology of the Bedford Shale and Berea Sandstone in the Appalachian Basin: U.S. Geological Survey Professional Paper 

259, 61 p. 

Potter, P.E., DeReamer, J.H., Jackson, D.S., Maynard, J.B., 1983, 

Lithologic and environmental atlas of Berea Sandstone 

(Mississippian) in the Appalachian Basin: Appalachian Geological Society Special Publication 1, 157 p. 

Randolph, P.L., 1973, Nuclear stimulation of gas fields: Canadian 

Gas Association, National Technical Conference, Calgary, 

Alberta, Canada, October 17-19, 1973, 21 p. 

---1974a, Massive stimulation effort may double U.S. gas 

supply, Part 1: World Oil, p. 33-36. 

---1974b, Massive stimulation effort may double U.S. gas 

supply, Part 2: World Oil, p. 65-71. 

---1974c, Massive stimulation effort may double U.S. gas 

supply, Part 3: World Oil, p. 131-134. 

Rice, D.D., Nydegger, G.L., and Brown, C.A., 1990, Bowdoin 

field-U.S.A., in Beaumont, E.A., and Foster, N.H., eds., 

Treatise of petroleum geology atlas of oil and gas fields, 

structural traps III, tectonic fold and fault traps: American 

Association of Petroleum Geologists, p. 337-355. 

Rice, D.D., and Shurr, G.W., 1980, Shallow, low-permeability 

reservoirs of northern Great Plains-Assessment of their 

natural gas resources: American Association of Petroleum 

Geologists Bulletin, v. 64, p. 969-987. 

Rose, P.R., Everett, J.R., and Merin, I.S., 1986, Potential basincentered gas accumulation in Cretaceous Trinidad Sandstone, Raton Basin, Colorado, in Spencer, C.W., and Mast, 

R.F., eds., Geology of tight gas reservoirs: American Association of Petroleum Geologists Studies in Geology no. 24, 

p. 111-128. 

Russell, W.L., 1972, Pressure-depth relations, Appalachian region: American Association of Petroleum Geologists Bulletin, v. 59, p. 528-536. 

Ryder, R.T., Harris, A.G., and Repetski, J.E., 1992, Stratigraphic 

framework of Cambrian and Ordovician rocks in the central 

Appalachian Basin from Medina County, Ohio, through 

southwestern and south-central Pennsylvania to Hampshire 

County, West Virginia: U.S. Geological Survey Bulletin 

1839-K, 32 p. 

Seni, S.J., and Jackson, M.P.A., 1983, Evolution of salt structures, East Texas diapir province, part !-Sedimentary 

record of halokinesis: American Association of Petroleum 

Geologists, v. 67, p. 1219-1244. 

Spencer, C.W., 1985, Geologic aspects of tight gas reservoirs in 

the Rocky Mountain region: Journal of Petroleum Technology, v. 37, p. 1308-1314. 

---1989a, Review of characteristics of low-permeability gas 

reservoirs in western United States: American Association of 

Petroleum Geologists Bulletin, v. 73, no. 5, p. 613-629. 

---1989b, Comparison of overpressuring at the Pinedale Anticline area, Wyoming, and the Multiwell Experiment Site, 

Colorado, in Law, B.E., and Spencer, C.W., eds., Geology of 

tight gas reservoirs in the Pinedale Anticline area, Wyoming, 

and the Multiwell Experiment Site, Colorado: U.S. Geological Survey Bulletin 1886, p. C1-C16. 

Supply-Technical Advisory Task Force, 1973, Task force report; 

national gas supply, in National gas survey v. II: Federal 

Power Commission, 662 p. 

---1978, National gas survey, in Report to the Federal Energy Regulatory Commission by the Supply-Technical Advisory Task Force on Nonconventional Natural Gas Resources: 

U.S. Department of Energy Federal Energy Regulatory 

Commission, 108 p. 

Wallace, L.G, and Roen, J.B, 1989, Petroleum source rock potential of the Upper Ordovician black shale sequence, northern 

Appalachian Basin: U.S. Geological Survey Open-File Report 89-488, 66 p. 

Zagorski, W.A., 1988, Exploration concepts and methodology for 

deep Medina Sandstone reservoirs in northwestern Pennsylvania: American Association of Petroleum Geologists Bulletin, v. 72, p. 976. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Autogenic Gas (Self Sourced) from ShalesAn Example from the Appalachian Basin 

By Robert C. Milici 1 

CONTENTS 

Abstract ......................................................................... 253 

Introduction ................................................. : ................. 254 

Shale Gas .... ...... .. .. ........ .. .. .... ... . ... . . ... . . .. .. ... ... .. .. ... . . 254 

A Source for Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 254 

Previous Studies . . .... ... . ..... ... .. . .. .. . . .. . ... . ... . . ... .. .. ... .. .. 256 

Present Study ......................................................... 256 

Shale-Gas Production . ..... .... ........ .... .. . ..... ... ... ... . .. .. 256 

Tectonic Setting ............................................................ 258 

The Catskill Delta ....... ........................................... 258 

Depositional Environments of Black ShaleAnoxia Versus Productivity and Sedimentation 

Rates ....................................................................... 259 

Stratigraphy ................................................................... 262 

Devonian Formations ............................................. 262 

West Falls Formation ...................................... 262 

Java Formation ................................................ 263 

Ohio Shale . .... .. .. ... ..... .... .... ... . .. ..... ..... .. .... .. .. .. . . 265 

Mississippian Formations . . . . .. ... .. . .... .. ....... ... ..... ..... 265 

Bedford Shale and Berea Sandstone .. .. ..... ...... 265 

Sunbury Shale ................................................. 266 

Price Formation .. .. .. .. .. .. .. . .... ... .... ..... ......... ....... 266 

Resource Potential of the Shales . . ....... .... .. . ...... ..... ... .... 266 

Content and Character of Organic Matter . ..... ... .. .. 266 

Thermal Maturity ................................................... 267 

Source-Rock-Potential Maps ................................. 268 

Role of Structure and Fracture Porosity ................ 268 

Plays and Production Characteristics of the 

Devonian and Mississippian Sequence in the 

South-Central Appalachian Basin ................................ 271 

1

U.S. Geological Survey, Denver Federal Center, Box 25046, 

MS 939, Denver, CO 80225-0046. 

Shale-Gas Plays and Potential in Other Basins ............ 272 

Summary and Conclusion ............................................. 275 

Acknowledgments ......................................................... 275 

References Cited ........................................................... 275 

ABSTRACT 

Black gas shales of Devonian and Mississippian age 

occur over much of the Appalachian basin, extending from 

eastern Tennessee north- and northeastward into Ohio and 

New York. In general, these shales were deposited along 

the distal margin of the Acadian Catskill delta in response 

to episodes of tectonic subsidence and regional transgression during the Acadian orogeny. A major trend of high 

organic carbon content in the black shales extends along 

the western side of the Catskill delta, from southwestern 

Virginia to the southern shores of Lake Erie. The high content of organic detritus in these Devonian and Mississippian 

black-shale source beds is probably related to high organic 

productivity in combination with moderate sedimentation 

rates along the distal margins of the Catskill delta, rather 

than to the widespread establishment of a pycnocline and 

preservation in anoxic environments. In general, organic 

matter in the black shales is more marine and oil prone on 

the western side of the basin, away from the major sources 

of siliciclastic input, than it is to the east. Thermal maturity 

trends follow depositional strike and isopachs of the 

Catskill delta and, thus, are related to depth of burial. Fracture porosity within the black shale sequence appears to 

have been affected mostly by regional decollement within 

discrete stratigraphic units that were, perhaps, overpressured during deformation. 

These shales are most productive in the south-central part 

of the Appalachian Basin, where they are thermally mature 

253 
254 THE FUTURE OF ENERGY GASES 

and are abundantly fractured. Shale gas is produced from 

relatively large fields in southwestern Virginia, eastern Kentucky, southwestern West Virginia, and southernmost Ohio. 

To the north, the strata rich in organic matter are thermally 

immature, and fields along the southern shores of Lake Erie 

in Ohio and Pennsylvania are only marginally productive. To 

the east in northwestern West Virginia, the organic content of 

the shales is diluted by increased amounts of siliciclastics; 

organic matter is not sufficient to sustain long-term gas 

production, and shale-gas wells are short lived. 

INTRODUCTION 

Black-shale formations intercalated within the gray 

shales, siltstones, and sandstones of the great Catskill 

delta of Late Devonian and Early Mississippian age are 

the principal source beds for much of the petroleum and 

natural gas generated in the Appalachian Basin (Claypool 

and others, 1978; Cole and others, 1987; Laughery, 1989). 

In general, hydrocarbons have migrated into and are produced from the more porous and permeable reservoirs that 

overlie these source beds, as well as from reservoirs that 

lie unconformably below the source beds in a broad region that extends from Tennessee north- and northwestward into Kentucky, Ohio, West Virginia, Pennsylvania, 

and New York. Cole and others (1987) demonstrated that 

much of the oil in Ohio reservoirs was derived from one 

Ordovician and three Devonian shale source beds. On the 

basis of relative thermal maturities of the oils and the reservoirs that contained them, they concluded that the oil 

must have migrated into Ohio from the east, from deep 

within the Appalachian Basin. Devonian shale, itself, has 

produced oil in a few places elsewhere in the Appalachian 

Basin. 

Gas is produced from Upper Devonian and Lower 

Mississippian black shales and associated strata in three 

general regions as well as in many other widely scattered 

localities in the Appalachian Basin (fig. 1). A major shalegas-producing area occurs in the south-central part of the 

Appalachian Basin, in southwestern Virginia, eastern Kentucky, southwestern West Virginia, and southernmost Ohio 

(Wallace and deWitt, 1975). This region includes the Big 

Sandy Gas Field and several other smaller fields. A northward extension of the major shale gas-producing region 

occurs in northwestern West Virginia. This area is called 

the "emerging area" by Patchen and Hohn (1993) in their 

description of shale-gas geology and production in West 

Virginia. Another important area of shale-gas production 

occurs along the northern margin of the basin, where relatively small amounts of gas are produced from low-pressure fields along the southern shores of Lake Erie in 

Ohio, Pennsylvania, and New York (deWitt and others, 

1993; Broadhead and others, 1982; Broadhead, 1993; Van 

Tyne, 1983). 

SHALE GAS 

The first well drilled specifically for natural gas in the 

United States was completed in 1821 in shale beds overlying the black Dunkirk Shale member of the Perrysburg Formation (Devonian) in Fredonia, Chautauqua County, New 

York. It was sited above a natural-gas seep and produced 

gas for local uses, probably from fractures at a depth of 

about 8 m (Weeks, 1886; Orton, 1899; Van Tyne, 1983; 

deWitt and others, 1993). This well was later drilled to a 

depth of 21 m. 

Since then, about 3.0 trillion cubic feet of gas (Tcf) 

have been produced from the Devonian shale formations in 

the Appalachian Basin, and it is estimated that about 20 Tcf 

of gas can still be recovered from these formations using 

currently available methods (Charpentier and others, 1993). 

Most of the gas, by far, has been produced from the Big 

Sandy area, where more than 10,000 wells had produced 

more than 2.5 Tcf by 1985 (Brown, 1976; Charpentier and 

others, 1993, p. N3). Recent estimates of the in-place natural-gas resources in the Devonian shales of the Appalachian 

Basin range from 577 Tcf at a 95 percent probability to 

1,131 Tcf at a 5 percent probability (Charpentier and others, 

1993, table 2, p. N13). 

A SOURCE FOR OIL 

Oil has been extensively produced from the Appalachian Basin since its discovery in 1859 near Titusville, 

Pennsylvania, by Edwin Drake. Much of the oil produced 

in the Appalachian Basin is from Devonian and Mississippian reservoirs, and most of this oil apparently originated 

in the Upper Devonian and Lower Mississippian black 

shales (Laughrey, 1989). 

The Oriskany Sandstone and its stratigraphic equivalents (Lower Devonian) have produced oil and gas, chiefly 

from anticlinal traps, over a wide area in West Virginia, 

Maryland, and Pennsylvania. These reservoirs are immediately below Devonian black shales in the northern and central parts of the Appalachian Basin, and in places the shales 

have served both as a source and a seal for the hydrocarbons. The anticlines, in general, do not involve strata from 

deep in the section. Instead, they are superficial and formed 

as the result of splay thrusting from subhorizontal decollement in the bedding of underlying Ordovician shales and 

Silurian salt measures (Gwinn, 1964). 

The regional dip of the Appalachian Plateau is generally to the east from the crest of the Cincinnati Arch, a 

pre-Alleghanian structure, toward the interior of the Appalachian Basin. Thus, migration of oil westward away from 

the deformed Appalachians toward the arch was generally 

up the regional dip, although some of the Devonian oil 

apparently has entered reservoir rocks that are stratigraphically lower than the source beds. 
AUTOGENIC GAS (SELF SOURCED) FROM SHALES-AN EXAMPLE FROM THE APPALACHIAN BASIN 255 

Much oil has been produced from Devonian sands 

younger than the Oriskany Sandstone, such as the Bradford 

sands, in an area that extends from western New York into 

central West Virginia. This oil also was probably derived 

from Devonian black-shale source beds (Laughrey, 1989). 

Oil is produced in small quantities from black-shale 

84°00' 

42°00'·-t---::;(<-=-="0------7'~--;;.--~;:;<"~f-'--,-;:-

EXPLANATION 

0 Producing areas 

50 0 50 MILES 

I ,',\,',I I 

50 KILOMETERS 

I 

50 0 

Figure 1. Regions and localities that produce gas from Upper Devonian and Lower Mississippian shales in the Appalachian Basin. 
256 THE FUTURE OF ENERGY GASES 

reservoirs in west-central West Virginia, apparently because 

of a weB-developed fracture porosity (Patchen and Hohn, 

1993 ). In Virginia, condensate produced from oolitic and 

fossiliferous-fragmental carbonate strata of Mississippian 

age at the upper (easternmost) limit of the oil window 

probably had its origin in underlying Devonian and Mississippian black shales (fig. 2). Oil production from Carboniferous rocks in Tennessee is restricted generaiiy to the 

northern part of the Cumberland Plateau. The origin of this 

oil is not known with certainty. There are, however, oil 

stains and residues in fractured carbonate rocks stratigraphicaiiy between black Chattanooga Shale (Devonian and 

Mississippian) source rocks and reservoirs in overlying 

(15m above) porous carbonate reefs in the Fort Payne 

Formation that attest to the migration of oil through those 

strata, most likely from the Chattanooga into the carbonate 

reservoirs. It is no coincidence that commercial production 

of hydrocarbons in the Appalachian Basin, exclusive of the 

Black Warrior Basin, ceases to the south in Tennessee, 

where Chattanooga source beds are less than 15 m thick, 

and thus the total mass of organic carbon per square centimeter apparently decreases below 0.6 percent (Charpentier 

and others, 1993, p. N4; Schmoker, 1993; Milici, 1985). 

PREVIOUS STUDIES 

Because of the demonstrated capability and significant 

potential of the Devonian and Mississippian black shales 

in the Appalachian Basin to produce gas, the U.S. Department of Energy (DOE), then the Energy Research and Development Administration (ERDA), initiated and funded a 

multidisciplinary regional study in the mid-1970's to characterize the geology of these natural-gas resources as weii 

as to design and develop new stimulation techniques that 

would enhance the recovery of the gas. Several state 

geological surveys, the U.S. Geological Survey (USGS), 

several universities, and industry were the principal cooperators. As a result of these studies, extensive geological 

and engineering literature was developed during the 

foiiowing decade that addressed a wide range of topics, 

including descriptions and interpretations of the stratigraphy, depositional environments, tectonics, geologic 

structure, paleontology and geochemistry of the shale formations as guides for exploration and development, as 

well as engineering topics dealing with driiiing and more 

effective stimulation and comple · n of shale-gas wells. 

In addition to the numerous rep ts published on the 

Devonian and Mississippian shale sequen during the past 

few decades, a report summarizing the work completed by 

USGS and others on the petroleum geology of these strata 

has been prepared for publication (Roen and Kepferle, 

1993). The stratigraphy of the Appalachian Basin, including that of the Devonian and Mississippian Catskill delta, 

was summarized by Milici and deWitt (1988). Furthermore, 

a consortium of industry and academia (Appalachian Basin 

Industrial Associates) has compiled and published the results of their extensive studies in the Appalachian Basin 

(including discussions of the Devonian and Mississippian 

shale sequence) in several annual volumes during the past 

decade. A few state geological surveys, most notably the 

West Virginia Geologic and Economic Survey, have published the results of shale-gas investigations supported by 

the Gas Research Institute (GRI) (for example, Hohn and 

Timberlake, 1988). 

PRESENT STUDY 

This paper reviews and synthesizes the geology of the 

shale-gas fields in the south-central part of the Appalachian 

Basin, generaiiy in southwestern Virginia, northeastern 

Tennessee, eastern Kentucky, southern Ohio, and southern 

West Virginia, in order to characterize the self-sourced 

shale-gas reservoirs of the region. These characteristics can 

then be used to define some elements of a general model 

that may be useful for identification of potentiaiiy commercial self-sourced shale-gas reservoirs elsewhere. 

SHALE-GAS PRODUCTION 

In general, commercial production of natural gas from 

shale depends upon the simultaneous occurrence of several 

conditions. The source rock must be of sufficient thickness 

and have a suitable type, amount, and thermal maturation 

of organic matter. Furthermore, a shale reservoir must 

have a trapping mechanism and have enough porosity and 

permeability to yield gas effectively above some minimum 

rate over the commercial life of a well. Ail of the characteristics favorable for gas production need not be precisely 

within the same bed or stratigraphic unit. More commonly 

they are distributed within packages of contiguous strata, 

with the different stratigraphic components exhibiting one 

or more of the desired characteristics. In some places, for 

example, gas apparently has migrated for relatively short 

stratigraphic distances from black-shale source beds rich 

in organic material into slightly more porous layers that 

consist of lighter gray or greenish-gray siltier or sandier 

shales, siltstones, and sandstones (Broadhead and others, 

1982; Broadhead, 1993). In other places, where blackshale formations have served as hosts for major subhorizontal decollements, the shales are greatly fractured and 

when driiied may yield gas explosively (Young, 1957). Although these decollement zones generaiiy are so fractured 

that they have lost much of the gas originally contained in 

the shale, the immediately overlying beds may be fractured sufficiently to serve as reservoirs. 

Sustained commercial gas production from Devonian 

and Mississippian self-sourced shales in the Appalachian 
0 

0 

85° 

0 

0 

~4. 

~~"'"' / 

I 

KENTUCKY 

0 

) /~ 

__ ___, 83° 

r 

MILES 

0 

SCALE 

82° 

VIRGINIA 

_,--r-- -----------

TENNESSEE 

/ 

' NORTH 

_\ CAROLINIA 

/ 

~; 

- / / 36° 

81° 

Vo GAS 

50 

- I OIL 

Figure 2. Eastern limit of oil window in south-central part of the Appalachian Basin. Line A-A' indicates location of section shown in figure 4. 

Eastern limit is based on fixed-carbon/free-carbon ratios (Miller and Fuller, 1954), conodont-alteration-index (CAl) isograds (Harris and others, 1978), 

and observed distribution of oil and gas. 

> 

c::: 

d 

0 

tr1 

z 

n 

0 

> 

(/1 

Vi 

tr1 

r 

., 

(/1 

0 

c::: 

:;>::) 

() 

tr1 

g 

., 

:;>::) 

0 

~ 

(/1 

::c 

> r 

tr1 

(/1 

I 

> z 

tr1 

>< 

> 

~ 

'"C 

r 

tr1 

., 

:;>::) 

0 

~ 

-l 

::c 

tr1 

> 

'"C 

~ r 

> () 

::c 

> z 

to 

> (/1 

z 
258 THE FUTURE OF ENERGY GASES 

Basin depends greatly on the porosity and permeability of 

natural fracture systems in the reservoir and the capability 

of that fracture system to be stimulated into commercial 

production. These fractured beds, when completed properly, constitute a major reservoir in the Big Sandy and associated gas fields in the south-central Appalachian Plateau 

(Shumaker, 1980, 1993) as well as in gas fields elsewhere 

in the basin. The geologic subtleties of these shale reservoirs, however, are commonly ignored by industry. Instead, completion practices are commonly designed to 

extend across a variety of lithologies as well as to bracket 

zones of fracture porosity identified on well logs. 

TECTONIC SETTING 

THE CATSKILL DELTA 

In general, Catskill deltaic sedimentation was initiated 

by Acadian tectonic activity in the northern part of the Appalachian Basin late in the Early Devonian and then spread 

southward (Faill, 1985). Although this tectonism was apparently caused by the collision of several continental 

plates, Armorica with Laurentia (ancestral North America) 

and Baltica (northern European sialic crust) (Perroud and 

others, 1984), it produced only moderate deformation in 

the Appalachian foreland. In other words, the onset of the 

Acadian Orogeny initiated the subsidence of a basin in central Pennsylvania sufficiently deep to receive over 3,000 

m (10,000 ft) of Devonian sediment (Milici and deWitt, 

1988) (fig. 3) and created mountains sufficiently high to 

yield the great amount of siliciclastic sediments that constitute the Catskill deltaic basin fill. 

Relatively coarse-grained continental and marginal marine deposits mark the proximal regressive phases of Acadian sedimentation in the Appalachian Basin. These deposits 

were derived primarily from the two major depositional 

systems that had developed in the basin by the Early Mississippian-the Pocono delta of eastern Pennsylvania and 

adjacent states to the north and the smaller Price delta to 

the south in central Virginia (Milici and de Witt, 1988; Kreisa and Bambach, 1973). The depositional environments in 

which these coarser grained sediments accumulated range 

widely from littoral and deltaic on the east and north (Pepper and others, 1954) to marine shelf and associated deposits on the south and west (Potter and others, 1983). 

Paleocurrent studies by Potter and others (1980, modified by Kepferle, 1993) show that the direction of sediment transport was predominantly toward the west over 

much of the delta and toward the southwest in the southern part of the basin, away from the principal source of 

sediments in and near the Pennsylvania depocenter and 

from the subsidiary sources along the Devonian and Mississippian shorelines to the south. 

' \ 

'v 

).¢ 

I 

) 

/ \ 

\ 

\ \ 

\ 

/ 

/ 

f 

\ 

/ 

/ 

\ 

/ 

/ 

Figure 3. Isopach map showing thickness of Catskill delta sequence. Isopachs are in feet; hachured area is Rome Trough. 

Modified from Milici and deWitt (1988, fig. 6). 
AUTOGENIC GAS (SELF SOURCED) FROM SHALES-AN EXAMPLE FROM THE APPALACHIAN BASIN 259 

To the west and south, in southwestern West Virginia 

and adjacent Kentucky, Ohio, Tennessee, and Virginia, the 

more distal part of the sequence consists mostly of prodelta 

deposits. This sequence is much thinner and is dominated 

by shale and siltstone. In these peripheral areas, black-shale 

units constitute a considerable proportion of the stratigraphic column, although their composite thickness is greater 

toward the north and east near the heart of the delta (deWitt 

and others, 1993). Data from gamma-ray logs and well 

samples indicate that the greatest thickness of combined 

Devonian black-shale units occurs in and near the central 

Pennsylvania depocenter, where they are about 425 m thick 

and constitute about 15 percent of the Devonian section. In 

comparison, in southwestern Virginia the combined thickness of Devonian black-shale beds is about 125 m, or 40 

percent of the section (see deWitt and others, 1975, for 

thickness data). Schmoker (1980; 1981; 1993, fig. 9) used 

data from density and gamma-ray logs and calculated that 

the thickness of Devonian shales rich in organic carbon 

(defined as total organic carbon (TOC)2!0.6 percent) exceeds 305 m in southern West Virginia and adjacent Kentucky and 275 m in eastern Ohio. Schmoker (1993) 

illustrates a major thickness trend in the total mass of organic carbon in the black-shale sequence, measured in kilograms per square centimeter, that extends from the coal 

fields of southwestern Virginia, through eastern Kentucky 

and Ohio to the southern shores of Lake Erie. 

Subsidence of the Devonian foreland basin was episodic throughout the Middle and Late Devonian and was, 

perhaps, induced by intermittent Acadian tectonism and 

sediment loading. On a gross scale, this subsidence was 

not sufficient to maintain pace with sedimentation, and so 

the net effect of Acadian tectonism was to fill most of the 

foreland basin up to sea level or slightly above by Early 

Mississippian time. Only to the south and west are the uppermost Mississippian deposits entirely marine. 

Depending upon location, there were four to eight 

transgressive and progradational events in the marine part 

of the foreland basin during the Late Devonian and Early 

Mississippian (Kepferle, 1993). Each of the radioactive 

black muds and silts that had been deposited by turbidity 

currents in the more distal parts of the delta during periods 

of basin subsidence (Ettensohn and Barron, 1981, 1982; 

Ettensohn, 1985; Kepferle, 1993) were subsequently overlain by the relatively less radioactive lighter colored gray 

and greenish-gray muds and silts that were being deposited 

along the advancing submarine toe or slope of the Catskill 

delta front. Almost all of these black-shale deposits are of 

regional extent. Indeed, the widespread distribution of the 

Devonian black-shale units from the Rhine-street Shale 

Member of the West Falls Formation to the Sunbury Shale 

(de Witt and others, 1993) indicates that they were deposited in response to regional transgressive events as the Devonian foreland basin subsided and filled. 

DEPOSITIONAL ENVIRONMENTS OF BLACK 

SHALE-ANOXIA VERSUS PRODUCTIVITY 

AND SEDIMENTATION RATES 

There are two principle theories concerning the processes that have resulted in the concentration of organic 

matter in the black-shale source beds. Most of the current 

workers in the Appalachian Basin and adjacent regions (for 

example, Kepferle, 1993; Russell, 1993) ascribe the high 

content of organic matter in the Upper Devonian and Lower 

Mississippian black shales both to high productivity of organic matter in surficial waters and to subsequent deposition of that organic matter in anoxic environments at the 

basin floor. In contrast, marine sedimentologists have determined that relatively high productivity of organic material 

in oxic marine environments in combination with moderate 

sedimentation rates, not anoxia at the site of deposition, are 

the principle factors that control the deposition of black 

muds rich in organic matter and, ultimately, the formation 

of black-shale source beds. 

Ettensohn and Barron (1981, 1982) and Ettensohn 

(1985) speculated about a special set of geologic conditions that might have led to the extensive accumulation of 

muds rich in organic matter in the broad region across the 

interior of the proto-North American continent (Laurasia) 

during the Middle to Late Devonian and Early Mississippian (see Kepferle, 1993, and Russell, 1993, for similar 

discussions). The abundance of organic material preserved 

in the shales derived from these muds indicates that ambient marine environments that existed during sedimentation 

not only had to support a substantial amount of biologic 

activity at or near the surface of the sea but simultaneously had to preserve much of the produced organic debris as 

it accumulated within fine-grained sediments at depth. For 

this to have happened, the water column would have to 

have been partitioned, or stratified, so that surficial waters 

rich in oxygen and nutrients could have coexisted unmixed with deeper waters that were sufficiently anoxic to 

inhibit complete biodegradation of the abundant organic 

detritus (Potter and others, 1980). Furthermore, these conditions had to be maintained, perhaps intermittently over 

widespread areas of the marginal sea, for periods of time 

sufficient to account for the extent and volume of the existing black-shale formations (see deWitt and others, 1993, 

for black-shale distributions in the Appalachian Basin; 

Hasenmueller, 1993, for the Illinois Basin; and Matthews, 

1993, for the Michigan Basin). 

The causes of widespread anoxia in ancient and modern sedimentary environments have been summarized by 

Demaison and Moore (1980). As defined by them, an 

aquatic environment is anoxic when virtually all aerobic 

biologic activity ceases because of a lack of oxygen. In 

general, bioturbation decreases significantly when sea 

water contains less than 0.5 mL of oxygen per liter of 
260 THE FUTURE OF ENERGY GASES 

water. Locally, the occurrence of oxic versus anoxic environmental conditions results from a flux in the balance between oxygen availability, which is controlled by water 

circulation, and oxygen consumption, which is related to 

the amount of biologic activity. Partitioning of the water 

column into oxic surficial waters and anoxic waters at 

depth requires that there be little or no turnover and mixing of the water column. Turnover is inhibited if there is a 

significant density contrast between the two layers, so that 

lighter surface waters "float" on denser layers below. This 

density contrast may be affected by differences in temperature (thermocline), composition (halocline), or both (pycnocline). Development of a permanent thermocline would 

be enhanced by lack of seasonal variation, such as would 

occur in tropical or subtropical environments; a permanent 

(or seasonal) halocline would occur where there was a 

substantial inflow of fresh water that could be layered with 

little mixing over sea water that had, perhaps, a greaterthan-normal salinity. 

Ettensohn and Barron ( 1981, 1982) and Ettensohn 

(1985) noted that a Devonian and Mississippian "blackshale sea" stratified into oxic and anoxic layers might 

have occurred as the result of both temperature-induced 

and composition-induced density contrasts. Sediments deposited in these two types of environments would be 

markedly different and would produce strata significantly 

different in appearance. Thus, laminated, unfossiliferous 

black shales that contain an abundance of organic matter 

and that are intercalated in the rock record with burrowed 

and fossiliferous green and gray shales and siltstones may 

reflect the transition from anoxic sediments that had accumulated in the lower part of a water column upward 

through a pycnocline into fossiliferous sediments that 

were deposited in relatively shallow water under more 

rigorous oxic conditions. 

The Late Devonian and Early Mississippian paleogeographic reconstructions illustrated by Ettensohn and Barron (1981, 1982) and Ettensohn (1985) permit the general 

conditions that might have led to the development of a 

long-term thermocline. They show that the southern part 

of the Laurasian landmass lay across the paleoequator during the latter part of the Devonian, and thus the epicontinental seas which extended from the Appalachians to and 

across the Transcontinental Arch into southern Alberta 

were in the tropics and subtropics. As a result, seasonal 

temperature changes would have been small, and a permanent thermocline could have been established over a significantly large region. 

Tropical atmospheric conditions in combination with 

regional paleophysiography also may have contributed to 

the establishment of local areas of density stratification in 

the "black-shale sea." Because of the trade winds, which 

flow from east to west along the equatorial bulge of the 

Earth, the eastern part of Laurasia, including the area of 

black-shale deposition, must have been in the rain shadow 

of the Caledonian Mountains and the newly formed Acadian mountain chain. However, the amount of sediment 

contained in the Catskill delta and its antecedents, the Pocono and Price deltas, suggests that there must have been 

abundant accumulation of rainfall in these eastern mountain ranges that flowed westward to where they entered the 

"black -shale sea." 

Su~stantial amounts of fresh water layered over sea 

water could have contributed to the formation of intermittent haloclines along the delta margin. These haloclines 

could have acted in conjunction with a regional thermocline to increase the density stratification of the water column at least locally. As local depocenters shifted from 

place to place along delta margins, less well-mixed waters 

in interdistributary areas might have become stagnant, and 

anoxic conditions would have prevailed on the sea floor. 

In addition, in some places tectonic subsidence and depression of the Middle to Late Devonian and Early Mississippian foreland basin might have restricted water 

circulation sufficiently to have enhanced the development 

of anoxic conditions at depth. When sedimentation rates 

diminished and remained low for extended periods of time 

because of subsidence and regional transgression, the deposition of muds rich in organic detritus would have migrated eastward and accumulated over waning coarser 

grained shallow-water deltaic deposits as anoxic conditions expanded. 

Kepferle (1993) considered the alternations of blackshale strata with gray- and green-shale and siltstone units 

in the Devonian and Mississippian shale sequence to be 

the result of deposition during cycles of regional transgression and regression, which he termed "the black-shale 

cycle." In contrast with most other workers in the Appalachian Basin, he divided the water column into three regimes rather than two-aerobic, dysaerobic, and anaerobic. 

The anaerobic zone was characterized by deposition of black 

shales, generally in deep waters; gray and green shales and 

siltstone, commonly deposited as turbidites, represented 

deposition in the dysaerobic zone, whereas sandstones, siltstones, and shaly mudstones accumulated in the aerobic 

zone (Kepferle, 1993). Kepferle interpreted the black muds 

rich in organic matter to have accumulated in the deepest 

waters of the sedimentary basin, beneath the pycnocline, 

during a period of relative sea-level rise. The lighter-colored 

sediments were thought to have been deposited in a transition zone within or above the pycnocline during regression. Of all the black-shale cycles, only the one initiated 

by deposition of the Sunbury Shale is not truncated by an 

overlying black-shale unit (Kepferle, 1993). Fining- and 

coarsening-upward units (subcycles) identified in well logs, 

such as those illustrated by Milici and Roen ( 1981 ), within 

individual black-shale formations, attest to the complexity 

of local facies variations (fig. 4). Many of the well log 

signatures cannot be correlated with certainty between wells 

and reflect, instead, rapid local variations of coarsening and 
Feet 

3300l 

3400 

A 

Hancock 

Dolomite 

EXPLANATION 

- Black shale 

Shale 

L=:-· --1 Silt 

I! ! !! !I Carbonate rock 

I I Sandstone 

TOGDOE 

7 

A' 

TOGDOE 

4 

Bed? 

0 

w 

co 

~ 

u 

::J 

w 

w 

a: 

I 

r0 

za: 

<(W 

-'CO 

w~ 

>w 

~~ u 

w >-------; 

--' <( 

I 

(fJ 

Q 

I 

0 

a: 

w 

co 

~ 

w 

~ 

z 

0 

a: 

::J 

I 

Figure 4. Cyclic deposition within black-shale formations in the Appalachian Basin as illustrated by gamma-ray logs. Modified from Milici and Roen (1981). Location of section is 

shown in figure 2. The stratigraphic nomenclature and unit assignments used in this figure may not necessarily conform to current usage by the U.S. Geological Survey. 

N 

0\ 
262 THE FUTURE OF ENERGY GASES 

fining of the sediments vertically within the depositional 

basin. 

In contrast with workers in the Appalachian, Illinois, 

and Michigan Basins, Pederson and Calvert (1990, 1991) 

pointed out that anoxia is not a requirement for the accumulation of black muds rich in organic matter in modem 

marine environments. Instead, they noted that recent research in marine sedimentology has demonstrated that 

substantial amounts of organic matter can accumulate and 

be preserved in sediments that were deposited in well-aerated oceanic waters that were producing large amounts of 

organic detritus. 

In addition to productivity, sedimentation rates significantly affect the preservation of organic matter in newly 

deposited sediments, the subsequent formation of source 

beds, and ultimately the hydrocarbon potential of a sedimentary basin. Ibach (1982) pointed out that organic matter, in general, goes through four stages, or zones, of 

alteration as it is buried progressively deeper by younger 

sediments. The process begins with the deposition of the 

organic detritus and its host sediment in an oxic environment in a well-mixed shelf setting. This may be followed 

by progressive burial and successive transitions of the sediment through ( 1) zones of aerobic oxidation and sulfate 

reduction in which the organic matter is degraded by aerobic and anaerobic bacteria, respectively, (2) a zone of fermentation in which methane is produced, and (3) into a 

zone of thermal maturation, in which liquid hydrocarbons 

are produced. 

Ibach (1982) showed that for certain sediment types 

TOC tends to increase with increasing sedimentation rates 

up to a maximum value, after which the effects of dilution 

predominate and TOC percentages decline. For black 

shales, this optimum sedimentation rate is about 41 m of 

uncompacted sediment per million years (Ibach, 1982). 

In the Catskill delta, the places where sedimentation 

rates enhanced the preservation of organic detritus in black 

muds would have shifted across and along depositional 

strike as the local paleogeography changed in response to 

the integrated effects of tectonism, sea-level variations, 

and climate. These places, today, would contain the thickest and richest source beds and, in general, would occur in 

the areas intermediate between the principal deltaic sources on the east and the more distal regions of low sedimentation on the west. 

Anoxia may not have been a requirement for the development of the extensive deposits of black shales that are 

preserved in the Upper Devonian and Lower Mississippian 

rock record of the Appalachian Basin. Instead, the initial 

, geologic conditions necessary to form the basal black-shale 

units of the Devonian and Mississippian "black-shale cycles" may have occurred in those ancient seas where there 

was a coincidence of areas highly productive of organic 

matter with areas of optimal siliciclastic sedimentation 

rates. In other words, muds rich in organic material might 

have accumulated and been preserved where high productivity of organic detritus was associated with moderate sedimentation rates in the marine waters marginal to an active 

delta. In order to preserve the organic matter, sedimentation 

rates would have to be sufficient to bury and remove it 

quickly from the zones of biodegradation; however, the 

amount of sediment could not be so great as to dilute the 

content of the organic material significantly. 

STRATIGRAPHY 

With minor exception, the oldest beds of the Devonian 

shale sequence in the south-central Appalachians are of 

Late Devonian age. They overlie beds ranging in age from 

Ordovician to Middle Devonian that occur below a major 

regional unconformity (deWitt an others, 1993). In the 

south-central part of the Appalachian Basin, the black-shale 

sequence is generally called the Chattanooga Shale in Tennessee and southeastern Kentucky and the Ohio Shale in 

northeastern Kentucky and eastern Ohio (deWitt, 1981). 

The New Albany Shale and Antrim Shale (Matthews, 1993) 

are the approximate lateral equivalents of the Chattanooga 

and Ohio Shales in the Illinois and Michigan Basins, respectively. The stratigraphic nomenclature of Devonian and 

Lower Mississippian strata in the distal part of the Appalachian foreland basin is summarized in figure 5. DeWitt and 

others ( 1993) presented an overview description of the Devonian and associated Lower Mississippian strata of the 

A:_ppalachian Basin and the following discussion of the 

units that occur in the south-central part of the Appalachian 

Basin is summarized mainly from their paper. 

DEVONIAN FORMATIONS 

WEST FALLS FORMATION 

In general, the shale sequence in the south-central part 

of the Appalachian Basin consists of several radioactive 

black-shale units interbedded with units that consist of 

lighter colored gray and greenish-gray beds (fig. 6). In 

most places in this region, a radioactive black-shale unit, 

the Rhinestreet Member of the West Falls Formation, lies 

at the base of the section unconformably above Middle 

Devonian sandstones and carbonate rocks. The thickness 

of the Rhinestreet Shale Member is as much as 150 ft in 

western West Virginia; it is 100 ft or more in eastern Kentucky and adjacent Virginia (deWitt and others, 1993), and 

it thins to the west to where it pinches out in eastern Kentucky and Ohio. The Rhinestreet is recognized in the subsurface by its characteristic gamma ray signature. In 

outcrop, it consists of brownish-black and black shale, 

some gray shale, and numerous limestone nodules and 

concretions (deWitt and others, 1993). 
AUTOGENIC GAS (SELF SOURCED) FROM SHALES-AN EXAMPLE FROM THE APPALACHIAN BASIN 263 

TENNESSEEz 

•Z ·a: Iw Iw SOUTHERN EASTERN SOUTHERN SOUTHERN 

1-1- j,-1- :::l(/) CI:CJ) VIRGINIA KENTUCKY WEST VIRGINIA OHIO 

0<( 0<( 

CJ)W zw 

Sunbury Sunbury Shale Sunbury Shale Sunbury Shale Sunbury Shale 

Berea/ Berea Sandstone Berea Sandstone Berea Sandstone Berea Sandstone 

Bedford 

Equival- Bedford Shale Bedford Shale Bedford Shale Bedford Shale ents 

a; a; 

~Q) ~ E- E Q)as Q) ::;;:65 :2 uo Cleveland Cleveland Cleveland Cleveland c·-

as.c Shale Shale Shale Shale 

CD a;O >- Member Member Member Member 

(ij a>o 

..c u 

(/) Q) Q) Q) Q) ca (ij (ij (ij (ij 

Cl Three Lick Bed .c Three Lick Bed .c Three Lick Bed .c Three Lick 'Bed Three Lick Bed .c 0 (/) (/) (/) (/) 

0 0 0 0 0 c :.2 :.2 :.2 :.2 

:m 0 Upper 0 0 Upper Upper 0 

ca Huron Huron Huron a; ..c ma> ~ 

0 E ,., "E~ a; Q) as ~ Huron :2 :: Q)(/) Middle as :2o E Member Middle Middle Q) (/) Huron Q) Huron (ij (/) c::.C :2 Huron .c as eo (!) =>- c (/) 

IO e c ::J e 

Lower I Lower Lower ::J 

I Huron Huron Huron 

xxxxxxxxxx Java Formation Java Formation A 

Center Hill Q) 

o;~ Pipe Creek Shale Member 7 Pipe Creek Member 

Ash Bed ~ .c Q) Q)(/)~ Olentangy Olentangy !!lc Jg5 Angola Shale Angola Shale ~-" E -o 

Dowell- ...JUQl Shale Shale ~:; Member Member ~~ Town as:2 

ai ~ E Rhinestreet Rhinestreet ~ g Member 

~~ ~~ ~~~ ~ 

;;: & Shale Member ~ Shale Member :S: u. 

Crab Orchard Leipers Limestone Hancock Dolomite Formation "Corniferous" Onondaga Limestone 

Figure 5. Stratigraphic nomenclature of the Devonian and 

Mississippian shale sequence in the Appalachian Basin. Data 

for Tennessee from Kepferle and Roen (1981) and deWitt 

and others (1993), Ohio from Baranoski and Riley (1988), 

Virginia from Jacobeen (1992), Kentucky from Provo and 

The overlying Angola Shale Member of the West Falls 

Formation exhibits less radioactivity than the black-shale 

units and thus is readily defined on gamma-ray logs. The 

Angola ranges in thickness from about 50 ft to over 300 ft 

in the south-central part of the Appalachian Basin. Surface 

exposures of the Angola consist chiefly of medium-gray 

mudrock and shale, with limestone nodules, thin siltstones, 

and some black shales (deWitt and others, 1993). 

JAVA FORMATION 

The Java Formation consists of two members-a blackshale unit at the base that is overlain by a gray and greenishothers ( 1978), and West Virginia from Patchen and Hohn 

(1993) and deWitt and others (1993). The stratigraphic nomenclature and unit assignments used in this figure may not 

necessarily conform to current usage by the U.S. Geological 

Survey. 

gray shale and siltstone unit. The basal Pipe Creek Shale 

Member of the Java Formation overlies the Angola Shale 

Member of the West Falls Formation. Like the Rhinestreet, 

the Pipe Creek is a regionally extensive radioactive black 

shale. It is much thinner than the Rhinestreet, however, 

and generally is less than 25 ft thick except in parts of 

eastern Kentucky and adjacent West Virginia and Virginia 

where it is as much· as 50ft thick (deWitt and others, 1993). 

Overlying the Pipe Creek Shale Member is the Hanover 

Shale Member of the Java Formation. Like the Angola, the 

Hanover is less radioactive than the black shales and consists 

chiefly of gray and greenish-gray shale and mudrock that 

contains limestone nodules and some layers of siltstone and 

black shale. The Hanover ranges in thickness from about 
1 

L, 

------ 3 

'~""' -' 

KY 

2 

,-/ 

2 OH ( 

/,(, 

I 

4 j 

\ '-'-- 5 6 wv 

7 

s\ 

''-

9 /< 

10_ 1 ( , _,''-- / 

I 12 VA 

OHIO 

3 

KENTUCKY 

4 5 6 7 8 9 

KENTUCKY 

10 

VIRGINIA 

11 12 

Brallier 

Shale 

Ql 

Ql 

lL 

0 

0 

l!) 

Marcellus 

Shale 

Wildcat Valley 

Sandstone 

Figure 6. Stratigraphic section of Devonian and Mississippian shale sequence across Appalachian Basin. Modified from Kepferle and others ( 1978). The 

stratigraphic nomenclature and unit assignments used in this figure may not necessarily conform to current usage by the U.S. Geological Survey. 

-3 

::r: 

tr1 

'T1 

c::: 

-3 

c::: 

:;;:l 

tr1 

0 

'T1 

tr1 

z 

tr1 

:;;:l 

C) 

-< 

C) 

>- Vl 

tr1 

Vl 
AUTOGENIC GAS (SELF SOURCED) FROM SHALES-AN EXAMPLE FROM THE APPALACHIAN BASIN 265 

I 00 ft in Virginia and southeastern Kentucky to about 50 ft 

in northeastern Kentucky and Ohio, where it combines with 

the Pipe Creek and Angola and grades to the west into the 

Olentangy Shale (deWitt and others, 1993). 

OHIO SHALE 

The Java Formation is overlain by the Ohio Shale in 

the western part of the Appalachian Basin. The Ohio Shale 

consists of three members- ( I) a lower radioactive blackshale unit called the Huron Member, (2) a middle member, 

the Three Lick Bed (Provo and others, 1978), which is a 

distinctive thin unit of intercalated gray and black shale, 

and (3) an upper radioactive black-shale unit, the Cleveland Member. To the east and south of Ohio, the black 

shales of the Huron Member are split and separated into 

two beds in Kentucky, West Virginia, and Virginia by intervening gray shales and siltstones. 

In general, the Ohio Shale thickens greatly to the east, 

primarily by an increase in the thickness of these gray-shale 

units. The Ohio grades laterally into the Chagrin Shale in the 

northern part of the Appalachian Basin and into the Braillier 

Shale (Kepferle and others, 1978) to the south in Virginia 

and adjacent West Virginia (Potter, and others, 1980). 

The Cleveland Member is the uppermost radioactive 

black shale of the Devonian sequence. It overlies the Three 

Lick Bed and in turn is overlain by the Mississippian Bedford Shale and Berea Sandstone. The Cleveland extends in 

a broad, elongate belt from the southern shore of Lake Erie, 

through central Ohio and eastern Kentucky, to southwestern 

Virginia (deWitt and others, 1993). Where it is thickest, it 

exceeds 50 ft in the Big Sandy area (fig. I) of eastern 

Kentucky; it is over 100ft thick in north-central Ohio. 

Significantly, the thickest net accumulations of Devonian black shales occur in three places in the Appalachian 

Basin- ( I) eastern Kentucky, adjacent Virginia, and West 

Virginia, (2) north-central Ohio, and (3) along the western 

part of the border between New York and Pennsylvania 

(deWitt and others, 1993). In the southern and northern 

parts of the basin, black shales collectively exceed 500 ft 

in thickness, whereas they are about 400 ft thick in Ohio. 

MISSISSIPPIAN FORMATIONS 

BEDFORD SHALE AND BEREA SANDSTONE 

The Bedford Shale and Berea Sandstone represent a 

period of basin infilling during a late stage of Acadian deltaic sedimentation. In general, grain sizes in these formations increase both upward and toward their source areas 

and, except in northern Ohio where sand-filled channels 

cut into underlying finer grained clastics, the transition 

with the overlying strata is gradational (deWitt and others, 

1993). In much of the area, the Berea is a relatively thick 

zone of relatively high porosity within the black-shale sequence. In Virginia, for example, the Berea is as much as 

150 ft thick and produces significant amounts of gas. Initial wellhead pressures commonly range from 500 to 800 

pounds per square inch and final open flows commonly 

attain volumes up to I ,400 thousand cubic feet per day 

(Mcf/d), although in some wells they may be much greater 

(Nolde and Milici, in press). 

Pepper and others ( 1954), in their study of the Bedford and Berea, provided the foundation for modern paleogeographic interpretations of the uppermost part of the 

Appalachian Devonian and Mississippian shale sequence 

(fig. 7). They showed that during deposition of the Bedford, Berea, and Sunbury, land was exposed over much of 

western Ohio, on the eastern flank of the Cincinnati Arch. 

Sediment input during the deposition of the Bedford was 

generally from the north and the east and extended southwestward and westward from Canada into the northern 

part of the Appalachian Basin in Ohio and westward from 

deltaic sources along a north-northeast-trending coastline 

from Pennsylvania to Virginia (Pepper and others, 1954). 

In general, the paleogeography and drainage patterns established during the time of deposition of the Bedford 

Shale persisted around the basin as coarser grained sediments prograded into the region and Berea sandstones 

began to accumulate within the basin. 

Mich. 

---- - - - --, ,--- --

Ind. 

1 

' 

I 

' ' I 

I 

Ky. 

OHIO 

W.Va. 

Figure 7. Generalized paleogeography, Bedford-Berea time. 

White area, marine black shale; stippled area, delta and coastal 

plain. Modified from Pepper and others (1954, pl. l3g). 
266 THE FUTURE OF ENERGY GASES 

The Berea was deposited as nonmarine and marine 

sands on and seaward of a low-lying coastal plain that 

stretched around the periphery of the Appalachian Basin 

from Virginia northeastward to western Pennsylvania and 

then westward to Ohio. Sediments were transported into the 

region by relatively small rivers, named by Pepper and others (1954) the Gay Fink and Cabin Creek channels in West 

Virginia and the Virginia-Carolina delta in Virginia and eastern Kentucky. Perhaps the most significant source of sandy 

sediments was from the Canadian shield to the north via the 

Berea delta, which emptied into the basin in northern Ohio. 

Recently, more detailed work in southwestern Virginia 

by Nolde and Milici (in press) has identified north-trending zones of relatively thick Berea Sandstone, which they 

interpret to represent coast-parallel marine bars that appear 

to have been deposited just offshore of the Virginia-Carolina delta. These bars are significant zones of gas production in the Virginia gas fields. To the west in Virginia, 

deposits contemporaneous with the Berea are compositionally immature finer grained sandstones and shaly siltstones 

that apparently were deposited in deeper waters on the 

nearby shelf (Potter and others, 1983). 

SUNBURY SHALE 

In the more distal part of the basin, the marine black 

Sunbury Shale is the uppermost radioactive shale of the 

Acadian Catskill delta sequence. Lithologically, the Sunbury is a dark-gray to black shale with thin siltstones or 

silty laminations. The Sunbury formed as a transgressive 

deposit during a final phase of Acadian tectonic activity 

(Kammer and Bjerstedt, 1986). The Sunbury overlies marine shelf siliciclastic deposits of Early Mississippian age, 

the Berea Sandstone and Bedford Shale, and is in turn 

overlain by the less radioactive siliciclastic deposits of the 

Borden and Price Formations in eastern Kentucky and adjacent Tennessee, by the Cuyahoga Formation in Ohio, 

and by the Pocono Sandstone or Price Formation in Virginia and West Virginia. Kammer and Bjerstedt ( 1986) included the Sunbury as a member within the lower part of 

the Price Formation in southwestern Virginia. 

PRICE FORMATION 

The Price Formation was deposited during the last 

stages of Acadian deformation and uplift, perhaps as a posttectonic molasse in prodelta, littoral, and nonmarine environments in the southwestern part of the Virginia Valley 

and Ridge Province (Kreisa and Bambach, 1973). The Price 

is noted for containing the oldest coalbeds in North America that have been exploited commercially. The formation is 

a progradational unit, with nonmarine coal-bearing beds 

overlying marine units. Progradation was generally from 

the northern and eastern part of the basin to the south and 

west; although the formation maintains approximately the 

same thickness along its outcrop, the proportion of marine 

units increases generally in the direction of progradation 

(Kreisa and Bambach, 1973, fig. 2). In general, the formation is 500 to 600 ft thick, although in places it is as much 

as 800 ft thick. 

RESOURCE POTENTIAL 

OF THE SHALES 

The potential of the Devonian black shales to produce 

natural gas is a function of the type, amount, and thermal 

maturation of their contained organic matter and the overall characteristics of the gas reservoir. The following review is based on only a few of the more comprehensive 

papers that have resulted from DOE's recently concluded 

Eastern Gas-Shales Project (EGSP) and several other 

smaller projects. 

Zeilinski and Mciver (1982), in a report prepared by 

the Mound Facility for DOE's Morgantown Energy Technology Center (METC), summarized the data from more 

than 2,000 core and several hundred cutting samples from 

numerous wells drilled in the Appalachian Basin. They 

concluded that the potential of the Devonian shale formations as a source for hydrocarbons could be related to 

three key parameters: ( 1) the quantity of organic carbon 

in the rock (total organic carbon, TOC), (2) the origin of 

the organic matter contained within the shales (for example, from normal marine life, the gn;en algae Tasmanites, 

and (or) terrestrially derived plant matter); and (3) the extent of thermal alteration of the organic matter by the heat 

of the Earth, expressed as thermal alteration index (TAl) 

values. 

CONTENT AND CHARACTER OF 

ORGANIC MATTER 

Zeilinski and Mciver (1982) and Maynard (1981) 

pointed out that the high proportion of organic matter in 

the Devonian black-shale units in the western half of the 

Appalachian Basin decreases eastward across the basin 

because of dilution by siliciclastic sedimentation. For example, Maynard (1981) showed that the weight percent of 

organic carbon ranges from 1.0 to 10.0 percent from the 

axial part of the Appalachian Basin westward to the Cincinnati Arch. 

Schmoker (1980, 1981, 1993) defined "organic-rich" 

Devonian shales as those containing 2 percent or more organic matter. Using data from gamma-ray logs, he calculated and mapped the "net thickness of organic matter in 

organic-rich Devonian shale facies." His map shows that 
AUTOGENIC GAS (SELF SOURCED) FROM SHALES-AN EXAMPLE FROM THE APPALACHIAN BASIN 267 

the greatest net thickness of organic matter occurs in a 

broad north-south trend that extends from eastern Kentucky and adjacent West Virginia northward into central 

Ohio. 

Zeilinski and Mciver (1982) noted that on the western 

side of the Appalachian Basin, the kerogen type is principally derived from algae or other marine biota (types I or 

II), whereas on the eastern side of the basin, woody and 

coaly forms (type III) predominate. Palynological studies 

have determined that a very important source of organic 

material in the Devonian black shales is the fossil marine 

algae Tasmanites. In certain deposits, very large amounts, 

or blooms, of Tasmanites apparently overwhelmed and excluded other types of biota from the euphotic zone in the 

water column. Biofacies maps prepared by Zeilinski and 

Mciver (1982, figs. 34-50) for several of the Devonian 

shale stratigraphic units illustrate the distribution of organic matter that was derived from terrestrial sources, 

from normal marine sources, and from marine sources 

that were dominated by Tasmanites. In ·general, these 

maps show that the organic matter in Devonian strata in 

the western part of the Appalachian Basin is dominantly 

of open marine and of Tasmanites origin, whereas in the 

eastern part of the basin, most of the organic matter was 

derived from nearby terrestrial sources. For some of the 

Devonian units, however, the distribution of the data 

points suggests that there may have been a western source 

for a part of the terrestrially derived organic matter, perhaps from an emergent part of the Cincinnati Arch. These 

units include the upper part of the Olentangy Shale and 

Hanover Shale Member of the Java Formation, the middle 

and upper beds of the Huron Member of the Ohio Shale, 

and the Chagrin Shale (Zeilinski and Mciver, 1982). The 

distribution of these data points, however, leaves room for 

interpretation of the direction of the source of this carbon 

(type III). 

Maynard (1981) studied the carbon isotopes in the organic matter, and showed that the only likely source of 

terrestrially derived carbon was to the east. In general, 

available carbon isotope ratios range in value from -24.8 

permil (terrestrial origin) to -30.4 permil (marine origin). 

Values from intermediate data points become increasingly 

more negative (more marine) toward the west. This distribution was interpreted by Maynard (1981) as having resulted from a mixing and progressive dilution of the 

terrestrially derived carbon isotope with the isotope that 

was selectively metabolized by marine biota in the submerged part of the Appalachian Basin. On the basis of 

these data, Maynard ( 1981) concluded that the Cincinnati 

Arch was not emergent during the deposition of the blackshale sequence. A comparison of carbon-isotope data values derived from gas with those derived from the source 

rocks would indicate the direction and extent of gas migration within the Appalachian Basin. Isotope data from 

gas, however, are currently not available. 

THERMAL MATURITY 

The thermal maturity of the Devonian and Mississippian black-shale sequence in the Appalachian Basin has 

been mapped by several different methods, which include 

variations in conodont colors expressed as the conodont 

alteration index (CAl), variations in the colors of plant 

pollen, spores, and cuticle fragments (thermal alteration 

indices, TAl), and vitrinite reflectance (R0 ). Harris and 

others (1978) used CAl values to prepare a regional thermal maturation map of the Appalachian Basin. This method has the advantage of utilizing data from carbonate 

strata, which contain little or no woody or other plant material. In general, regional trends in thermal alteration as 

illustrated by the conodonts do not follow the structural 

grain of the Appalachians. Instead, they cut across the regional structural grain and follow the overall thickness 

trends of the Appalachian Basin fill, especially that contribution to the fill made by the Devonian and Mississippian 

Catskill delta. 

Zeilinski and Mciver (1982) used TAl to illustrate the 

range of thermal maturity of the Upper Devonian units of 

the Appalachian Basin. They noted that the rocks in the 

western part of the Appalachian Basin are thermally immature with respect to oil generation. Consequently, only a 

limited amount of hydrocarbons has been generated and 

only a part of the potential of the source rocks has been 

realized. In contrast, in much of the eastern part of the 

Appalachian Basin the Devonian and Mississippian blackshale sequence is overmature, and little potential remains 

for generation of liquid hydrocarbons. 

The immature Upper Devonian and Lower Mississippian strata on the western side of the Appalachian Basin 

contain the greatest amount of oil-prone source beds. In 

comparison, source beds on the eastern side of the basin 

are more gas prone, occur in modest proportions to organically lean strata, and are mature to overmature with respect to oil generation. It is the intermediate part of the 

basin, where there is a coincidence of relatively high-quality source rock and an appropriate amount of thermal maturation, that had the greatest potential for generation of 

liquid hydrocarbons and has the potential for commercial 

production of locally sourced shale gas. The type of organic matter apparently does not affect the quantitative 

capacity of a source bed to yield gas. Instead, the total 

amount of organic matter and the degree of thermal maturation appear to be the significant variables that determine 

the gas-producing potential of the source rock (Claypool 

and others, 1978). 

Interestingly, Zeilinski and Mciver (1982) observed 

from the distribution of historical production data that oil 

apparently was first generated in the Devonian shales of 

the Appalachian Basin farther to the east and at higher 

temperatures than would normally be expected, at the 

TAI=3 isoline, rather than at the TAI=2 isoline. They 
268 THE FUTURE OF ENERGY GASES 

suggest that the exceptionally low permeability of the 

shale required a greater-than-normal thermal stress for the 

generation of liquid hydrocarbons than· otherwise would 

have occurred. Alternatively, the oil could have migrated 

into the area after maximum maturity levels were set. 

Maynard (1981) and Schmoker (1993) used vitrinite 

reflectance values expressed as percent R0 and arrived at 

the same general conclusion as Zeilinski and Mciver 

(1982) concerning the thermal maturation of the Devonian 

and Mississippian shale sequence, even though their maps 

differ in detail. In general, R0 values of vitrinite in the 

shale sequence increase from about 0.5 to 2.0 percent eastward across the Appalachian Basin, with the principal 

areas that are producing gas in Virginia, eastern Kentucky, 

and West Virginia generally having R0 values between the 

0.6 and 1.5 percent isolines. These R0 values (0.6 to 1.5 

percent) suggest that the gas produced is either biogenic or 

that some thermogenic gas has migrated to the west and is 

being produced from these relatively immature areas. 

The probable eastern limit of oil in the hydrocarbonproducing region of the south-central part of the Appalachian Basin is illustrated in figure 2. This map encompasses 

all of the producing Paleozoic strata in the basin and is 

based on fixed carbon/free carbon ratios (Miller and Fuller, 

1954 ), CAl isograds (Harris and others, 1978), and the observed distribution of oil and gas. 

SOURCE-ROCK-POTENTIAL MAPS 

On the basis of a regional study and synthesis of data 

from thermal alteration indices, organic carbon content, 

and an analysis of the biofacies of the Devonian and Mississippian shale sequence, Zeilinski and Mciver (1982) 

prepared maps for several of the stratigraphic units in the 

sequence, illustrating these units' potential for oil and gas 

production in the Appalachian Basin. The map, which 

combines the effects of formation thickness with source 

quality, shows that the overall gas potential is greatest in 

southeastern Ohio, eastern Kentucky, western Pennsylvania, and southwestern New York (Zeilinski and Mciver, 

1982). In general, these areas are not the ones that are producing most of the shale gas today. The map illustrating 

the overall potential of the shale sequence as a source for 

oil shows a pattern similar to the map for gas; however, 

areas of potentially favorable source beds are smaller for 

oil (Zeilinski and Mciver, 1982). Like the areas with the 

high potential for producing gas, the areas with the greatest potential for producing oil are not the areas from 

which most of the historical production has been obtained. 

Vitrinite reflectance data, however, indicate that the 

high-potential areas of Zeilinski and Mciver (1982) in 

much of Ohio are immature with respect to oil generation, 

whereas the areas in western Pennsylvania and adjacent 

New York are overmature. The delineation of geochemically favorable areas (Zeilinski and Mciver, 1982) from areas 

of high historical production thus is partly related to the use 

of TAl data to determine thermal maturity and partly related to other factors, especially porosity and permeability, 

that are essential to ensure production of the resource in 

commercial quantities for a sustained period of time. 

Schmoker (1993) adopted the 0.6-percent R0 vitrinite 

reflectance contour as the approximate onset of oil generation and the 1.5-percent R0 contour as marking the maturity 

at which oil breaks down to condensate and begins cracking to gas. He showed that the zone of oil generation coincides with the greatest accumulation of organic carbon in 

the Devonian shale in eastern Kentucky and adjacent West 

Virginia. With the exception of the Lake Shore Fields in 

Ohio, Devonian shale-gas production occurs generally to 

the east of the 0.6-percent R0 isoline. Vitrinite reflectance 

data thus appear to reflect the hydrocarbon potential of the 

Appalachian Basin more accurately than TAl data. 

ROLE OF STRUCTURE AND 

FRACTURE POROSITY 

The two major geologic structures that affect the accumulation of oil and gas in the Appalachian Basin are the 

Rome Trough, which is a Cambrian graben system that 

formed by extension and perhaps by strike-slip movement 

in the Grenville-age crystalline basement, and the subhorizontal decollements and associated ramp anticlines that 

occur in the overlying Paleozoic sequence (fig. 8). 

The Rome Trough (the Eastern Interior aulacogen of 

Harris, 1978) extends from the Mississippi Embayment generally eastward across Kentucky to West Virginia and then 

northeastward through Pennsylvania into southern New 

York. The trough forms a keellike feature beneath the Appalachian Basin that is filled with an overthickened sequence 

of Cambrian siliciclastics that are correlated crudely with the 

Rome Formation of eastern Tennessee and southwestern 

Virginia, hence the name "Rome Trough." Evidence from 

seismic cross sections and drilling indicates that the trough 

was first formed in Early Cambrian-or perhaps latest Precambrian-and was intermittently active at least into the 

Devonian (Harris, 1978; Shumaker, 1986). Cores taken from 

wells in the Rome Trough in West Virginia contain Middle 

Cambrian fossils (Donaldson and others, 1975). 

Although late-stage movement on the Rome Trough 

appears to have had little effect on the location and 

production of natural gas from the Devonian and Mississippian shales, it may have produced late-stage fractures 

in these strata in some places in West Virginia (Shumaker, 

1993, p. K9). In north-central Tennessee and south-central 

Kentucky, the coincidence of the Rome Trough with the 

Cumberland Saddle appears to have enhanced the production 

of hydrocarbons from fractures in Ordovician limestones. 

Perhaps the single most widespread mechanism for 

producing structural traps and reservoir porosity within the 

Appalachian foreland is the subhorizontal bedding-plane 
AUTOGENIC GAS (SELF SOURCED) FROM SHALES-AN EXAMPLE FROM THE APPALACHIAN BASIN 269 

t 

N 

I 

0 100 Miles 

EXPLANATION 

Pennsylvanian rocks 1: •: • :1 Decollement in Silurian, 

Devonian and L::=J Cambrian to Mississippian 

rocks 

Mississippian rocks 

lttttt;J Precambrian and 

Paleozoic rocks 

~ Decollement in Silurian rocks 

~ Decollement in Ordovician 

rocks ~ Decollement in 

Pennsylvanian rocks - - - Approximate boundary of 

Rome trough 

Figure 8. Location of Rome Trough and distribution of decollement zones in middle and upper part of Paleozoic sequence in the 

Appalachian Basin. 

decollement (Milici, 1980a). Multilevel decollement occurs throughout the southern and central Appalachian Valley and Ridge Province and Plateaus in strata ranging in 

age from Cambrian to Pennsylvanian (Milici, 1980a). In 

the productive part of the Appalachian Plateau region, 

those subhorizontal decollements and associated structures 

that occur in the middle part of the Paleozoic sequence, 

from the Ordovician Martinsburg Shale to the Devonian 

shales, are the ones that most directly affect the formation 

of reservoirs and traps for hydrocarbons. 

In much of the folded region of West Virginia and 

Pennsylvania, major oil resources are in porous beds that 

have been folded and faulted, primarily as superficial 

structures above decollement in salt and shale beds. Fracture porosity commonly augments intergranular porosity 

in tightly folded anticlines where strata were forcefully 

ejected from anticlinal cores during the folding process 

(deWitt and Milici, 1989). In addition, decollement is 

the principal mechanism for creating bedding-parallel 

zones of fracture porosity in selected sedimentary strata. 
270 

c 

0 

'iii 

c 

Q) 

x 

Q) 

Q)Q 

c 

0 

N 

Q) 

;, 

ti 

!1l .;:, 

"-~ cCll~Q) 

aJOlc Ul cEo "0 oo- Q) -- Ul .0 Q) Ul 010 

(ij (ij "0 c c coco 

() 

0 (/) 

£ ~UC/l 

~mo !!! Q) ~ 'S c ::J ~ 

N 

0 ~ c 

"0 c 0 

Q) 0 ·u 

"OQ; 'iii 

c ~ ro> Q) c 00 x 0 o:u w () 

~§~ 

THE FUTURE OF ENERGY GASES 

-o 

-= o;

~ Q) 

8 

0 

0 

.<:: 

~ ~ 

-o 

§ 

,.-.. 

rr0\ 

-'-' 

] 

~ -o 

-= o;

-~ 

:r: 

8 

0 

<!::: 

-o 

Q) 

<J:: 

:a 

0 

::E 

.; 

Q) 

"' "' Q) 

c -= 

~ 

... -= 

Q) 

.s 

::I 

0 

"' ci 

<;; 

-= "' § 

·s 

o; 

;;. 

~ 

"' -= 

-= 

~ ... 

Q) 

~ 

0 

-l 

.5 

= Q) 

8 

~ 

0 

u 

Q) 

-o 

2 

-o 

~ 

] 

"' Q) 

·a 

u 

o; 

<!:: 

...... 

0 

e 

Q) 

~ c. 

-o 

Q) 

-~ 

03 

... 

Q) 

-= . Q)---

0~ • 0\ 

=" -'-' 

f:! ~ = Q) 

~~ 

Effective fracture porosity is best developed where tectonic transport and deformation in the decollement zone is 

low to moderate. Extensive deformation within the decollement commonly results in the destruction of the fractured reservoir and a significant loss of the original volume 

of gas. 

The nature of decollement tectonics and the generation 

of subsidiary fractures in the folded and faulted Appalachians was described by Harris and Milici (1977). They 

determined that the position and character of subhorizontal 

decollement within a given stratigraphic sequence is closely controlled by subtle lithologic variations. Of particular 

importance in localizing subhorizontal decollemept in Devonian and Carboniferous rocks in the Appalachians are 

shale beds (especially if they are rich in organic matter) and 

coalbeds. These shale and coal beds are the principal sources of gas in the Appalachian Basin, and the release of gas 

from the source beds where they were tectonically deformed could have overpressured some of the fractured 

shale reservoirs (Shumaker, 1993) . 

Decollement and decollement-related structures commonly may be divided into two regimes-a zone of extremely fractured or brecciated rock called a broken 

formation and an overlying zone of fracture (Harris and 

Milici, 1977) (fig. 9). In the broken formation, fractures 

consist primarily of subhorizontal shears that are overprinted by later stage, relatively high-angle extensional and contractional faults. These latter faults commonly extend 

upward from the broken formation zone into a less-deformed zone of fracture. This pattern of deformation commonly encompasses all scales ranging from dimensions of a 

few ft to tens or hundreds of feet of strata, depending upon 

the local stress regime during deformation . 

In many places in the Appalachian Plateau near the 

western limits of detachment, the contact between deformed and undeformed strata is abrupt, with little or no 

gradation between. The hanging wall may show little or no 

deformation that can be related to westward tectonic transport and shortening. In these places, the deformed strata in 

the decollement zone appear to have been squeezed like 

toothpaste between hanging and foot walls. For example, in 

some places in the plateau regions of Tennessee and Virginia, coalbeds normally a few feet thick are squeezed along 

the bedding into intensely deformed tectonic rolls 20 ft or 

more thick. Where this has happened, several thick coal 

rolls may be connected to one another by thin leads (leaders) of coal (Nelson, 1925; Milici and Gathright, 1985; Milici and others, 1986). 

Similar deformation has been observed in outcrop in 

the Devonian/Mississippian shales of Virginia and Tennessee (Milici and Statler, 1980; Milici, 1980b; Harris and 

Milici, 1977). In the subsurface of southwestern Virginia 

and eastern Kentucky, all gradations of deformation occur 

in the shale, from serving as the locus of a major decollement beneath the Pine Mountain thrust sheet (Young, 
AUTOGENIC GAS (SELF SOURCED) FROM SHALES-AN EXAMPLE FROM THE APPALACHIAN BASIN 271 

1957; Jacobeen, 1992) to localizing the decollement of 

much lower magnitude that occurs as a blind thrust in the 

Big Sandy Gas Field (Shumaker, 1993) and, perhaps, to 

the toothpaste tectonics that occur in the lesser deformed 

regions of southeastern Ohio. Wilson and others ( 1980) 

and Shumaker (in press) observed this range of structural 

deformation in cores drilled into the black shales across 

the Appalachian Basin, and Shumaker noted the progressive decrease of subhorizontal shears westward from eastern Kentucky into Ohio. Schumaker (I 980) coined the 

term "porous fracture facies" to describe the extensive 

fracturing that is related to subhorizontal deformation in 

the lower Huron black shales and hypothesized that these 

decollement zones were related to overpressured gas 

zones in the Devonian shale. 

There is little doubt that in most of the Appalachian 

Basin, fracturing of the gas-producing shale zones was induced by tectonic forces. However, in the relatively low 

production Devonian shale-gas fields in the northern part 

of the basin, along the southern shores of Lake Erie in 

Ohio, Pennsylvania, and New York, shallow fractures may 

have been affected and (or) enhanced by the southward 

movement of ice sheets over the shales during the Pleistocene (White, 1992). 

PLAYS AND PRODUCTION 

CHARACTERISTICS OF THE DEVONIAN 

AND MISSISSIPPIAN SEQUENCE IN THE 

SOUTH-CENTRAL APPALACHIAN BASIN 

In general, the production characteristics of the shalegas-producing regions in the Appalachian Basin reflect 

major differences in (1) organic-carbon content, (2) thermal maturity, and (3) fracture porosity along and across 

the basin. Although production is obtained in areas that 

do not have the optimal conditions for long-term and relatively high-yield fields, the best results are obtained 

where all three conditions are optimal (table I). In only 

one of the three major shale-gas-producing areas in the 

Appalachian Basin are the three conditions optimal. 

The Lake Shore Fields in northern Ohio and Pennsylvania (see fig. I) are in a region that is immature for thermogenic gas, suggesting that the gas produced there may 

have migrated into the region from elsewhere in the Appalachian Basin. It is possible, however, that this gas was 

generated locally and is of biogenic origin. The subeconomic emerging area of West Virginia is located on the 

eastern margin of the main trend of high organic carbon 

within the black shales. Only in and near the Big Sandy 

area is there a coincidence of high organic-carbon content within the source beds, suitable thermal maturity, 

and a shale reservoir that is enhanced by decollement-induced fracture porosity. 

The Big Sandy Gas Field in eastern Kentucky (see fig. 

I) has produced gas from various reservoirs since 1914 

and from Upper Devonian shales since 1921 (Hunter and 

Young, 1953). In this area, the potentially productive reservoir ranges from about 350 to 750 ft in thickness. Without treatment, most of the wells drilled into these gas 

shales yielded little or no gas. For example, approximately 

6 percent of the 3,400 wells studied by Hunter and Young 

(1953) were completed without treatment, and these wells 

had an average open flow of about 1,055 Mcf/d. The approximately 3,200 wells remaining were shot with nitroglycerine; it was common practice in the early decades of 

exploration to stimulate the well by shooting the entire 

shale interval with at least 3,000 to 7,000 pounds of explosives. In these wells, initial open flows of gas averaged 

about 61 Mcf/d before shooting and final open flows averaged about 285 Mcf/d after shooting. Hunter and Young 

(1953) concluded that fractures enhanced by the explosives were the principal cause of porosity and permeability 

Table 1. Generalized production characteristics of three shale-gas producing regions in the Appalachian Basin. 

Region 1 

Lake Shore Fields, Ohio and 

Pennsylvania. 

Emergin area, West Virginia---------

Southern Ohio, southwestern West 

Virginia, and eastern Kentucky 

(Big Sandy Gas Field) and 

Southwestern Virginia (Roaring 

Fork Field). 

1 Shown on figure I. 

Organic-carbon Relative thermal 

content maturity 

High to low-------- Immature---------

Medium to high--- Mature------------

High ---------------- Mature------------

Natural fracture 

porosity 

Good ----------

Good----------

Very good----

Production characteristics 

Intermediate- to long-term low-production 

wells. 

Final open flow after treatment is high; 

organic carbon content not sufficient to 

maintain long term production, and 

wells decline in a matter of months. 

Final open flow after treatment is high; 

production decreases sharply at first; 

wells stablilize at very long term, lowto-moderate yields. 
272 THE FUTURE OF ENERGY GASES 

within the shales and that effects of porosity and permeability in silty and sandy zones within the shale sequence 

were relatively minor. Common practice at present is to 

stimulate selected zones within wells with a liquid nitrogen foam frac utilizing sand as a proppant. 

Baranoski and Riley (1988) noted that the lower part 

of the Huron Member is the primary and most prolifically 

producing Devonian shale unit in southernmost Ohio. 

There, shale-gas wells that have an initial potential greater 

than 200 Mcf/d appear to have been drilled into reservoirs 

with a higher-than-normal fracture porosity that somehow 

may be related to local folds and faults. In general, data 

available for 29 shale-gas wells show that the average well 

in southernmost Ohio declines from about 45 Mcf/d to 

about 25 Mcf/d over a 10-year period. Thereafter, the decline rate flattens, and production is maintained at about 

25 Mcf/d for 30 years or more. For a 30-year period, the 

cumulative production from Ohio shale-gas wells averages 

0.311 billion cubic feet (Bcf). 

In the Roaring Fork Field in southwestern Virginia 

(see fig. 1 ), 16 shale-gas wells completed exclusively 

within the Devonian shales exhibit an average final open 

flow after completion of about 133 Mcf/d. More commonly, production from Devonian shale in this field is comingled with gas produced from the Mississippian Berea 

Sandstone, Price Formation (Weir of drillers' usage), and 

(or) Greenbrier Limestone (Big Lime of drillers' usage). 

Final open flow data from comingled wells averages about 

843 Mcf/d. 

Patchen and Hohn ( 1993) made a detailed study of production decline curves for wells in a three county area, the 

area of long-term historical production in southwestern 

West Virginia where the Big Sandy Gas Field enters the 

state from Kentucky, and compared them with production 

decline curves from the six county area immediately to the 

north in the more recently emerging area of shale-gas 

production (see fig. 1). They determined that the annual 

production rates of wells in the emerging area at the end of 

their first year were less than annual production rates from 

wells in the historical area to the south after 30 years. 

Average shale-gas wells in the area of historical production in West Virginia generally have an initial production (IP) of between 250 and 300 Mcf/d. They decline 

within 10 years to about so· Mcf/d and after 40 years are 

producing about 20 Mcf/d. Patchen and Hohn (1993) estimated that the average shale-gas well in southern West 

Virginia produces 0.5 Bcf after 40 years. In comparison, 

available production data from the northern part of the 

newly emerging area shows that wells there decline generally from about 36 Mcf/d to about 10 Mcf/d in 12 months. 

Patchen and Hohn (1993) concluded that in spite of a few 

good wells, the emerging area will prove to be noncommercial. This most likely is because of the relatively low 

amount of total organic carbon available for generation of 

hydrocarbons in that area (Schmoker, 1993) as well as the 

migration of generated gas westward, away from the deeper parts of the Appalachian Basin, during the Alleghanian 

orogeny. 

Wells have been producing gas from the Devonian 

shales in the Lake Shore Fields of northern Ohio and adjacent Pennsylvania for more than 100 years. Drilling 

began in Pennsylvania during the 1850's and continued into 

Ohio a decade later (Janssens and deWitt, 1976). Many 

hundreds of wells were drilled, mainly for domestic purposes, and their initial production commonly ranged between 1 and 50 Mcf/d. These wells have declined very 

slowly and some have produced gas for 50 years or more. 

Unlike the wells in fields in the south-central part of the 

Appalachian Basin, these wells have produced mainly from 

silty and sandy zones in the Chagrin Shale and Three Lick 

Bed. Fracture porosity is of secondary importance and apparently has served to conduct the gas from the black-shale 

source beds of the Marcellus, Rhinestreet, and Huron into 

the more porous units (Broadhead and others, 1982; Broadhead, 1993). 

SHALE-GAS PLAYS AND 

POTENTIAL IN OTHER BASINS 

Black shales of Devonian and Mississippian age occur 

in several basins in the Rocky Mountain region and interior of North America. The New Albany Shale of the Illinois Basin (Hansenmuller, 1993; Cluff, 1993) and the 

Antrim Shale of the Michigan Basin (Matthews, 1993; 

Gutschick and Sandberg, 1991; Decker and others, 1992) 

contain many of the aspects _of their counterpart in the Appalachian Basin and, indeed, include some of the units 

named from the Appalachians. The Woodford Shale is an 

important source for hydrocarbons in the Anadarko Basin 

(Schmoker, 1989) as is the Bakken Formation in the 

Williston Basin (Price and LeFever, 1992; Schmoker, 

1993 ). The locations of basins discussed herein are illustrated in figure I 0. 

Of these black shales, the Antrim has been the most 

explored in recent years for shallow gas. In general, exploration for Antrim shale gas is confined to the northern part 

of the Michigan Basin. Approximately 2,000 wells were 

completed in the Antrim Shale between the end of 1986 

and the end of 1991, when about 1,350 wells were producing 123 million cubic feet of gas per day (MMcf/d) of 

shale gas (Decker and others, 1992). These shale wells 

typically produce 25 to 150 Mcf/d (average 70-80 Mcf/d) 

from depths of about 305-500 m (Gordon Dolton, U.S. 

Geological Survey, written commun., 1993). The Antrim 

has produced gas since the 1940's and contains an estimated gas reserve of 76 Tcf (Decker and others, 1992). These 

wells are commonly fractured with nitrogen foam, utilizing sand as a proppant. 
AUTOGENIC GAS (SELF SOURCED) FROM SHALES-AN EXAMPLE FROM THE APPALACHIAN BASIN 273 

Figure 10. Locations of major black-shale basins in Eastern and Central United States. 

Like Devonian-shale source beds in the Appalachians, 

the Atrim contains a great deal of organic matter. Total 

organic-carbon content, determined from analyses of several 

hundred samples, averages about 8 percent and ranges from 

2 to 25 percent. Kerogen in the Antrim has been determined 

to be hydrogen rich and oil prone, the gas is thermogenic 

in origin, and thermal maturation is related to burial depth 

(Decker and others, 1992). As a result, the currently producing area occurs generally at shallow depth on the northern 

edge of the Michigan Basin, an area of relatively low thermal 

maturation. Delta carbon-13 (0 13C) isotope values, pyrolysis 

data, and total-organic-carbon measurements, however, indicate that Antrim gas has been generated in place by thermal maturation of kerogen within the black shales of the 

lower part of the Antrim (Manger and Curtis, 199 I). 

Although porosity in the Antrim as determined from 

core analysis ranges from 5 to 15 percent, matrix permeabilities are low. Thus, fracturing is essential to provide 

additional porosity and to convey the gas to the well bore. 

Unlike parts of the Appalachians, however, bedding-parallel decollement apparently does not play a role in fracture 

generation in the Michigan Basin. Instead, the principal 

mechanisms for fracture production within the Antrim shale 

are regional structures, including joints, fractures associated 

with folding and possibly fractures caused by isostatic 

movements related to glaciation (unloading fractures). 

If favorable conditions of high organic content, thermal maturity, and porosity and permeability persist southward into the core of the Michigan Basin, the entire region 

has a substantial potential for the production of shale gas 

as well as for generation of oil from these enriched source 

beds. It should be noted that activity in the basin declined 

sharply in I 991, which probably reflects Jess favorable 

economic conditions for gas exploration. 

It should be mentioned that production from shallow 

gas fields in the Niobrara Formation in the Denver Basin, 

Colorado, Kansas, and Nebraska, is in many ways similar 

to the production of gas from shales (Pollastro and 

Scholle, 1986; Lockridge and Pollastro, 1988). There, biogenic gas is produced from chalk beds that are sufficiently 

enriched in organic matter to be self sourcing; reservoir 

depths range generally from 300 to 1,000 m. The chalk 

reservoirs have a relatively high porosity and a low permeability which must be enhanced by fracturing; initial 

production from wells stimulated with foam ranges from 

100 to 1,200 Mcf/d. 
274 THE FUTURE OF ENERGY GASES 

84°00' 

42°00'!----:;;>""=~rf--_____,,.L ___ ~LLxfl--.L 

50 

I I I 

It I 

50 0 I 

76°00' 

LAKE 

EXPLANATION 

[IT] Potentially favorable areas for 

thermogenic gas, based on mass 

of organic carbon (kg/cm2) 

and thermal maturation 

0 Producing areas 

J 0.8 kg/cm2 isoline 

-0.6- Vitrinite reflectance values (percent Ro) 

50 MILES I 

50 KILOMETERS 

Figure 11. Relationship of areas producing gas from Devonian shales in the Appalachian Basin to mass of organic carbon (area with 

values greater than 0.8 kg/cm2

) and thermal maturation. Modified from Schmoker (1993, fig. 9). 
AUTOGENIC GAS (SELF SOURCED) FROM SHALES-AN EXAMPLE FROM THE APPALACHIAN BASIN 275 

SUMMARY AND CONCLUSION 

The Devonian and Mississippian shale-gas fields of the 

south-central part of the Appalachian Basin are in an area 

characterized by significant amounts of organic carbon, 

suitable thermal maturation, and decollement-induced fracture porosity. As a result, the wells are of relatively high 

yield and produce gas for many years at slowly declining 

rates after a relatively short period of sharp decline. Wells in 

the emerging area of West Virginia are sited in a similar 

geologic environment, except that available organic carbon 

apparently was not sufficient to generate enough gas for 

sustained gas production; in addition, some of the generated 

gas may have migrated out of the area during Alleghanian 

deformation. Wells in the emerging area decline sharply 

within a year and the area is, in general, subeconomic. Wells 

producing along the southern shores of Lake Erie are in an 

area that contains significant amounts of organic carbon and 

intergranular and fracture porosity. The area is thermally 

immature with respect to oil generation and the available 

gas is either biogenic or thermogenic gas that has migrated 

into the porous beds from sources deeper in the Appalachian 

Basin. Like wells in the Big Sandy Gas Field, these wells 

produce for a very long term but are low in yield. 

There are two areas in eastern Ohio and northwestern 

Pennsylvania that currently do not produce shale gas but lie 

between the 0.8 kg/cm2 organic matter isoline on the east 

and the 0.6-percent R0 vitrinite reflectance isoline on the 

west, as mapped by Schmoker.(l993). These areas are potentially favorable for exploration and production of shale 

gas, providing that the potential reservoirs have sufficient 

fracture and (or) interstitial porosity (fig. II). 

Exploration targets for shale gas in areas outside of the 

Appalachian Basin will very likely require conditions similar to those in the Big Sandy Gas Field if they are to produce 

gas commercially. It should be noted that factors such as 

location with respect to market, the total potential volume of 

the resource, as well as local drilling depths and evolving 

techniques for stimulating wells will bear upon the economic feasibility of shale-gas production at any given. 

ACKNOWLEDGMENTS 

This manuscript was reviewed and improved by recommendations from Vito F. Nuccio, Robert T. Ryder, Paul 

G. Lillis, Katryn Wiese, and David G. Howell, U.S. Geological Survey. 

REFERENCES CITED 

Baranoski, M.T., and Riley, R.A., 1988, Analysis of stratigraphic 

and production relationships of Devonian-shale gas reservoirs in Lawrence County, Ohio: Ohio Division of Geologic 

Survey Open-File Report 88-2, 30 p. 

Bartholomew, M.J., Milici, R.C., and Schultz, A.P., 1980, Geologic structure and hydrocarbon potential along the Saltville 

and Pulaski thrusts in southwestern Virginia and northeastem Tennessee: Virginia Division of Mineral Resources Publication 23, part A, sheet 1. 

Broadhead, R.F., 1993·, Petrography and reservoir geology of 

Upper Devonian shales, northern Ohio, in Roen, J.B., and 

Kepferle, R.C., eds., Petroleum geology of the Devonian and 

Mississippian black shale of eastern North America: U.S. 

Geological Survey Bulletin 1909, p. Hl-H15. 

Broadhead, R.F., Kepferle, R.C., and Potter, P.E., 1982, Stratigraphic and sedimentologic controls of gas in shale-Example from Upper Devonian of northern Ohio: American 

Association of Petroleum Geologists Bulletin, v. 66, p. 10-

27. 

Brown, P.J ., 1976, Energy from shale-A little used natural resource, [Chap.] 6, in Natural gas from unconventional 

geologic sources: Energy Research and Development Administration Report FE-2271-1, p. 86-99. 

Charpentier, R.R., deWitt, Wallace, Jr., Claypool, G.E., Harris, 

L.D., Mast, R.F., Megeath, J.D., Roen, J.B., and Schmoker, 

J.W., 1993, Estimates of unconventional natural gas resources in the Devonian shales of the Appalachian Basin, in 

Roen, J.B., and Kepferle, R.C., eds., Petroleum geology of 

the Devonian and Mississippian black shale of eastern North 

America: U.S. Geological Survey Bulletin 1909, p. Nl-N20. 

Claypool, G.E., Threkeld, C.N., and Bostick, N.H., 1978, Natural 

gas occurrence related to regional thermal rank of organic 

matter (maturity) in Devonian rocks of the Appalachian 

Basin, in Preprints for Second Eastern Shales Symposium: 

U.S. Department of Energy, Morgantown Energy Technology Center Report METC/SP-78-6, p. 54-65. 

Cluff, R.M., 1993, Source rocks and hydrocarbon generation in 

the New Albany Shale (Devonian-Mississippian of the Illinois Basin)-A review, in Roen, J.B., and Kepferle, R.C., 

eds., Petroleum geology of the Devonian and Mississippian 

black shale of eastern North America: U.S. Geological Survey Bulletin 1909, p. 11-115 

Cole, G.A., Drozd, R.J., Sedivy, R.A., and Halpern, H.I., 1987, 

Organic geochemistry and oil-source correlations, Paleozoic 

of Ohio: American Association of Petroleum Geologists Bulletin, v. 71, p. 788-809. 

Decker, D., Coates, J-M.P., and Wicks, D., 1992, Stratigraphy, 

gas occurrence, formation evaluation and fracture characterization of the Antrim Shale, Michigan Basin: Gas Research 

Institute Topical Report GRI-92/0258, 101 p. 

deWitt, Wallace, Jr., 1981, Revision of the areal extent of the 

New Albany, Chattanooga, and Ohio shales in KentuckyField trip 3, in Roberts, T.G. ed., Field trip guidebooks for 

the annual meeting of the Geological Society of America, 

1981, Cincinnati, Ohio, v. 2-Economic geology, structure: 

Falls Church, American Geological Institute, p. 331-334. 

deWitt, Wallace, Jr., and Milici, R.C., 1989, Energy resources of 

the Appalachian orogen, in Hatcher, R.D., Jr., Thomas, 

W.A., and Viele, G.W., eds., The Geology of North America, 

v. F-2-The Appalachian-Ouachita orogen in the United 

States: Boulder, Geological Society of America, p. 495-510. 
276 THE FUTURE OF ENERGY GASES 

deWitt, Wallace, Jr., Perry, W.J., Jr., and Wallace, L.G., 1975, 

Oil and gas data from Devonian and Silurian rocks in the 

Appalachian Basin: U.S. Geological Survey Miscellaneous 

Investigations Series Map 1-917 B, scale 1:2,500,000. 

deWitt, Wallace, Jr., Roen, J.B., and Wallace, L.G., 1993, Stratigraphy of Devonian black shales and associated rocks in 

the Appalachian Basin, in Roen, J.B., and Kepferle, R.C., 

eds., Petroleum geology of the Devonian and Mississippian 

black shale of eastern North America: U.S. Geological Survey Bulletin 1909, p. Bl-B57. 

Demaison, G.J., and Moore, G.T., 1980, Anoxic environments 

and oil source bed genesis: American Association of Petroleum Geologists Bulletin, v. 64, p. 1179-1209. 

Donaldson, A.C., Heald, M.T., Renton, J.J., and Warshaver, 

S.M., 1975, Depositional environment of Rome Trough 

rocks, Mingo County well, West Virginia [abs.]: American 

Association of Petroleum Geologists Bulletin, v. 59, 

p. 1,735. 

Ettensohn, F.R., 1985, Controls on development of Catskill delta 

complex basin-Facies, in Woodrow, D.L., and Sevon, 

W.O., eds., The Catskill delta: Geological Society of America Special Paper 201, p. 65-77 

Ettensohn, F.R., and Barron, L.S., 1981, Depositional model for 

the Devonian-Mississippian black shales of North America-A paleoclimatic-paleogeographic approach, in Roberts, 

T.G., ed., Field trip guidebooks for the annual meeting of 

the Geological Society of America, 1981, Cincinnati, Ohio, 

v. 2-Economic geology, structure: Falls Church, American 

Geological Institute, p. 344-361. 

Ettensohn, F.R., and Barron, L.S., 1982, A tectonic-climatic approach to the deposition of the Devonian-Mississippian 

black-shale sequence of North America: Appalachian Industrial Associates Program-Fall Meeting, October 14-15, 

1982, 91 p. 

Faill, R.T., 1985, The Acadian orogeny and the Catskill delta, in 

Woodrow, D.L., and Sevon, W.O., eds., The Catskill delta: 

Geological Society of America Special Paper 201, p. 15-37 

Gutschick, R.C., and Sandberg, C.A., 1991, Late Devonian history of the Michigan Basin, in Catacosinos, P.A., and 

Daniels, P.A., Jr., eds., Early sedimentary evolution of the 

Michigan Basin: Geological Society of America Special 

Paper 256, p. 181-202 

Gwinn, V.E., 1964, Thin-skinned tectonics in the Plateau and 

northwestern Valley and Ridge Provinces of the central Appalachians: Geological Society of America Bulletin, v. 75, 

n.9,p. 863-900 

Harris, L.D., 1978, The Eastern Interior aulacogen and its relation to Devonian shale gas production: U.S. Department of 

Energy, Morgantown Energy Technology Center Report 

METC/SP-78/6, v. 2, p. 55-72 

Harris, L.D., and Milici, R.C., 1977, Characteristics of thinskinned style of deformation in the southern Appalachians 

and potential hydrocarbon traps: U.S. Geological Survey 

Professional Paper 1018, 40 p. 

Harris, A.G., Harris, L.D., and Epstein, J.B., 1978, Oil and gas 

data from Paleozoic rocks in the Appalachian Basin-Maps 

for assessing hydrocarbon potential and thermal maturity 

(conodont color alteration isograds and overburden isopachs): U.S. Geological Survey Miscellaneous Investigations 

Series Map 1-917-E, scale 1:2,500,000, 4 sheets. 

Hasenmueller, N.R., 1993, New Albany Shale (Devonian and 

Mississippian) of the lllinois Basin, in Roen, J.B., and 

Kepferle, R.C., eds., Petroleum geology of the Devonian and 

Mississippian black shale of eastern North America: U.S. 

Geological Survey Bulletin 1909, p. C1-C19 

Hohn, M.E., and Timberlake, K.J., 1988, Devonian shale fields 

and pools in West Virginia: West Virginia Geological and 

Economic Survey Map-WV34, 8 sheets, scale 1:125,000. 

Hunter, C.D., and Young, D.M., 1953, Relationship of natural 

gas occurrence and production in eastern Kentucky (Big 

Sandy Gas Field) to joints and fractures in Devonian bituminous shales: American Association of Petroleum Geologists 

Bulletin, v. 37, no. 2, p. 282-299. 

Ibach, L.E.J., 1982, Relationship between sedimentation rate and 

total organic carbon content in ancient marine sediments: 

American Association of Petroleum Geologists Bulletin, 

v. 66, p. 170-188. 

Jacobeen, F.J., Jr., 1992, Oil and gas well analyses of hydrocarbon potential of Buchanan, Dickenson, and Wise Counties, 

Virginia: Virginia Division of Mineral Resources Open-File 

Report 91-2, 15 p. 

Janssens, A., and deWitt, Wallace, Jr., 1976, Potential natural gas 

resources in the Devonian shales in Ohio: Ohio Division of 

Geological Survey Geological Note no. 3, 12 p. 

Kammer, T.W., and Bjerstedt, T.W., 1986, Stratigraphic framework of the Price Formation (Upper Mississippian-Lower 

Devonian) in West Virginia: Southeastern Geology, v. 27, 

p. 13-33. 

Kepferle, R.C., 1993, A depositional model and basin analysis 

for the gas-bearing black shale (Devonian and Mississippian) in the Appalachian Basin, in Roen, J.B., and Kepferle, 

R.C., eds., Petroleum geology of the Devonian and Mississippian black shale of eastern North America: U.S. Geological Survey Bulletin 1909, p. F1-F23. 

Kepferle, R.C., and Roen, J.B., 1981, Field trip No. 3-Chattanooga and Ohio Shales of the southern Appalachian Basin, 

in Roberts, T.G., ed., Field trip guidebooks for the annual 

meeting of the Geological Society of America, 1981, Cincinnati, Ohio, v. 2-Economic geology, structure: Falls Church, 

American Geological Institute, p. 259-362. 

Kepferle, R.C., Wilson, E.N., and Ettensohn, F.R., 1978, Preliminary stratigraphic cross section showing radioactive zones in 

the Devonian black shales in the southern part of the Appalachian Basin: U.S. Geological Survey Oil and Gas Investigations Chart OC-85. 

Kreisa, R.D., and Bambach, R.K., 1973, Environments of deposition of the Price Formation (Lower Mississippian) in its type 

area, southwestern Virginia: American Journal of Science, 

Cooper volume, 273-A, p. 326-342. 

Laughrey, C.D., 1989, Distribution and significance of geochemical fossils in the petroleum source rocks of Pennsylvania: 

The Twentieth Annual Appalachian Petroleum Geology 

Symposium, March 27-30, 1989, Morgantown, West Virginia: I.C. White Memorial Fund Publication, no. 1, p. 37-44. 

Lockridge, J.P., and Pollastro, R.M., 1988, Shallow Upper Cretaceous Niobrara gas fields in the eastern Denver Basin, in 

Goolsby, S.M., and Longman, S.M., eds., Occurrence and 

petrophysical properties of carbonate reservoirs in the Rocky 

Mountain region: Denver, Rocky Mountain Association of 

Geologists Carbonate Symposium [Proceedings], p. 63-74. 
AUTOGENIC GAS (SELF SOURCED) FROM SHALES-AN EXAMPLE FROM THE APPALACHIAN BASIN 277 

Manger, K.C., and Curtis, J.B., 1991, Geologic influences on location and production of Antrim shale gas, in Devonian gas 

shales technology review: Gas Research Institute v. 7, n. 2, 

p. 5-16. 

Matthews, D.R., 1993, Review and revision of Devonian-Mississippian stratigraphy in the Michigan Basin, in Roen, J.B., 

and Kepferle, R.C., eds., Petroleum geology of the Devonian 

and Mississippian black shale of eastern North America: 

U.S. Geological Survey Bulletin 1909, p. DI-D85 

Maynard, J.B., 1981, Some geochemical properties of the Devonian-Mississippian shale sequence, in Kepferle, R.C., and 

Roen, J.B., 1981, Field trip no. 3, Chattanooga and Ohio 

Shales of the southern Appalachians, in Roberts, T.G., ed., 

Field trip guidebooks for the annual meeting of the Geological Society of America, 1981, Cincinnati, Ohio, v. 2-

Economic geology, structure: Falls Church, American Geological Institute, p. 336-343. 

Milici, R.C., 1980a, Relationship of regional structure to oil and 

gas producing areas in the Appalachian Basin: U.S. Geological Survey Miscellaneous Investigations Series Map 1-917-F, 

scale 1:2,500,000 

---1980b, Saltville fault footwall structure at Stone Mountain, Hawkins County, Tennessee, in Geologic structure and 

hydrocarbon potential along the Saltville and Pulaski thrusts 

in southwestern Virginia and northeastern Tennessee: Virginia Division of Mineral Resources Publication 23, part C, 

sheets 5 and 6. 

---1985, Oil and gas possibilities in eastern Tennessee and 

southwestern Virginia, in Important regulatory considerations: Tennessee Division of Geology Information Circular 

18,p. 27-40 

Milici, R.C., and deWitt, Wallace, Jr., 1988, The Appalachian 

Basin, in Sloss, L.L., ed., Sedimentary cover-North American craton, United States: Boulder, Geological Society of 

America, The Geology of North America, v. D2, p. 427-

469. 

Milici, R.C., and Gathright, T.M., 1985, Geologic features related 

to coal mine roof falls-A guide for miner training: Virginia 

Division of Mineral Resources Publication 55, 13 p. 

Milici, R.C., Gathright, T.M., Miller, B.W., Gwin, M.R., and 

Stanley, C.B., 1986, Subtle bedding plane faults-a major 

factor contributing to coal mine roof falls in southwestern 

Virginia, in McDowell, R.C., and Glover, Lynn, III, eds., 

The Lowry volume-Studies in Appalachian geology: 

Virginia Tech Department of Environmental Sciences 

Memoir 3, p. 83-95. 

Milici, R.C., and Roen, J.B., 1981, Stratigraphy of the Chattanooga Shale in the Newman Ridge and Clinch Mountain 

areas, Tennessee: Tennessee Division of Geology Report of 

Investigations 40, 102 p. 

Milici, R.C., and Statler, A.T., 1980, Fractures related to major 

thrusts-Possible analogues to tectonically fractured Chattanooga Shale in Tennessee: U.S. Department of Energy 

DOE/METC/SP-80/23, p. 157-166. 

Miller, R.L., and Fuller, J.O., 1954, Geology and oil resources of 

the Rose Hill district-the fenster area of the Cumberland 

overthrust block-Lee County, Virginia: Virginia Geological 

Survey Bulletin 71, 383 p. 

Nelson, W.A., 1925, The southern Tennessee coal field: Tennessee Division of Geology Bulletin 33A, 239 p. 

Nolde, J.E., and Milici, R.C., in press, Stratigraphic and structural controls of natural gas production from the Berea 

Sandstone (Mississippian), southwestern Virginia [abs.]: 

American Association of Petroleum Geologists Abstracts 

with Program, 1993 Eastern Section meeting, Williamsburg, 

Virginia. 

Orton, E., 1899, Petroleum and natural gas in New York: New 

York State Museum Bulletin, v. 6, no. 30, p. 496-497. 

Patchen, D.O., and Hohn, M.E., 1993, Production and production 

controls in Devonian shales, West Virginia, in Roen, J.B., 

and Kepferle, R.C., eds., Petroleum geology of the Devonian 

and Mississippian black shale of eastern North America: 

U.S. Geological Survey Bulletin 1909, p. Ll-L28. 

Pederson, T.F., and Calvert, S.E., 1990, Anoxia versus productivity-What controls the formation of organic-carbon-rich 

sediments and sedimentary rocks?: American Association of 

Petroleum Geologists Bulletin, v. 74, p. 454-466. 

Pederson, T.F., and Calvert, S.E., 1991, Anoxia versus productivity: What controls the formation of organic-carbon-rich sediments and sedimentary rocks? Reply: American Association 

of Petroleum Geologists Bulletin, v. 75, p. 500-501. 

Pepper, J.F., deWitt, Wallace, Jr., and Demarest, D.F., 1954, Geology of the Bedford Shale and Berea Sandstone in the Appalachian Basin: U.S. Geological Survey Professional Paper 

259, 111 p. 

Perroud, H., Van der Voo, R., and Bonhommet, N., 1984, Paleozoic evolution of the America plate on the basis of paleomagnetic data: Geology, v. 12, p. 579-582. 

Pollastro, R.M., and Scholle, P.A., 1986, Exploration and development of hydrocarbons from low-permeability chalks-An 

example from the Upper Cretaceous Niobrara Formation, 

Rocky Mountain region, in Spencer, C.W., and Mast, R.F., 

eds., Geology of tight gas reservoirs: American Association 

of Petroleum Geologists Studies in Geology, no. 24, p. 129-

142. 

Potter, P.E., Maynard, J.B., and Pryor, W.A., 1980, Final report 

of special geological, geochemical, and petrological studies 

of the Devonian shales in the Appalachian Basin: Cincinnati 

H. N. Fisk Laboratory of Sedimentology, Department of Geology, University of Cincinnati; prepared for U.S. Department of Energy Eastern Gas Shales project, contract DEAC21-76-M05201. 

Potter, P.E., DeReamer, J.H., Jackson, D.S., and Maynard, J.B., 

1983, Lithologic and environmental atlas of Berea Sandstone 

(Mississippian) in the Appalachian Basin: Charleston, 

W. Va., Appalachian Geological Society Special Publication 

1, 157 p. 

Price, L.C., and LeFever, J .A., 1992, Does Baaken horizontal 

drilling imply a huge oil-resource base in fractured shales?, 

in Schmoker, J.W., Coalson, E.B., and Brown, C.A., eds., 

Geological studies relevant to horizontal drilling-Examples 

from western North America: Rocky Mountain Association 

of Geologists, p. 199-214. 

Provo, L.J., Kepferle, R.C., and Potter, P.E., 1978, Division of 

black shale in eastern Kentucky: American Association of 

Petroleum Geologists Bulletin, v. 62, no. 9, p. 1703-1713. 

Roen, J.B., and Kepferle, R.C., eds., 1993, Petroleum geology of 

the Devonian and Mississippian black shales of eastern 

North America: U.S. Geological Survey Bulletin 1909, 

p.A1-N20. 
278 THE FUTURE OF ENERGY GASES 

Russell, D.J., 1993, Stratigraphy of the Kettle Point Formation 

(Upper Devonian of southwestern Ontario, Canada)-Implications for depositional setting and resource potential, in 

Roen, J.B., and Kepferle, R.C., eds., Petroleum geology of 

the Devonian and Mississippian black shale of eastern North 

America: U.S. Geological Survey Bulletin 1909, p. E1-E1l. 

Schmoker, J.W., 1980, Organic content of Devonian shale in the 

western Appalachian Basin: American Association of Petroleum Geologists Bulletin, v. 64, p. 2156-2165. 

--_-1981, Determination of organic-matter content of Appalachian Devonian shales from gamma-ray logs: American Association of Petroleum Geologists Bulletin, v. 62, p. 1285-

1298. 

---1989, Thermal maturity of the Anadarko Basin, in 

Johnson, K.S., ed., Anadarko Basin Symposium, 1988: 

Oklahoma Geological Survey Circular 90, p. 25-31. 

---1993, Use of formation density logs to determine organiccarbon content in Devonian shales of the western Appalachian Basin, and an additional example based on the Baaken 

Formation of the Willeston Basin, in Roen, J.B., and Kepferle, R.C., eds., Petroleum geology of the Devonian and Mississippian black shale of eastern North America: U.S. 

Geological Survey Bulletin 1909, p. 11-114_ 

Shumaker, R.C., 1980, Porous fracture facies in Devonian shales 

of eastern Kentucky and West Virginia: U.S. Department of 

Energy DOE/METC/SP-80/23, p. 124-132. 

---1986, The effect of basement structure on sedimentation 

and detached structural trends within the Appalachian Basin, 

in McDowell, R.C., and Glover, Lynn III, eds., The Lowry 

volume-Studies in Appalachian geology: Virginia Tech Department of Geological Sciences Memoir 3, p. 67-81. 

---1993, Structural param that affect Devonian shale gas 

production in West Virginia and eastern Kentucky, in Roen, 

J.B., and Kepferle, R.C., eds., Petroleum geology of the Devonian and Mississippian black shales of eastern North 

America: U.S. Geological Survey Bulletin 1909, p. K1-K38. 

Van Tyne, A.A., 1983, Natural gas potential of Devonian black 

shales of New York: Northeastern Geology, v. 5, no. 3/4, 

p. 209-216. 

Wallace, L.G., and deWitt, Wallace, Jr., 1975, Thickness and extent of Devonian black shale facies, sheet 2, in deWitt, Wallace, Jr., Perry, W.J., Jr., and Wallace, L.G., Oil and gas data 

from Devonian and Silurian rocks in the Appalachian Basin: 

U.S. Geological Survey Miscellaneous Investigations Map I917B, scale 1 ,250,000. 

Weeks, J.D., 1886, Natural gas, in Mineral resources of the United States, Calendar Year 1885: U.S. Geological Survey, 

p. 155-179. 

White, W.A., 1992, Displacement of salt by the Laurentide ice 

sheet: Quarternary Research, v. 38, p. 305-315. 

Wilson, T.H., Dixon, J.D., Shumaker, R.C., and Wheeler, R.L., 

1980, Fracture patterns observed in cores from the Devonian 

'shale of the Appalachian Basin: U.S. Department of Energy 

DOE/METC/SP-80/23, p. 100-123. 

Young, D_M., 1957, Deep drilling in the Cumberland overthrust 

block in southwestern Virginia: American Association of Petroleum Geologists Bulletin, v. 41, p. 2567-2573. 

Zeilinski, R.E., and Mciver, R.D., 1982, Resource and exploration assessment of the oil and gas potential in the Devonian 

gas shales of the Appalachian Basin: U.S. Department of 

Energy Morgantown Energy Technology Center MLM-MU82-61-0002, DOE/DP/0053-1125, 326 p. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

A Primer on Gas Hydrates 

By Keith A. Kvenvolden1 

CONTENTS 

Abstract ......................................................................... 279 

Introduction ................................................................... 280 

Definition ............................................................... 280 

Controls .................................................................. 281 

Locations . . .... .. .. .. .... .. ... .... .. . ... .. ... .. .. ...... .... .. . . . .. . ... ... 282 

Geophysics . .. .. .... . .. ... .. . ........ ... .... ... ... . .. ... .... ... . .. ..... ... . . . .. 282 

Geothermal Gradients .. . ... ...... ... . ... ... .... .... ... .. .. ... ... . 282 

Quantitative Assessments ...................................... 283 

Nature of Bottom-Simulating Reflections 

(BSR'S) .................................................................. 284 

Wire-Line Logs ...................................................... 284 

Geochemistry . . .. . . .. .... . .. . .. ... .... ... .. .. .. .. ..... . ... .. .. .. ... . . ... . . .. . 285 

Sources of Methane ............................................... 285 

Microbial Versus Thermogenic Methane .............. 285 

Inorganic Geochemistry ......................................... 287 

Estimates of Amount of Methane ................................ 287 

Recovery of Methane ...... ... .... ......... ........ ...... .... ... .. ... ... 288 

Conclusions ................................................................... 289 

Acknowledgments ........................................................ 289 

References Cited .. . . .. . .. ... ...... . .. . .. .. .. ... .. ... .. . ... .. . . .. . .. ... .. ... 289 

ABSTRACT 

Natural-gas hydrates are ice-like mixtures of gas and 

water in which the gas molecules, mainly methane, are 

trapped within a framework of cages, that is within a clathrate, of water molecules. Gas hydrates are stable under pressure and temperature conditions that occur worldwide in two 

1

U.S. Geological Survey, MS 999, 345 Middlefield Rd., Menlo 

Park, CA 94025. 

distinct locations: (1) in polar regions, where temperatures 

are cold enough for onshore and offshore permafrost to be 

present, and (2) in offshore sediment of outer continental 

and insular margins, where there are cold bottom-water temperatures and deep waters, exceeding 300 to 500 m. 

Samples of gas hydrates have been recovered in 14 

areas of the world, and geophysical and geochemical evidence for them has been found in about 30 other areas. 

Many oceanic occurrences of gas hydrates are inferred, 

mainly on the basis of the appearance on marine seismicreflection profiles of a pronounced bottom-simulating 

reflection, commonly called a BSR. This reflection is inferred to coincide with the base of the gas-hydrate 

stability field. BSR's indicating gas hydrates are useful in 

estimating geothermal gradients and heat flow in oceanic 

sediments and, in conjunction with other seismic information, in assessing the amount of methane within and 

below the gas-hydrate interval. Wire-line well logs also 

provide a basis for estimating the quantity of methane. 

Most methane in gas hydrates is microbial in origin, 

determined on the basis of molecular and isotopic compositions; however, thermogenic methane hydrates are 

known from the Gulf of Mexico and the Caspian Sea. 

During gas-hydrate formation, salt ions are excluded 

from the crystal structure; therefore pore-water freshening is observed with gas-hydrate occurrence. The total 

amount of methane in gas hydrates around the world 

likely exceeds 1019 g of methane carbon (-20xl015 m3 

of methane gas=-7xl05 trillion cubic feet (Tcf)). Because 

gas hydrates represent a large amount of methane within 

2,000 m of the Earth's surface, they are considered to be 

an unconventional, potential source of fossil fuel. Because of unsolved technological problems in producing 

methane from gas hydrates, however, wide-scale recovery 

of methane from these substances probably will not take 

place until sometime in the 21st century. 

279 
280 THE FUTURE OF ENERGY GASES 

INTRODUCTION following discussion has been taken and modified from 

that report. 

Chemists have known about gas hydrates since the 

early part of the 19th century (reviewed by Sloan, 1990). 

The petroleum industry became aware of these substances 

in the 1930's when gas-hydrate formation inside pipelines 

was discovered to cause blockage during transmission of 

natural gas (Hammerschmidt, 1934). In the ~ 960's naturally occurring gas hydrates were found in the Siberian Messoyakha gas field (reviewed by Makogon, 1981; Collett, 

this volume), and in the 1970's it was recognized that gas 

hydrates occur naturally not only in polar continental regions but also in the uppermost portion of deep-water sediment in oceanic regions at outer continental margins 

(Claypool and Kaplan, 1974). Kvenvolden and McMenamin ( 1980) reviewed the geological occurrences of natural gas hydrates. Since then it has become increasingly 

evident that naturally occurring gas hydrates are significant components of the shallow geosphere and a potential 

energy resource. The energy density (volume of methane 

at standard temperature and pressure (STP) per volume of 

rock) of methane hydrates is ten times greater than the energy density of other unconventional sources of gas, such 

as coalbeds, tight sands, black shales, and deep aquifers, 

and two to five times greater than the energy density of 

conventional natural gas within about 2,000 m of the surface (MacDonald, l990a). K venvolden (in press) has recently reviewed societal aspects of gas hydrates, and the 

DEFINITION 

Gas hydrates, also called gas clathrates, are naturally 

occurring solids composed of water molecules forming a 

rigid lattice of cages with most of the cages each containing a molecule of natural gas, mainly methane. Gas hydrates are essentially water clathrates of natural gas in 

which water crystallizes in the isometric crystallographic 

system rather than the hexagonal system of normal ice. 

Two structures, I and II, of the isometric (cubic) lattice are 

recognized in nature. Structure I (fig. 1) is most common; 

in this structure the cages are arranged in body-centered 

packing and are large enough to include methane, ethane, 

and other gas molecules of similar molecular diameters 

such as carbon dioxide and hydrogen sulfide. In structure 

II, the cages are arranged in diamond packing, resulting in 

some cages being large enough to include not only methane and ethane but also gas molecules as large as propane 

and isobutane (Sloan, 1990). 

The maximum amount of methane that can occur in a 

methane hydrate is fixed by the clathrate or lattice-structure 

geometry. In a fully saturated structure I methane hydrate, 

one molecule of methane is present for approximately 

every six molecules of water. In theory, when appropriate 

Figure 1. Gas hydrate structure. In this structure I methane hydrate, the rigid cages are composed of hydrogen-bonded water molecules. Each cage, both exposed and covered in this figure, 

can contain a methane molecule. Average cage diameter is about 8 A. Modified from Hitchon 

(1974). 
A PRIMER ON GAS HYDRATES 281 

hydrate expansion factors are considered, I m3 of methane 

hydrate can contain up to 164 m3 of methane gas at STP 

(fig. 2). Thus gas hydrates in shallow reservoirs less than 

about 1.5 km beneath the surface can have more methane 

per unit volume than can be contained as free gas in the 

same space (Hunt, 1979). This fact, along with the widespread occurrence of gas hydrates in the shallow geosphere, 

explains some of the serious interest in gas hydrates as a 

potential future energy resource. 

+iiJ 

Gas Hydrate Gas Water 

Figure 2. One m3 of gas hydrate yields 164 m3 of gas and 0.8 

m3 of water at standard temperature and pressure (STP). 

CONTROLS 

The occurrence of gas hydrates in nature is controlled 

by conditions of temperature, pressure, and composition, 

as illustrated by means of a phase diagram (fig. 3). In the 

pressure-temperature domain of methane hydrates, the position of the hydrate-gas phase boundary is determined not 

only by the composition of the gas mixture, that is, the 

presence of gases other than methane, but also by the 

ionic impurities in the water. Because the exact composition of gas and water in sediment pore spaces is usually 

not known, a system of pure methane and pure water is 

commonly assumed to estimate the depth and temperature 

regime where naturally occurring gas hydrates are stable 

(Claypool and Kaplan, 1974). 

Phase-boundary information (fig. 3) coupled with thermal information (fig. 4) suggests that the upper depth limit 

for methane hydrates is about 150 m in continental polar 

regions, where surface temperatures are below 0°C. In oceanic sediment, gas hydrates occur where the bottom-water 

temperatures approach 0°C and water depths exceed about 

300 m. The lower limit of methane hydrate occurrence in 

sediment is determined by the geothermal gradient; the 

maximum lower limit is about 2,000 m below the solid 

surface, although the lower limit is typically much less depending on local conditions (fig. 4). Thus the occurrence of 

gas hydrates is restricted to the shallow geosphere. 

One feature of gas hydrate occurrence that is not apparent from the phase diagram (figs. 3 and 4) is the 

amount of gas (methane) that is necessary for gas-hydrate 

formation. Gas hydrates will form with about 90 percent 

of the cages of the clathrate filled, that is with about 150 

volumes of methane at STP per volume of water (Sloan, 

1990). But methane solubility in seawater is very low, 

about 0.045 volumes of methane at STP per volume of 

water (Yamamoto and others, 1976). Thus the amount of 

methane required for gas hydrates greatly exceeds the solubility of methane in water. This requirement for large 

amounts of methane for gas-hydrate formation limits the 

regions on earth where gas hydrates can be expected to 

those regions having significant sources of methane. 

10.--.------w-----,------,------,------, 

so 

100 METHANE 

(/) 

a: 

' GAS+ICE 

' 

~ METHANE UJ HYDRATE+ ~ ICE+GAS 

I 

tfu soo 0 

1000 

sooo 

METHANE 

GAS+WATER 

~ ~ 

% 

~ 

~ 

~ " d. 

~ 

~ '1-

TEMPERATURE (° C) 

s 

~10 

:::!: 

t-

~ 

UJ 

a: 

::J 

(/) 

(/) 

so UJ 

a: 

a. 

100 

soo 

1000 

40 

Figure 3. Phase diagram showing boundary between free methane 

gas (no pattern) and methane hydrate (pattern) for a pure-water 

and pure-methane system. Adding NaCl to water shifts boundary 

to the left. Adding C02, H2S, C2H6, C3H8 to methane shifts 

boundary to right and thus increases area of hydrate stability field. 

Depth scale assumes a pore-water hydrostatic pressure gradient of 

0.1 atm m- 1

• Modified from Katz and others (1959). 
282 THE fUTURE OF ENERGY GASES 

LOCATIONS 

Gas hydrates occur worldwide, but because of the 

pressure-temperature and gas-volume requirements, they 

are restricted to two regions, polar and deep oceanic. In 

polar regions, gas hydrates are usually associated with 

permafrost both onshore in continental sediment and offshore in sediment of the continental shelves. In deep oceanic regions, gas hydrates are found in outer continental 

margins in sediment of slopes and rises where cold bottom water is present. The worldwide occurrence of known 

and inferred gas hydrates is shown on figure 5. Samples 

of gas hydrates have been recovered on land in the West 

Prudhoe Bay oil field in Alaska (reviewed by Kvenvolden 

and McMenamin, 1980; Collett, this volume) and at 14 

oceanic locations, providing irrefutable evidence of natural gas-hydrate occurrence (Kvenvolden and others, 1993). 

Deep-ocean drilling has recovered gas hydrates at nine locations (offshore from Peru, Costa Rica, Guatemala, Mexico, southeastern United States, western United States; 

two locations offshore from Japan; and in the Gulf of 

Mexico). Shallow sediment coring (using piston and gravity cores) has also recovered gas hydrates at six locations 

(Black Sea, Caspian Sea, offshore from northern California, northern Gulf of Mexico, and two locations in the 

Okhotsk Sea). 

0 

200 

400 

<JJ 

a: 600 w 

tw 

::;:; 

z 800 

I 

t0.. 

~ 1000 

1200 

1400 

\ 

\ 

\ . Geothermal--..\ 

gradient \ 

in permafrost \ 

\ 

\ 

SEDIMENT 

Depth of permafrost\ l 

Base of 

gas hydrate 

\ . 

1\ 

1\ 

I ' 

I \ 

I ' 

1600 L---~----~----~----~----~----~ 

A 

-20 -10 0 10 30 

TEMPERATURE oc 

20 

GEOPHYSICS 

Most other oceanic occurrences of gas hydrates are 

inferred, mainly on the basis of the appearance on marine 

seismic-reflection profiles of a pronounced bottom-simulating reflection (BSR) (fig. 6). This reflection coincides with 

the depth predicted from the phase diagram as the base of 

the gas-hydrate stability zone (fig. 4). BSR's mark the interface between higher sonic velocity, hydrate-cemented 

sediment above and lower sonic velocity, uncemented sediment below. The seismic reflection from the base of a gashydrate zone is generally characterized by reflection polarity reversals (reflections opposite to those from the seafloor) 

and large vertical reflection coefficients, for example 

-0.12:t0.04 for BSR's of the Blake Outer Ridge offshore 

from the southeastern United States (Shipley and others, 

1979; Lee and others, this volume). Such negative reflection coefficients indicate a reflective interface between 

higher velocity strata overlying lower velocity strata. 

GEOTHERMAL GRADIENTS 

Bottom-water temperatures and the depths to gashydrate BSR's have been used in conjunction with gashydrate phase-boundary information (fig. 4) to estimate 

0 

200 

400 

<JJ 

a: 600 w 

tw 

::;:; 

~ 800 

I 

tQ. 

~ 1000 

1200 

1400 

B 

Zone of 

I 

I 

1- Hydrothermal 

1 gradient 

I 

WATER 

_.....Phase 

boundary 

gas hydrate { 

-20 -10 0 10 20 

TEMPERATURE oc 

Figure 4. Examples of thermal gradients imposed on the gas-hydrate phase diagram (fig. 3), showing differ~nt depth-temperatu~~ zon~s 

for gas-hydrate occurrence. A, Conditions that are favorable for gas-hydrate formation where permafrost IS present; B, ConditiOns m 

which gas hydrates are stable in outer continental margin sediments. From K venvolden and Grantz (1990). 
A PRIMER ON GAS HYDRATES 283 

ARCTIC OCEAN 

-~-- ·yo 

• • 

• • 

PACIFIC 

•· 

OCEAN OCEAN 

• -~ 

Figure 5. Worldwide locations of known and inferred gas hydrates in oceanic sediments (dots) and in regions of continental permafrost 

(diamonds). Dashed lines in Antarctica indicate continental edge of ice shelves. Modified from Kvenvolden (1988). 

geothermal gradients and heat flow in oceanic sediment 

(Shipley and others, 1979; Yamano and others, 1982). This 

method has been applied to seismic data from the Blake 

Outer Ridge, around Central America, and in the Nankai 

Trough offshore from Japan. The estimated geothermal 

gradients and heat-flow values are consistent with results 

obtained by conventional means using downhole temperature and surface heat-flow measurements. An example of 

the use of the method comes from offshore Peru where 

geothermal gradients of 43 and 49.5°C/km were estimated 

in two areas from BSR's (Kvenvolden and Kastner, 1990); 

these results are similar to those obtained by direct measurements (Yamano and Uyeda, 1990). 

QUANTITATIVE ASSESSMENTS 

Multichannel seismic reflection data have been used 

to analyze several aspects of the zone of gas-hydrate stability. For example, quantitative analyses of BSR's have 

been undertaken with reprocessed seismic records· and 

synthetic seismograms to estimate the amount of gas hydrate at the BSR and the thickness of the underlying freegas zone for a site offshore from Peru (Miller and others, 

1991). The results indicate that the BSR is laterally discontinuous. A free-gas zone 5.5 to 17 m thick beneath a 

zone where gas hydrate fills 1 0 percent of the porosity is 

estimated from BSR's of high amplitude. Where the BSR 

amplitude is low, the free-gas zone is much thinner than 

5.5 m or is absent. In a seismic study of gas hydrates, 

Hyndman and Spence (1992) examined BSR's from offshore Vancouver Island in Canada using amplitude versus 

offset (AVO) and high-resolution velocity analyses as well 

as modeling of vertical incidence data. The results suggest 

that above the BSR is a 10- to 30-m-thick high-velocity 

layer with about 30 percent of its pore space filled with 

gas hydrate. Beneath the BSR there is no seismically detectable free gas. In this case the BSR records an interface 

between sediment with gas hydrate and sediment without 

gas hydrate. 
284 THE FUTURE OF ENERGY GASES 

Figure 6. A 12-fold multichannel reflection profile from the crest and eastern flank of Blake Outer Ridge, offshore from southeastern 

United States. Strong bottom-simulating reflection (BSR) is inferred to represent base of gas-hydrate stability zone. Blanking of crosscutting strata above the BSR is likely due to masking by presence of gas hydrates. The well-defined, continuous BSR suggests that the 

gas hydrate here forms a seal that may be trapping free gas beneath the BSR. Modified from Shipley and others ( 1979). 

NATURE OF BOTTOM-SIMULATING 

REFLECTIONS (BSR 'S) 

The presence or absence of free gas beneath BSR's is a 

controversial and as yet unresolved issue. Two models have 

been proposed to account for gas-hydrate formation and the 

development of BSR's. In the first, methane is assumed to 

be generated microbially from organic matter within the 

zone of gas-hydrate stability (Claypool and Kaplan, 1974). 

Gas-hydrate formation takes place concurrent with sedimentation. As the zone of methane hydrate thickens and 

deepens, its base eventually subsides into a temperature 

region where the gas hydrate is unstable. In this region free 

gas can occur, but this gas can migrate back into the overlying zone of gas hydrate stability if suitable migration pathways are available (Kvenvolden and Barnard, 1983a). A 

consequence of this model is that gas hydrates should occur 

throughout the zone of gas-hydrate stability and free gas 

may or may not be present beneath the BSR. 

In the second model, gas hydrates are formed by the 

removal of methane from rising pore fluids as they pass 

from below into the gas-hydrate stability zone (Hyndman 

and Davis, 1992). This model postulates that most of the 

methane is generated microbially at depths below the stability zone but not at depths sufficient for the formation of 

thermogenic methane. A consequence of this model is that 

gas hydrates should be concentrated at the base of the stability zone near the BSR, and free gas is not to be expected 

beneath the BSR. 

Tests of these models were possible on Ocean Drilling Program (ODP) Legs 141 (offshore from Chile) and 

146 (offshore from Vancouver Island) where seismic reflectors indicated by BSR's were purposely cored. Previously the coring of these kinds of reflectors during deepocean drilling had been avoided because of presumed 

safety hazards (Ocean Drilling Program, 1986). Unfortunately, results from Leg 141 are equivocal (Behrmann and 

others, 1992), and appropriate information from Leg 146 

is not yet available. 

WIRE-LINE LOGS 

In addition to seismic data, geophysical information 

from wire-line well logs can be valuable in the detection 

and evaluation of gas-hydrate intervals (K venvolden and 

Grantz, 1990). Well logs for gas-hydrate studies include 

caliper, gamma ray, spontaneous potential, resistivity, sonic 

velocity, and neutron porosity (Goodman, 1980). Illustrated 

in figure 7 are the wire-line log responses, and a mud-gas 

log, in one gas-hydrate-bearing interval drilled at the N.W. 

Eileen State No. 2 well on the North Slope of Alaska. The 

resistivity and sonic velocity responses have proved most 

useful in a comprehensive study of well-log data from 445 

wells on the North Slope where six gas-hydrate-bearing 

intervals have been identified and mapped in 50 of these 

wells (Collett and others, 1988). A comparison between 

logs from the N.W. Eileen State No. 2 well and logs from 

Deep Sea Drilling Project (DSDP) Hole 570 located offshore from Guatemala showed similar characteristics and 

clearly defined the gas-hydrate zones (Mathews, 1986). 

Well logs provide a basis for estimating gas quantity, and, 

in conjunction with seismic data, hold the key to future 

worldwide gas-hydrate resource assessment. 
A PRIMER ON GAS HYDRATES 285 

CALIPER 

r-1 "' 12 1 tj 

0 lt.O 

'----------" 

GAMMA 

API 

sr 

mV 

,---, 

10 

LAT-8 

otHn-m 

0 10 1001000 

150 !:JO L____j___.J 

SONIC 

mseclft 

NEUTRON 

POROSITY 

percent 

r-r--, 

0 25 50 

10 1001000 

MUD GAS 

ppm 

Figure 7. Comparison of wire-line logs (caliper, gamma-ray 

(GAMMA), spontaneous potential (SP), resistivity (LAT-8), 

sonic velocity (SONIC), and neutron porosity) and total mud-gas 

log for a gas-hydrate-containing interval (664-677 m) in the 

N.W. Eileen State No. 2 well on the North Slope of Alaska. Unit 

abbreviations: API, American Petroleum Institute; ft, feet; in, 

inches; m, meters; msec/ft, milliseconds per foot; mY, millivolts; 

ohm-m, ohm meters; ppm, parts per million. From Kvenvolden 

and Grantz ( 1990). 

GEOCHEMISTRY 

SOURCES OF METHANE 

In both models for gas-hydrate formation discussed 

previously, the methane is considered to be mainly microbial in origin. This conclusion is based on geochemical 

investigations of recovered gas hydrates and of hydrocarbon gases from sediment sections known to contain gas 

hydrates, such as occur offshore from the southeastern 

United States, northern California, and Peru, and in the 

Black Sea and at some sites in the Gulf of Mexico (table 

1 ). These investigations have shown that the molecular 

compositions of the hydrocarbon gases and the isotopic 

compositions of methane are consistent with results expected from microbial gas-generation processes. Methane 

in all of these investigations constitutes more than 99 percent of the hydrocarbon gas mixtures, and the isotopic 

composition of methane (<'\ 13C) is usually lighter than -60 

permil (parts per thousand) relative to the Peedee belemnite (PDB) standard. The molecular and isotopic ranges 

are diagnostic of gas of microbial origin (Bernard and others, 1976). 

In a sedimentary section where methane is being microbially generated, there is a consistent relation between 

the carbon isotopic composition of methane (the product) 

and that of carbon dioxide (the immediate precursor), as 

illustrated in figure 8. In this example from the Blake 

Outer Ridge (Galimov and K venvolden, 1983), carbon isotopic compositions of methane increase (become heavier) 

with depth from about -94 permil in the uppermost sediment to about -66 permil in the deepest sediment, reflecting a systematic but nonlinear depletion of 12C with depth. 

The carbon isotopic compositions of carbon dioxide also 

increase with depth of sediment from about -25 permil to 

about -4 permil showing a depletion of 12c that closely 

parallels the trend of isotopic compositions of methane. 

The magnitude and parallel distribution of carbon isotopic 

values for both methane and carbon dioxide are consistent 

with the concept that the formation of methane resulted 

from the microbial reduction of carbon dioxide derived 

from organic matter (Claypool and Kvenvolden, 1983). 

The results corroborate a microbial origin for methane in 

gas hydrates at this site. Other localities with similar depth 

trends in carbon isotopic compositions of methane and 

(or) carbon dioxide are offshore from Guatemala (Jeffrey 

and others, 1985) and offshore from Peru (Kvenvolden 

and Kastner, 1990) where gas hydrates have also been recovered in DSDP and ODP drilling, respectively. 

MICROBIAL VERSUS THERMOGENIC METHANE 

Methane in gas hydrates from the Gulf of Mexico 

(Pflaum and others, 1986; Brooks and others, 1986) is microbial at some sites and thermogenic at others (table 1). 

"' :;; 

a; 

E 

.<::: 

.<:;; 

0. 

Q) 

"0 

E 

g 

0 

.D 

.6 

::J 

if! 

0,----------------------------------------, 

50 

100 

150 

200 

250 

300 

350 

400+---.---,----,2--,---.---,---.---,---,--~ 

-100 -90 -80 -70 -60 -50 -40 -30 -20 -10 0 

ollc permil 

Figure 8. Distribution with depth of carbon isotopic compositions of methane (lefthand curve) and carbon dioxide (righthand 

curve) from site 533, DSDP Leg 75, Blake Outer Ridge, offshore 

southeastern United States. Modified from Galimov and Kvenvolden (1983). 
286 THE FUTURE OF ENERGY GASES 

Table 1. Carbon isotopic compositions and concentrations of methane in natural-gas hydrates and hydratecontaining sediment. 

[DSDP, Deep Sea Drilling Project; ODP, Ocean Drilling Program; do, ditto] 

Location Type of sample CH4 

(percent) 

o13c 

(permil) Reference 

Offshore southeastern United States, Blake Outer Ridge 

DSDP Leg II Sediment >99 -88 to -70 Claypool and others ( 1973) 

DSDP Leg 76 Sediment >99 -93.8 to -6!i.4 Kvenvolden and Barnard (1983b); 

Galimov and Kvenvolden (1983) 

---- do----------------- Gas hydrate >99 -68.0 Brooks and others (1983) 

Offshore Peru, Peru-Chile Trench 

ODP Leg 112 Sediment >99 -79 to -55 Kvenvolden and Kastner (1990) 

---- do----------------- Gas hydrate >99 -65.0, -59.6 Kvenvolden and Kastner (1990) 

Offshore northern California 

Eel River Basin Gas hydrate >99 -69.1 to -57.6 Brooks and others (1991) 

Gulf of Mexico 

DSDP Leg 96 Sediment >99 -73.7 to -70.1 Pflaum and others (1986) 

---- do----------------- Gas hydrate >99 -71.3 Pflaum and others (1986) 

Garden Banks Gas hydrate >99 -70.4 Brooks and others (1986) 

Green Canyon Gas hydrate >99 -69.2, -66.5 Brooks and others (1986) 

---- do----------------- Gas hydrate 62, 74, 78 -44.6, -56.5, -43.2 Brooks and others (1986) 

Mississippi Canyon Gas hydrate 97 -48.2 Brooks and others (1986) 

Offshore Guatemala, Middle America Trench 

DSDP Leg 84 Sediment >99 -71.4 to -39.5 Kvenvolden and McDonald (1985); 

Jeffrey and others (1985) 

---- do----------------- Gas hydrate >99 -43.6 to -36.1 Kvenvolden and others (1984) 

---- do----------------- Gas hydrate >99 -46.2 to -40.7 Brooks and others (1985) 

Eurasia 

Black Sea Gas hydrate >99 

Caspian Sea Gas hydrate 59 to 96 

Samples of hydrate hydrocarbon gas from Garden Banks 

and Green Canyon contain more than 99 percent methane 

with carbon isotopic compositions lighter than -60 permil. 

In a different sample from Green Canyon and one from 

Mississippi Canyon the hydrate hydrocarbon gas is 62 to 

78 percent methane, and this methane has carbon isotopic 

compositions ranging from -43.2 to -56.5 permil. Gas hydrates associated with mud volcanoes in the Caspian Sea 

contain hydrocarbon gases with 59 to 96 percent methane 

having carbon isotopic compositions of -44.8 to -57.3 permil. These samples fall within the molecular and isotopic 

compositional field diagnostic of thermogenic methane 

(Bernard and others, 1976): 

Molecular and isotopic compositions of gases associated with gas hydrates found on DSDP Leg 84 offshore 

-63.3, -61.8 Ginsburg and others ( 1990) 

-44.8 to -55.7 Ginsburg and others (1992) 

from Guatemala support either a microbial or thermal 

source for the methane (Kvenvolden and others, 1984). 

Hydrocarbon gases from cores of the deepest sediment 

samples and from dissociated gas hydrates all contain 

greater than 99 percent methane (Kvenvolden and McDonald, 1985). This observation suggests that the methane is microbial in origin. Many methane samples had 

carbon isotopic compositions lighter than -60 permil suggesting a microbial source, but at two sites, methane in 

sediments at depths below 210 m increased in carbon 

isotopic value to as heavy as about -40 permil; methane 

from a massive gas hydrate sample had a carbon isotopic 

composition of -44 permil (Jeffrey and others, 1985). A 

detailed study of the dissociation of this massive gas hydrate under controlled laboratory conditions showed car-
A PRIMER ON GAS HYDRATES 287 

bon isotopic compositions of methane ranging from -36.1 

to -43.6 permil (K venvolden and others, 1984). These 

heavy carbon isotopic values are usually considered to 

reflect thermogenic gas. 

The isotopically heavy methane found offshore from 

Guatemala was accompanied by isotopically very heavy 

carbon dioxide, + 16.3 permil for gaseous carbon dioxide 

(Jeffrey and others, 1985) and +37 permil for total dissolved carbon dioxide (Claypool and others, 1985). The 

isotopically heavy methane could have been formed by 

microbial processes from the isotopically heavy carbon dioxide, similar to circumstances described previously for 

the Blake Outer Ridge. Alternatively, the isotopically 

heavy methane could have migrated up from deeper sediments where it was thermally derived from deeply buried 

organic matter. That is, deeply buried organic matter, experiencing temperatures from about 80°C to more than 

150°C, can be altered thermally to produce methane directly (Claypool and Kvenvolden, 1983). The association 

of isotopically heavy methane with isotopically heavy carbon dioxide could be coincidental or could be controlled 

by some unknown isotopic interaction between methane 

and carbon dioxide. The microbial explanation is preferred, but a thermal origin of the methane cannot be ruled 

out (Kvenvolden and others, 1984). 

The ultimate source of hydrate methane is buried organic matter that can be altered microbially or thermally 

to produce methane. The amount and quality of organic 

matter present is critical to the methane generation process. Because gas-hydrate formation requires amounts of 

methane that greatly exceed the water solubility of methane, the amount of organic matter needed for gas-hydrate 

formation is very large. Observations of the present organic-matter content of gas-hydrate-containing sediments offshore from Guatemala suggest that 2.0 to 3.5 percent 

organic carbon is sufficient if only in-situ and not migrated 

methane is involved (Hesse and Harrison, 1981); on the 

Blake Outer Ridge, the present organic-matter content of 

sediment associated with gas-hydrate occurrence averages 

about 1 percent organic carbon (Kvenvolden and Barnard, 

1983b ). At the time of gas-hydrate formation, the organic 

carbon content in the zone of gas-hydrate stability was undoubtedly higher, perhaps double the present amounts. 

INORGANIC GEOCHEMISTRY 

During gas-hydrate formation, water molecules crystallize into a cubic lattice structure, and, as in the formation of 

normal hexagonal ice, the hydrate crystals exclude salt ions 

from the crystal structure. Measurements of chlorinity of 

pore-water samples recovered from gas-hydrate-bearing 

zones offshore from Guatemala ranged from 0.51 to 3.2 

permil (K venvolden and McDonald, 1985) and from 1.8 to 

8.2 permit for samples from offshore Peru (Kvenvolden and 

Kastner, 1990). These samples, all of which were likely 

contaminated to varying degrees with seawater, had chlo-

. rinity values much less than the average seawater chlorinity 

of 19.8 permil. During DSDP Leg 67 drilling offshore from 

Guatemala, Hesse and Harrison ( 1981) first noticed that the 

chlorinities of pore-water samples in the gas-hydrate-bearing zones decreased significantly with depth from about 19 

to 9 permil. Concurrently the oxygen isotopic composition 

(<'~ 180 relative to Standard Mean Ocean Water (SMOW)) of 

pore water increased with depth from near zero close to the 

sediment surface to values as large as +2.6 permil at depth. 

Oxygen isotopic fractionation of pore water apparently 

takes place during gas-hydrate formation, leading to 180 

enrichment with depth of pore fluids recovered after gashydrate dissociation. This same trend of oxygen isotopic 

compositions was observed in pore waters of gas-hydratebearing sediments recovered on ODP Leg 112 offshore 

from Peru (Kvenvolden and Kastner, 1990). 

The trends of decreasing chlorinity with depth in gashydrate-bearing sediments as noticed on DSDP Leg 67 

have been observed in the Blake Outer Ridge (DSDP Leg 

76)(Kvenvolden and Barnard, 1983b; Jenden and Gieskes, 

1983), offshore from Guatemala (DSDP Leg 84)(Kvenvolden and McDonald, 1985; Hesse and others, 1985 ), and 

offshore from Peru (ODP Leg 112)(Kvenvolden and Kastner, 1990). These chlorinity trends are derived to a large 

extent from the dissociation of gas hydrates during core 

recovery. The chloride concentrations are measured on 

mixtures composed of in-situ pore water and dissociated 

gas-hydrate water. Thus a progressive dilution artifact is 

produced in the pore water that can be squeezed from the 

sediment with increasing depths. Pore-water freshening is a 

useful signal of the presence of gas hydrates although it is 

not a unique signal. Freshwater migration in sediments near 

continents and clay mineral dewatering are also processes 

that can cause pore waters to have decreased chlorinities. 

However, where pore-water freshening is observed in sediments having large amounts of methane within the depth 

range of the gas-hydrate stability zone, gas hydrates are 

likely to be present. 

ESTIMATES OF AMOUNT OF METHANE 

Estimates of the amount of methane in gas hydrates 

are speculative and uncertain (Kvenvolden, 1988). Although it is generally known that gas hydrates occur 

worldwide (fig. 5), knowledge of their occurrence is incomplete, contributing to a wide range of estimates of the 

amount of methane in gas hydrates. The Potential Gas 

Committee (1981) has summarized such estimates. They 

reported ranges of methane values (reported as methane 

carbon) from a low of 7.5x10 15 gin Arctic permafrost regions to a high of 4.1 x 1021 g in oceanic sediment. Current 

estimates of the amount of methane carbon in gas hydrates 
288 THE FUTURE OF ENERGY GASES 

are in rough accord at 10x1018 g (Kvenvolden, 1988) and 

11.4x10 18 g (MacDonald, 1990b). The volume of methane 

at STP represented by 10 19 g of methane carbon is equal 

to about 20xJ015 m3 or 6.6xJ05 Tcf of methane gas. The 

relative magnitude of gas hydrates as a reservoir of organic carbon on the Earth is illustrated in figure 9. If these 

estimates of reservoir sizes are correct, then the amount of 

methane carbon in gas hydrates is a factor of two larger 

than the carbon present in known fossil fuel deposits (coal, 

oil, and natural gas). 

Dissolved 

organic matter 

in water 

980 

Land biota 

830 

Gas 

Marine biota 

3 

hydrate 

(onshore and offshore) 

10,000 

Figure 9. Distribution of organic carbon in the Earth, excluding 

dispersed organic carbon such as kerogen and bitumen, which 

equals nearly I ,000 times the total amount shown in the diagram. 

Numbers are in units of 10 15 g of carbon. Modified from Kvenvolden ( 1988). 

RECOVERY OF METHANE 

Although naturally occurring gas hydrates were recognized in the 1960's, the gas industry has been slow to develop methods to recover methane from these substances. 

Three principal methods are being considered: thermal 

stimulation, depressurization, and inhibitor injection (Holder and others, 1984 ). In thermal stimulation, the gashydrate-bearing strata are heated in order to increase the 

local temperature enough to cause gas hydrates to dissociate. In depressurization, the pressure in the gas-hydrate deposit is lowered by pumping to cause gas-hydrate 

dissociation; heat for the depressurization process is provided by the natural geothermal heat flow. Injection of inhibitors, that is, agents such as methanol that cause gas 

hydrates to dissociate, shifts the pressure-temperature equilibrium (phase boundary) so that the gas hydrates are no 

longer stable at in-situ pressure-temperature conditions. Of 

these three production methods, depressurization combined 

with hot-water injection appears to be the most practical 

where free gas is trapped beneath the gas hydrate (Holder 

and others, 1984 ). That free gas is trapped beneath the gas 

hydrate has yet to be established with certainty as discussed 

previously. Gas hydrates will become a potential energy 

resource when it can be shown that the energy required to 

release methane from the hydrate itself is significantly less 

than the thermal energy of the methane that can be recovered from the dissociated gas-hydrate deposits. Circulation 

of warm surface water into gas-hydrate deposits and horizontal drilling techniques provide possible future approaches to the exploitation of hydrated methane. 

The production of methane from gas hydrates requires 

that the deposit occur in geologic contexts wherein the elements of a conventional gas deposit are present; that is, 

in association with a reservoir of adequate porosity and 

permeability, with a methane source, and with a seal to 

form a trap. Dissociated gas hydrate can serve as one 

source of methane; migrated methane from below the gashydrate zone is another possible source. The ability of the 

gas-hydrate to act as a seal, however, has not been well 

established. Miller and others (1991) and Lee and others 

(this volume) present geophysical evidence from the Blake 

Outer Ridge that suggests gas hydrates are trapping gas 

beneath the BSR (fig. 6). Examples of possible traps 

caused by gas hydrates are shown in figure 10. These examples assume that the gas-hydrate-containing interval is 

impermeable and that free gas can be trapped. The free 

gas below the gas hydrate has migrated up from depth and 

can be from both microbial and thermal sources. As free 

gas (methane) is removed by production and pressure is 

reduced, the gas-hydrate seal will begin to decompose, 

providing more producible methane from the hydrated 

sediments. Thus the seal becomes a source. Two of the 

trapping situations (figs. I OA, 1 OC) in figure I 0 are in effect structural, caused by the domal or anticlinal shapes of 

the gas-hydrate layer. The other trap (fig. I OB) is stratigraphic, where gas-bearing strata are sealed at their updip 

ends by the presence of gas hydrates (Dillon and others, 

1980). 

Development of the Messoyakha gas field in western 

Siberia during the past 25 years has shown that methane 

can be recovered from naturally occurring gas hydrates 

(Makogon, 1981; Collett, this volume), but the methanol 

injection methods used for production proved to be prohibitively expensive. Recovery of gas hydrates in pressurized core barrels at the Area-Exxon N.W. Eileen State No. 

2 wildcat well on the North Slope of Alaska confirmed the 

presence of gas hydrates in the region of the Prudhoe Bay 

and Kuparuk River oil fields (Kvenvolden and McMenamin, 1980). It has been estimated that about 1.1 X 1 o12 

m3 of methane (440x10 12 g methane carbon) are present 

in gas hydrates of this region (Collett, 1992). This amount 

of methane is about 1.4 times the methane estimated to be 

in conventional reservoirs in the same region, but is only 9 
A PRIMER ON GAS HYDRATES 289 

percent of the estimated conventional North American gas 

reserves (fig. I 1). If methane from gas hydrates is ever to 

be recovered commercially in the U.S., larger accumulations will have to be identified and exploited. Initial production, however, is likely to come from the North Slope 

of Alaska where the industrial infrastructure for handling 

gas is already in place. Methane first produced from gas 

hydrates on the North Slope will likely be used for repressurization of waning oil fields rather than as a source of 

fuel. Although methane from gas hydrates should be considered a potential energy resource, wide-scale recovery of 

A B c 

Figure 10. Schematic diagrams of geological situations in which 

gas hydrates serve as seals forming traps for methane. Developed 

from Dillon and others (1980). A, Gas hydrate layer forms anticline-like structure, trapping free methane below. B, Gas-hydrate 

layer seals methane-bearing strata at their updip ends. C, Base of 

gas-hydrate layer has migrated upward in response to the 

changed geothermal gradient caused by the emplacement of the 

salt dome, forming a gas trap. 

NORTH AMERICAN 

GAS RESERVES 

(LESS PRUDHOE-KUPARUK 

GAS RESERVES) 

11.7 X 10'2 rn3 

PRUDHOE-KUPARUK 

GAS HYDRATE 

1.1 X 1012 m3 

Figure 11. Comparison of the amount of methane estimated to 

be present in gas hydrate in the region of the Prudhoe Bay and 

Kuparuk River (Alaska) oil fields with the amount of methane 

estimated to be present in conventional reservoirs in the same 

region and in North America. 

methane from gas hydrates will probably not be accomplished until the 21st century (Sloan, 1990). 

CONCLUSIONS 

From a geologic perspective, gas hydrates are an important feature of the shallow geosphere. If current estimates are correct, gas hydrates contain more potential 

fossil fuel energy than occurs in conventional oil, gas, and 

coal deposits. Uncertain, however, is the proportion of this 

potential energy source that can actually be exploited. Because of unsolved technological problems in producing 

methane from gas hydrates, wide-scale recovery of methane from these substances probably will not take place 

until sometime in the 2 I st century. 

ACKNOWLEDGMENTS 

I thank D.W. Scholl and R.E. Kayen for their reviews, 

and S.R. Vath and T.D. Lorenson for their assistance in the 

preparation of figures. 

REFERENCES CITED 

Behrmann, J.H., Lewis, S.D., Musgrave, R.J., and others, I 992, 

Proceedings of the Ocean Drilling Program, Initial Reports, 

v. 141: College Station, Texas, Ocean Drilling Program, 

708 p. 

Bernard, B.B., Brooks, J.M., and Sackett, W.M., 1976, Natural gas 

seepage in the Gulf of Mexico: Earth and Planetary Science 

Letters, v. 31, p. 48-54. 

Brooks, J .M., Barnard, L.A., Wiesen burg, D.A., Kennicutt II, M.C., 

and K venvolden, K.A., 1983, Molecular and isotopic compositions of hydrocarbons at site 533, Deep Sea Drilling Project 

Leg 76, in Sheridan, R.E., Gradstein, F., and others, eds., 

Initial Reports of the Deep Sea Drilling Project, v. 67: Washington, D.C., U.S. Government Printing Office, p. 377-384. 

Brooks, J.M., Cox, H.B., Bryant, W.R., Kennicutt II, M.C., Mann, 

R.G., and McDonald, T.J., 1986, Association of gas hydrates 

and oil seepage in the Gulf of Mexico: Organic Geochemistry, v. I 0, p. 221-234. 

Brooks, J.M., Field, M.E., and Kennicutt II, M.C., 1991 , Observations of gas hydrates in marine sediments, offshore northern 

California: Marine Geology, v. 96, p. I 03-I 08. 

Brooks, J.M., Jeffrey, A.W.A., McDonald, T.J., Pflaum, R.C., and 

Kvenvolden, K.A., 1985, Geochemistry of hydrate gas and 

water from site 570, Deep Sea Drilling Project Leg 84, in von 

Huene, R., Aubouin, J ., and others, eds., Initial Reports of the 

Deep Sea Drilling Project, v. 84: Washington, D.C., U.S. 

Government Printing Office, p. 699-703. 

Claypool, G.W., and Kaplan, I.R., 1974, The origin and distribution of methane in marine sediments, in Kaplan, I.R., ed., 

Natural gases in marine sediments: New York, Plenum Press, 

p. 99-139. 
290 THE FUTURE OF ENERGY GASES 

Claypool, G.W., and Kvenvolden, K.A., 1983, Methane and other 

hydrocarbon gases in marine sediment: Annual Review of 

Earth and Planetary Sciences, v. 11, p. 299-327. 

Claypool, G.W., Presley, B.J., and Kaplan, I.R., 1973, Gas analyses in sediment samples from Legs 10, 11, 13, 14, 15, 18, 

and 19, in Scholl, D.W., and others, eds., Initial Reports of 

the Deep Sea Drilling Project, v. 19: Washington, D.C., U.S. 

Government Printing Office, p. 879-884. 

Claypool, G.W., Threlkeld, C.N., Mankewicz, P.N., Arthur, M.A., 

and Anderson, T.A., 1985, Isotopic composition of interstitial fluids and origin of gases in sediments of the Middle 

America Trench, DSDP Leg 84, in von Huene, R., Aubouin, 

J., and others, eds., Initial Reports of the Deep Sea Drilling 

Project, v. 84: Washington, D.C., U.S. Government Printing 

Office, p. 683-691. 

Collett, T.S., 1992, Potential of gas hydrates outlined: Oil and 

Gas Journal, v. 90, no. 25, p. 84-87. 

Collett, T.S., Bird, K.J., Kvenvolden, K.A., and Magoon, L.B., 

1988, Geologic interrelations relative to gas hydrates within 

the North Slope of Alaska: U.S. Geological Survey OpenFile Report 88-389, 150 p. 

Dillon, W.P., Grow, J.A., and Paull, C.K., 1980, Unconventional 

gas hydrate seals may trap gas off southeast U.S.: Oil and 

Gas Journal, v. 78, no. 1, p. 124-130. 

Galimov, E.M., and Kvenvolden, K.A., 1983, Concentrations and 

carbon isotopic compositions of CH4 and C02 in gas from 

sediments of the Blake Outer Ridge, Deep Sea Drilling 

Project Leg 76, in Sheridan, R.E., Gradstein, F., and others, 

eds., Initial Reports of the Deep Sea Drilling Project, v. 76: 

Washington, D.C., U.S. Government Printing Office, p. 403-

407. 

Ginsburg, G.D., Guseynov, R.A., Dadashev, A.A;, Ivanov, G.A., 

Kazantsev, S.A., Solov'yev, V.A., Telepnev, E.V., AskeriNasirov, R. Ye., Yesikov, A.D., Mal'tseva, V.I., Mashirov, Yu. 

G., and Shabayeva, I. Yu., 1992, Gas hydrates of the southern 

Caspian: International Geology Review, v. 34, p. 765-782. 

Ginsburg, G.D., Kremlev, A.N., Grigor'ev, M.N., Larkin, G.V., 

Pavlenkin, A.D., and Saltykova, N.A., 1990, Filtrogenic gas 

hydrates in the Black Sea: Soviet Geology and Geophysics 

(Allerton Press), v. 31, no. 3, p. 8-16. 

Goodman, M.A., 1980, Insitu gas hydrates-Past experience and 

exploitation concepts: Proceedings 1st International Gas Research Conference, Chicago. Illinois, p. 376-391. 

Hammerschmidt, E.G., 1934, Formation of gas hydrates in natural gas transmission lines: Industrial Engineering Chemistry, 

v. 26, p. 851-855. 

Hesse, R., and Harrison, W.E., 1981, Gas hydrates (clathrates) 

causing pore-water freshening and oxygen isotope fractionation in deep-water sedimentary sections of terrigenous continental margins: Earth and Planetary Science Letters, v. 55, 

p. 453-562. 

Hesse, R., Lebel, J., and Gieskes, J.M., 1985, Interstitial water 

chemistry of gas-hydrate-bearing sections on the Middle 

America Trench slope, Deep Sea Drilling Project Leg 84, in 

von Huene, R., Aubouin, J., and others, eds., Initial Reports 

of the Deep Sea Drilling Project, v. 84: Washington, D.C., 

U.S. Government Printing Office, p. 727-736. 

Hitchon, B., 1974, Occurrence of natural gas hydrates in sedimentary basins, in Kaplan, l.R., ed., Natural gases in marine 

sediments: New York, Plenum Press, p. 195-225. 

Holder, G.D., Kamath, V.A., and Godbole, S.P., 1984, The potential of natural gas hydrates as an energy resource: Annual 

Review of Energy, v. 9, p. 427-445. 

Hunt, J.M., 1979, Petroleum geochemistry and geology: San 

Francisco., W.H. Freeman, 617 p. 

Hyndman, R.D., and Davis, E.E., 1992, A mechanism for the 

formation of methane hydrate and seafloor bottom-simulating reflectors by vertical fluid expulsion: Journal of Geophysical Research, v. 97, no. B5, p. 7025-7041. 

Hyndman, R.D., and Spence, G.D., 1992, A seismic study of 

methane hydrate marine bottom simulating reflectors: Journal of Geophysical Research, v. 97, no. B5, p. 6683-6698. 

Jeffrey, A.W.A., Pflaum, R.C., McDonald, T.J., Brooks, J.M., and 

Kvenvolden, K.A., 1985, Isotopic analysis of core gases at 

sites 565-570, Deep Sea Drilling Project Leg 84, in von 

Huene, R., Aubouin, J ., and others, eds., Initial Reports of 

the Deep Sea Drilling Project, v. 84: Washington, D.C., U.S. 

Government Printing Office, p. 719-726. 

Jenden, P.D., and Gieskes, J.M., 1983, Chemical and isotopic 

compositions of interstitial water from Deep Sea Drilling 

Project sites 533 and 534, in Sheridan, R.E., Gradstein, F., 

and others, eds., Initial Reports of the Deep Sea Drilling 

Project, v. 76: Washington, D.C., U.S. Government Printing 

Office, p. 453-461. 

Katz, D.L., Cornell, D., Kobayashi, R., Poettmann, F.H., Vary, 

J.A., Elenblass, J.R., and Weinaug, C.F., 1959, Handbook of 

natural gas engineering: New York, McGraw Hill, 802 p. 

Kvenvolden, K.A., 1988, Methane hydrate-A major reservoir of 

carbon in the shallow geosphere?: Chemical Geology, v. 71, 

p.41-5l. 

----in press, Gas hydrates-Geological perspective and global change: Reviews of Geophysics. 

K venvolden, K.A., and Barnard, L.A., 1983a, Hydrates of natural 

gas in continental margins, in Watkins, J.S., and Drake, 

C.L., eds., Studies in continental margin geology: American 

Association of Petroleum Geologists Memoir 34, p. 631-

640. 

---1983b, Gas hydrates of the Blake Outer Ridge, Site 533, 

Deep Sea Drilling Project Leg 76, in Sheridan, R.E., Gradstein, F., and others, eds., Initial Reports of the Deep Sea 

Drilling Project, v. 76: Washington, D.C., U.S. Government 

Printing Office, p. 353-365. 

Kvenvolden, K.A., Claypool, G.E., Threlkeld, C.N., and Sloan, 

E.D., 1984, Geochemistry of a naturally occurring massive 

marine gas hydrate: Organic Geochemistry, v. 6, p. 703-713. 

Kvenvolden, K.A., Ginsburg, G.D., and Solovyev, V.A., 1993, 

Worldwide distribution of subaquatic gas hydrates: GeeMarine Letters, v. 13, p. 32-40. 

Kvenvolden, K.A., and Grantz, A., 1990, Gas hydrates of the 

Arctic Ocean region, in Grantz, A., Johnson, L., and 

Sweeney, J.F., eds., The Arctic Ocean region: Boulder, Colorado, Geological Society of America, The Geology of North 

America, v. L, p. 539-549. 

K venvolden, K.A., and Kastner, M., 1990, Gas hydrates of the 

Peruvian outer continental margin, in Suess, E., von Huene, 

R., and others, eds., Proceedings of the Ocean Drilling Program, scientific results, v. 112: College Station, Texas, 

Ocean Drilling Program, p. 517-526. 

Kvenvolden, K.A., and McDonald, T.J., 1985, Gas hydrates of 

the Middle America Trench-Deep Sea Drilling Project Leg 
A PRIMER ON GAS HYDRATES 291 

84, in von Huene, R., Aubouin, J., and others, eds., Initial 

Reports of the Deep Sea Drilling Project, v. 84: Washington, 

D.C., U.S. Government Printing Office, p. 667-682. 

Kvenvolden, K.A., and McMenamin, M.A., 1980, Hydrates of 

natural gas-A review of their geologic occurrence: U.S. 

Geological Survey Circular 825, II p. 

MacDonald, G.T., 1990a, The future of methane as an energy 

resource: Annual Review of Energy, v. 15, p. 53-83. 

---1990b, Role of methane clathrates in past and future climates: Climatic Change, v. 16, p. 247-281. 

Mathews, M., 1986, Logging characteristics of methane hydrate: 

The Log Analyst, v. 27, no. 3, p. 26-63. 

Makogon, Yu. F., 1981, Hydrates of natural gas: Tulsa, Okla., 

Pennwell Publishing Company, 237 p. 

Miller, JJ., Lee, M.W., and von Huene, R., 1991, An analysis of 

a seismic reflection from the base of a gas hydrate zone, 

offshore_ Peru: American Association of Petroleum Geologists Bulletin, v. 75, p. 910-924. 

Ocean Drilling Program, 1986, Guidelines for pollution prevention and safety: JOIDES Journal, v. 12 (Special Issue 5), 40 p. 

Pflaum, R.C., Brooks, J.M., Cox, H.B., Kennicutt II, M.C., and 

Sheu, D-D., 1986, Molecular and isotopic analysis of core 

gases and gas hydrates, Deep Sea Drilling Project Leg 96, in 

Bouma, A.H., Coleman, J.M., Meyer, A.W., and others, eds., 

Initial Reports of the Deep Sea Drilling Project, v. 96: 

Washington, D.C., U.S. Government Printing Office, p. 781-

784. 

Potential Gas Committee, 1981, Potential supply of natural gas 

in the United States (as of December 31, 1980): Golden, 

Colorado, Potential Gas Agency, Colorado School of Mines, 

119 p. 

Shipley, T.H., Houston, M.H., Buffler, R.T., Shaub, FJ., McMillen, K.J., Ladd, J.W., and Worzel, J.L, 1979, Seismic reflection evidence for the widespread occurrence of possible 

gas-hydrate horizons on continental slopes and rises: American Association Of Petroleum Geologists Bulletin, v. 63, 

p. 2204-2213. 

Sloan, E.D., 1990, Clathrate hydrates of natural gas: New Yorl5-, 

Marcel Dekker, 641 p. 

Yamamoto, S., Alcauskas, J.B., and Crozier, T.E., 1976, Solubility of methane in distilled water and seawater: Journal of 

Chemical and Engineering Data, v. 21, p. 78-80. 

Yamano, M., and Uyeda, S., 1990, Heat-flow studies in the Peru 

Trench subduction zone, in Suess, E., von Huene, R., and 

others, eds., Proceedings of the Ocean Drilling Program, scientific results, v. 112: College Station, Texas, Ocean Drilling 

Program, p. 653-661. 

Yamano, M., Uyeda, S., Aoki, Y., and Shipley, T.H., 1982, Estimates of heat flow derived from gas hydrates: Geology, 

v. 10, p. 339-343. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Rock Physics for Characterization of Gas Hydrates 

By Jack Dvorkin1 and Amos Nur1 

CONTENTS 

Abstract .oo.oooo•ooooooooooooooooooooooooooooooooooooooooo····ooooooooooooooooooo 

Introduction .......... ~ ....................................................... . 

Cemented Materials: A Model for Hydrate-Cemented 

Sediments oooooooooooo••••oo•ooooooooo••oo••oooooooooooooooo•ooooooooo···oo·oo·· 

Experiments oooooooooooooooooooooooooOOOOOOOOOOOOOOOOOOOoooooooooo •• oo. 

Theory OOOOoooooooooooooooooooooooooooOOOoOOOOOOOOOooooooooo,,oo.oooo•·••oo 

Hydrate Deposition, Porosity and Effective 

Properties . 000 000.00 000 ••• 0000 00 00 000000 000.00 00 00 00 •• 0000 •• 00 00000 000.00 

Conclusions oooooooooooooooooooooo··oo·•ooooooooooooOOOOOoOOOOOOoooo••oo•oo••oo 

References Cited . 00.00 00 •• 00 00.0000 000 000 oo• 00 ••• oo• 0000 oo•. 0000 00 00 00 00.00 

ABSTRACT 

293 

293 

294 

294 

294 

296 

298 

298 

Our theoretical and experimental results indicate that 

even small amounts of intergranular cementation can dramatically increase the stiffness of a granular material if the 

cement is placed around grain-to-grain contacts. This finding can explain the seismically discovered phenomenon of 

bottom-simulating-reflectors (BSR's): the gas-hydrate cementation above a reflector acts to strongly increase the 

elastic moduli of the rock, an effect that results in strong 

reflections at the base of a hydrated zone, and muted reflections at natural lithological boundaries within the zone. 

INTRODUCTION 

Gas-hydrate layers, marked by prominent bottom-simulating reflectors (BSR's) at continental margins, trap a sig1

Stanford University, Department of Geophysics, Stanford, CA 

94305-2215. 

nificant proportion of global methane. The geophysical 

characterization of gas hydrates, including the percentage of 

c pore space filled with gas hydrates, is among the central 

topics of gas-hydrate-layer characterization. In his overview 

of the National Workshop on Gas Hydrates, Dillon (1991) 

stated that "Seismic and geochemical studies probably will 

remain the most important approaches to studying gas hydrates, as they have in the past, but major changes in approach 

are necessary. Seismic studies must go beyond the analysis 

of the reflection from the base of the hydrate zone (the BSR) 

and begin to consider the acoustic velocity and reflection 

responses to hydrate occurrence across the entire zone of 

hydrate stability and relationships of hydrates to other geological factors." The quantitative mechanical characterization of gas-hydrate layers is necessary for assessing the 

likelihood of penetrating recoverable hydrates and for predicting possible engineering complications (such as drilling 

hazards and underwater landslides). Theoretical and experimental rock physics can provide a link between the seismically observable characteristics (seismic reflections and 

velocities) of sediments containing gas hydrates and their 

physical state (the amount of gas hydrates, their location 

within the pore space, and the strength of hydrated rock). 

Our experimental and theoretical results show that 

even small amounts of intergranular hydrate cementation 

may dramatically increase -the elastic moduli of the dry 

rock frame and thus produce the BSR effect. Therefore, 

there is no need to assume that the seismic contrast between hydrated and hydrate-free zones is due to free gas 

underneath a BSR, or some other pore-fluid arrangement. 

Our main assumption here is that gas hydrates change the 

properties of oceanic sediments by cementing grain-tograin contacts (fig. 1). This morphological arrangement 

may also explain why lithologically controlled reflectors 

have lower amplitude within the zone containing solid hydrates. Indeed, "advanced cementation makes all rocks 

look much the same" (Anstey, 1991). 

293 
294 THE FUTURE OF ENERGY GASES 

as .~ c 

grain 

Intergranul ar 

cementation 

Sediments with intergranul ar 

Figure 1. Two elastic grains (dark gray) with cement (light gray) at their contact, and a 

granular material (dark gray) with gas-hydrate cement (light gray) and some residual 

pore space (white). 

In this short paper we present some experimental and 

theoretical results of our rock physics investigation of 

cemented granular materials. The experiments included 

measuring ultrasonic velocities in artificial granular samples (precompacted glass beads) that were cemented by (I) 

freezing capillary water accumulated at the grain contacts 

and (2) using epoxy as a cement. 

The freezing experiments showed a strong increase of 

compressional-wave velocity at the freezing point, that is, 

at the point where the unconsolidated grains became icecemented. This experiment may be especially relevant to 

gas hydrates because the mechanical properties of hydrates 

and ice are similar (Sloan, 1989). 

The second set of experiments, which used epoxy as a 

cement, also showed a strong increase in both compressional- and shear-wave velocities with the addition of only a 

small amount of the cement. The results of our theoretical 

modeling of cemented granular materials are in close agreement with the data from this second set of experiments. 

Our conclusion is that similar intergranular cementation of sediments by gas hydrates may be responsible for 

the BSR effect. Moreover, the existence of a BSR may be 

due to only small amounts of gas hydrates above it, so 

these traces of hydrates may be easily missed in the extracted cores as well as in the well-log data. 

CEMENTED MATERIALS: A MODEL FOR 

HYDRATE-CEMENTED SEDIMENTS 

EXPERIMENTS 

In our first set of experiments, a granular material 

was represented by identical glass beads. A container with 

the beads was filled with water that was allowed afterwards to slowly escape the sample through drainage. The 

process of cementation was simulated by freezing the capillary water accumulated at the bead contacts. The measured compressional velocity in the material had small 

constant values before freezing and increased sharply at 

.. 

> 1.500 ~ " 

" 

-~ 

.~ 1: 

500 c. 

E • • • 0 

u 

-20 -15 -10 -5 0 10 

Figure 2. Our experimental results on compressional-wave 

(P-wave) velocity versus temperature in ice-cemented glass beads. 

the freezing point (fig. 2). This effect is apparently due to 

the solidification of the small pendular rings that form ice 

intergranular cement. 

We also measured compressional- and shear-wave velocities (hereinafter referred to as compressional and shear 

velocities) in epoxy-cemented glass beads at varying 

epoxy saturation of the pore space. The important experimental result is that the velocity increase with saturation is 

very large between 0 and 10 percent saturation and negligible between 50 and 100 percent saturation (fig. 3). 

Therefore, cementation can dramatically increase the stiffness of a granular material only if it is placed around 

grain-to-grain contacts. 

THEORY 

Our theoretical model allows one to calculate the effective elastic properties of a random packing of identical 

elastic spheres with elastic cement at their contacts. The 

effective bulk and shear moduli of a packing are calculated from the average number of contacts per sphere and 
ROCK PHYSICS FOR CHARACTERIZATION OF GAS HYDRATES 295 

porosity of the aggregate, and from the normal and tangential stiffnesses of a two-grain combination. These stiffnesses are found by solving the problems of normal and 

tangential deformation of two elastic spherical grains cemented at their contact. 

The effective elastic properties of a random packing of 

identical spherical particles can be expressed through its 

porosity (0), coordination number (C) (the average number of contacts per sphere), the radius of a particle (R), 

and the normal (Sn) and tangential (St) stiffnesses of a 

two-sphere combination (Digby, 1981; Winkler, 1983). 

The normal and shear stiffnesses are defined as the ratios 

of a corresponding force increment to the displacement of 

the sphere center relative to the contact region (fig. 4): 

s n 

aF -S ao' '[ 

where F is normal force, 0 is normal displacement, T is 

tangential force, and T is tangential displacement. 

Effective bulk (Keff) and shear (Geff) moduli are as 

follows: 

K = c (I - ¢) s , G = c 0 - ¢) (s + ~s ) . 

eff 12:rtR n eff 20:rtR n 2 't 

Therefore, the effective compressional (Vp) and shear velocities (Vs) can be found as 

v 

p --

3C ( 2 ) S +-S V 

20:rtRp n 3 't ' s --c ( 3 ) S +-S 20:rtR n 2 't ' 

where p is the density of the grain material. 

3.5 

1.5 

0 

···--· ---•---- _; ____ . •---··r· -------, ./-· I : I . I . 

I 

I 

I 

) 

0.2 0.4 

Compressional · 

velocity 

0.6 0.8 

Cement Saturation of Pore Space 

Figure 3. Compressional (Vp) and shear CVs) velocities measured 

in epoxy-cemented glass beads at varying cement saturation (1 

represents 100-percent saturation). Circles indicate measurement 

points. The experiments were conducted using the ultrasonic 

pulse transmission method. The glass beads (0.2-0.3 mm diameter) were precompacted at 20 megapascals (MPa). 

The solution to the problem of the normal and tangential deformation of two cemented grains is based on the 

assumption that the surface area of a contact region is 

small compared to that of the grain.The case of normal 

deformation was discussed by Dvorkin and others, 1991. 

In the following example we explore the influence of 

the amount of cementation on the effective properties (compressional and shear velocities) of a random packing of 

identical spheres. The porosity of the packing (without cementa~ion) was 0.36 (that is, 36 percent of the total volume 

was pore space), the coordination number was 9. The properties of the grain material were as follows: density, 2,480 

kg/m3

; bulk modulus, 49.9 gigapascals (GPa); and shear 

modulus, 26.2 GPa-parameters typical for glass. The density of the cement material was 1,160 kg/m3. We explored 

four cases of the increasing stiffness of the cement: (a) 

Kc=3.4 GPa, Gc=l.O GPa; (b) Kc=6.8 GPa, Gc=2.0 GPa; (c) 

Kc=13.6 GPa, Gc=4.0 GPa; and (d) Kc=27.2 GPa, Gc=8.0 

GPa (Kc and Gc are the bulk and shear moduli of the cement). The second case (b) corresponds to typical epoxy 

parameters. The ratio of the cement-layer radius to the grain 

radius varied from 0.01 to 0.5. 

Plots in figure 5 show that both compressional and 

shear velocities dramatically increase with the increasing 

radius of the cement layer. The influence of this parameter 

is clearly much stronger than that of the cement stiffness: 

even a small increase in the amount of relatively soft cement yields a significant rise in both velocities. 

We explored the effect of cementation stiffness (fig. 6) 

in a random packing of identical spheres for a constant 

amount of cement (the ratio of the cement-layer radius to 

the grain radius was 0.1). The parameters of the grain material were kept constant with bulk and shear moduli 49.9 

and 26.2 GPa, respectively, whereas the bulk and shear 

moduli of the cement were varied respectively from 3.4 

GPa and 1.0 GPa to 68 GPa and 20 GPa. This dramatic 

increase in cement stiffness resulted in only about a 15 

percent increase in compressional velocity and a 20 

percent increase in shear velocity-an effect much smaller 

than that of increasing cement content. 

Figure 4. Normal and shear deformation of a two-grain combination. F, normal force; T, tangential force; fl, normal displacement; 1:, tangential displacement. 
296 THE FUTURE OF ENERGY GASES 

HYDRATE DEPOSITION, POROSITY AND 

EFFECTIVE PROPERTIES 

The following example illustrates how two possible 

schemes of hydrate deposition may affect the porosity and 

the elastic moduli of a granular material. 

tacts. In the second model, the hydrates evenly cover the 

grains and the contact cement layer is formed as an intersection of these cement shells. It is clear that in the first 

model, the size of a contact cement layer is larger (for 

given porosity) than in the second model. This effect results 

in a steeper increase of the effective moduli with decreasing 

porosity in the first model as compared to the second (fig. 

7). Both bulk and shear moduli steeply increase at the very 

beginning of cement deposition because even a small addition of cement at intergranular contact points leads to rapid 

widening of the cement layer. 

The process of cementation starts at the critical porosity point (about 36 percent for a random identical-sphere 

packing) at which both bulk and shear moduli are zero in 

an unconsolidated granular material. In the first model, all 

added hydrate cement accumulates at the intergranular con3.5 

~ 

-'!2. 

g 

0 2.5 ·o 

~ > 

(;3 

= 

·~ Vl 1.5 ~ 0.. 

E 

0 

u 

0.5 

Grains: 

density= 2480 kg/cum 

K = 49.9 GPa, G = 26.2 GPa 

Cemenl: 

density= 1160 kg/cu m 

a. K = 3.4 GPa. G = 1.0 GPa 

b. K = 6.8 GPa, G = 2.0 GPa 

c. K = 13.6 GPa. G = 4.0 GPa 

d. K = 27.2 GPa. G = 8.0 GPa 

0 0.1 0.2 0.3 0.4 

A Cement Layer Radius I Grain Radius 

2.5 

Grains: 

density = 2480 kg/cu m 

K = 49.9 GPa. G = 26.2 GPa 

Cement: 

density = t 160 kg/cu m 

0.5 a. K = 3.4 GPa. G = 1.0 GPa 

b. K = 6.8 GPa. G = 2.0 GPa 

c. K = 13.6 GPa, G = 4.0 GPa 

d. K = 27.2 GPa. G = 8.0 GPa 

.. ..... ..!...................... . ............................ . 

0.5 

0 

.. ..... L 

0.1 

..... L. 

0.2 0.3 0.4 0.5 

B Cement Layer Radius I Grain Radius 

Figure 5. Compressional (A) and shear (B) velocities in random packings of identical cemented spherical particles as functions of the amount of cementation. The 

parameters of the grain material are constant; the parameters of the cement vary 

from soft (a) to stiff (d). Both velocities are strongly affected by the amount of 

cement rather than by the cement stiffness. K, bulk modulus; G, shear modulus. 
~ ~ 

g 

0 

> 

~ G) 

..c: 

VJ 

"0 

§ 

Ol 

c:: 

·~ 

2 

0. 

E 

0 

u 

A 

B 

ROCK PHYSICS FOR CHARACTERIZATION OF GAS HYDRATES 297 

1.8 

1.6 

1.4 

1.2 

0.0 

0.0 

5 9 

Grains: 

density = 2480 kg/cu m 

K = 49.9 GPa, G = 26.2 GPa 

Cement: 

density = 1160 kg/cu m 

rnodL •:, gradually increase from 

K = 3.4 GPa, G = 1.0 GPa 

to 

K = 68 GPa. G = 20 GPa 

II 13 15 17 19 

Factors by Which Cement Moduli Increase Rclalivc to the First Point 

0.1 0.2 

Porosity 

0.3 0.4 

l.O~-----------,------------~------------,-------------

Modified 

Grains and ccmcnL arc idcnlica l: 

K = 49.9 GPa. G = 26.2 Gl'a 

0.0 ______________ _j_ _________ _ 

0.0 0.1 0. 2 

Porosity 

0.4 

Figure 6. Compressional CVp) and shear CVs) velocities in a random packing of identical cemented 

spherical particles as a function of cement stiffness. Ratio of cement-layer radius to grain radius 

is constant and equals 0.1 . The effect of increasing 

cement stiffness on the effective properties of cemented granular materials is much smaller than 

that of increasing amounts of cement. K, bulk 

modulus; G, shear modulus. 

Figure 7. Bulk (A) and shear (B) moduli of a 

random packing of identical glass beads for two 

models of cement deposition (see text for discussion of models). The moduli are normalized by 

those of glass, so a bulk modulus of I on the 

vertical scale in figure 7A corresponds to the bulk 

modulus assumed here for glass (=49.9 GPa). Porosity of aggregate decreases with increasing 

amount of cement. Moduli steeply increase at initial stage of cementation. Modified upper-bound 

Hashin-Shtrikman formulas (Chen, 1992) provide 

reasonable extensions of the moduli curves into 

the low-porosity domain. Both grains and cement 

are assumed to have a bulk modulus (K) and 

shear modulus (G) typical of glass. 
298 THE FUTURE OF ENERGY GASES 

Our theoretical model is applicable only for small 

amounts of cement at intergranular contacts. We have 

found that a possible appropriate continuation of the moduli 

curves to the low-porosity region· can be provided by the 

modified Hashin-Shtrikman upper bounds (Chen, 1992). 

CONCLUSIONS 

Both theoretical and experimental rock physics investigations of cemented granular materials show that even 

small amounts of cement at the grain contacts significantly 

increase rock stiffness. This fact explains the seismic contrasts observed at the boundaries of gas-hydrate zones, as 

well as muted reflections observed within these zones. Applying rock physics to gas-hydrate investigation can help 

in interpreting seismic data to determine the amounts of 

gas hydrates in sediments and, probably, to determine the 

strength of sediments containing gas hydrates. 

REFERENCES CITED 

Anstey, N.A., 1991, Velocity in thin section: First Break, v. 9, 

p. 449-457. 

Chen, Q., 1992, Critical concentration models for the mechanical 

and acoustic properties of porous materials: Palo Alto, 

Calif., Stanford University, Ph.D. dissertation. 

Digby, P.J., 1981, The effective elastic moduli of porous granular 

rocks: Journal of Applied Mechanics, v. 48, p. 803-808. 

Dillon, W.P., 1991, Overview of the National Workshop on Gas 

Hydrates: Report on National Workshop on Gas Hydrates, 

U.S. Department of Energy, p. 1-5. 

Dvorkin, J., Mavko, G., and Nur, A., 1991, The effect of cementation on the elastic properties of granular material: Mechanics of Materials, v. 12, p. 207-217. 

Sloan, E.D., Jr., 1989, Clathrate hydrates of natural gas: New 

York, Marcel Dekker. 

Winkler, K.W., 1983, Contact stiffness in granular porous materials-Comparison between theory and experiment: Geophysical Research, v. 10, p. 1073-1076. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Natural Gas Production from Arctic Gas Hydrates 

By Timothy S. Collett1 

CONTENTS 

Abstract . .. . .. ... . .. ... . ... ..... ...... ..... ..... .. ....... .. ...... .... .. .......... 299 

Introduction ................................................................... 299 

Prudhoe Bay-Kuparuk River Gas-Hydrate 

Accumulation . ...... .. . ... ... .. . ... ... ...... .. ... .. .. .. .. .. .. .... .. .. ........ 300 

Messoyakha Gas-Hydrate Accumulations ................... 305 

Messoyakha Production History . .. . .. . . . . .. ... . .. ... ... . ..... .... 308 

Potential Production from the Prudhoe Bay-Kuparuk 

River Gas-Hydrate Accumulation ................................ 309 

Conclusions . ... . .. .. .. . . .. .. .... .. .... .. . . .. .. .. . .. .. ....... .... .. .. . . . ....... 310 

Acknowledgments ........................................................ 310 

References Cited . .. ... . ..... .... .... .... .. .. ... .. ... ... .. .. ..... ... ... .. ... 310 

ABSTRACT 

The natural-gas hydrates of the Messoyakha field in 

the West Siberian basin of Russia and those of the Prudhoe 

Bay-Kuparuk River area on the North Slope of Alaska 

occur within a similar series of interbedded Cretaceous and 

Tertiary sandstone and siltstone reservoirs. Geochemical 

analyses of gaseous well-cuttings and production gases 

suggest that these two hydrate accumulations contain a 

mixture of thermogenic methane migrated from a deep 

source and shallow, microbial methane that was either directly converted to gas hydrate or was first concentrated in 

existing traps and later converted to gas hydrate. Studies of 

well logs and seismic data have documented a large freegas accumulation trapped stratigraphically downdip of the 

gas hydrates in the Prudhoe Bay-Kuparuk River area. The 

presence of a gas-hydrate/free-gas contact in the Prudhoe 

1

U.S. Geological Survey, Denver Federal Center, P.O. Box 25046, 

MS 940, Denver, CO 80225. 

Bay-Kuparuk River area is analogous to that in the Messoyakha gas-hydrate/free-gas accumulation, from which 

approximately 5.17xi09 cubic meters (183 billion cubic 

feet) of gas have been produced from the hydrates alone. 

The apparent geologic similarities between these two accumulations suggest · that the gas-hydrate-depressurization 

production method used in the Messoyakha field may have 

direct application in northern Alaska. 

INTRODUCTION 

Large quantities of natural gas, composed mainly of 

methane, can occur in sediments in the form of gas hydrates. These substances are solids, composed of rigid 

cages of water molecules that trap molecules of gas. Cold 

surface temperatures at high latitudes are conducive to the 

development of onshore permafrost and gas hydrate in the 

subsurface. Gas hydrates are known to be present in the 

western Siberian platform (Makogon and others, 1972) 

and are believed to occur in other permafrost areas of 

northern Russia, including the Timan-Pechora province, 

the eastern Siberian craton, and the northeastern Siberian 

and Kamchatka areas (Cherskiy and others, 1985). Permafrost-associated gas hydrates are also present in the North 

American Arctic. Well-log responses attributed to the presence of gas hydrates have been observed in about one-fifth 

of the wells drilled in the Mackenzie Delta, and in the 

Arctic Islands over half of the wells are inferred to contain 

gas hydrates (Bily and Dick, 1974; Judge, 1988). Direct 

evidence for gas hydrates on the North Slope of Alaska 

comes from a core test, and indirect evidence comes from 

drilling and open-hole well logs that suggest the presence 

of numerous gas-hydrate layers in the area of the Prudhoe 

Bay and Kuparuk River oil fields (Collett, 1983; Collett 

and others, 1988). The combined information from Arctic 

gas-hydrate studies shows that in permafrost regions, gas 

299 
300 THE FUTURE OF ENERGY GASES 

hydrates may exist at subsurface depths ranging from 

about 130 to 2,000 m. Because large quantities of gas hydrates are widespread in permafrost regions they may be a 

potential energy resource. Worldwide estimates of the 

amount of gas within continental gas hydrates range from 

1.4xl013 to 3.4xl016 cubic meters (5.0xl02 to 1.2xl06 

trillion cubic feet) (reviewed by the Potential Gas Committee, 1981 ). 

The gas-hydrate accumulations of the Russian Messoyakha field, located in the West Siberian basin, and 

those of the Prudhoe Bay-Kuparuk River area of northern 

Alaska (fig. 1) are the most studied gas-hydrate accumulations in the world; however, language barriers have hindered previous attempts to compare these two hydrocarbon 

accumulations. The primary objectives of this paper are 

( 1) to describe the geologic and geochemical nature of 

both the Messoyakha and the Prudhoe Bay-Kuparuk River 

gas-hydrate accumulations and (2) to characterize the potential for gas production from the Alaskan gas hydrates 

on the basis of the production history of the Messoyakha 

accumulation. 

PRUDHOE BAY-KUPARUK RIVER 

GAS-HYDRATE ACCUMULATION 

Gas hydrates exist under a limited range of temperature and pressure conditions, and the depth and thickness 

of the zone of potential gas-hydrate stability can be calculated (Makogon, 1981). Depicted in figure 2 is the calculated thickness of the potential methane-hydrate stability zone 

in the N.W. Eileen State No. 2 well of the Prudhoe Bay oil 

field in northern Alaska. The zone of potential methanehydrate stability in the N.W. Eileen State No. 2 well lies 

within the depth interval from approximately 210 to 950 

m. Regional analysis of subsurface gas chemistry, temperatures, pore pressures, and pore-water salinities indicates 

that methane hydrate would be stable beneath most of the 

~---------------------------------------------------------------------------------. 

ARCTIC OCEAN 

.. 

OCEAN OCEAN 

Figure 1. Locations of known and inferred gas hydrates in marine sediments of outer continental margins (dots), and in continental 

permafrost (squares). Dashed lines in Antarctica indicate edges of ice shelves. Modified from Kvenvolden (1988). 
NATURAL GAS PRODUCTION FROM ARCTIC GAS HYDRATES 301 

en 

a: 

0 

200 

UJ 400 fUJ 

:2 

z 600 

::c 

5:,: BOO UJ 

0 

1000 

1200 

-20 

-Ba=f ~- ice-bearing 

permafrost 

-10 0 10 

TEMPERATURE, IN DEGREES CELSIUS 

20 

Figure 2. Phase diagram illustrating depth-temperature zones in 

which methane hydrates would be stable in N.W. Eileen State 

No. 2 well on North Slope of Alaska (modified from Collett, 

1983). See figure 5 for well location. 

coastal plain province of northern Alaska and that the stability zone would be thicker than 1 ,000 m in parts of the 

Prudhoe Bay oil field (fig. 3) (Collett and others, 1 988). 

Previous North Slope studies (Collett, 1983; Collett and 

others, I 988) indicate that gas hydrates occur only in rocks 

of the Cretaceous and Tertiary Sagavanirktok Formation 

(fig. 4) and are limited to the area overlying the Prudhoe Bay 

and Kuparuk River oil fields. The Sagavanirktok Formation 

consists of shallow-marine shelf and delta-plain deposits 

composed of sandstone, shale, and conglomerate whose 

provenance is the Brooks Range, to the south. In the Prudhoe 

Bay area, the Sagavanirktok Formation thickens from southwest (about 1,000 m) to northeast (about 2,000 m), and 

conformably overlies marine shale of the Canning Formation. The regional structure of the Sagavanirktok Formation 

in the study area is a gentle ( 1 o -2°) northeasterly-dipping 

monocline. The Sagavanirktok Formation includes the informally named West Sak and Ugnu sands. These oil-bearing 

horizons have been extensively described by Werner (1987) 

and are estimated to contain more than approximately 6 

million metric tons (40 billion barrels) of in-place lowgravity oil. In the Prudhoe Bay-Kuparuk River area, the 

Sagavanirktok Formation is cut by northwesterly striking 

1621 160' 1541 152° 148° 146° 

Figure 3. Isopach map of north-central Alaska showing calculated 

thickness (in meters) of methane-hydrate stability field. Isopachs are 

based on gas-hydrate-stability calculations from 124 wells (Collett 

and others, 1988). NPRA, National Petroleum Reserve in Alaska. 

high-angle normal faults, generally downthrown to the east 

(Werner, 1 987). A similar set of northwesterly striking faults 

cuts the older rocks in this area, suggesting a genetic linkage 

to the faults within the Sagavanirktok Formation. These 

faults are important in that they are interpreted to have 

served as conduits for oil and gas migration from the underlying Prudhoe Bay field (Carman and Hardwick, 1983). 

The only confirmation of natural-gas hydrate on the 

North Slope was obtained in 1972 when Arco and Exxon 

successfully recovered gas hydrate in a core (reviewed by 

Kvenvolden and McMenamin, 1980). This gas-hydrate 

sample was from a depth of about 666 min the N.W. Eileen 

State No. 2 well (cored interval 664 to 667 m)_ After completion of this well, the gas-hydrate-bearing interval was 

perforated and tested. A drill-stem test of the perforated 

interval from 663 to 671 m flowed gas at a maximum rate 

of 112 cubic meters per day (3,960 cubic feet per day). 

Geochemical analyses (table 1) reveal that methane was the 

dominant gas recovered during the drill-stem test (93 percent methane, 7 percent nitrogen) and from the core sample 

Table 1. Geochemical analysis of gas samples obtained from the hydrate-bearing core (664-667 m) and production 

flow test (663-671 m) in the N.W. Eileen State No.2 well at Prudhoe Bay, Alaska 

[From written common., 1983, P. Barker, Area Alaska Inc., Anchorage, Alaska. %, percent of total gas volume; ---, not detected] 

Sample type 

Interval depth Carbon dioxide Oxygen Nitrogen Methane Ethane 

(m) (%) (%) (%) (%) (%) 

Core 664-667 0.52 12.53 86.95 Trace 

Core 664-667 0.02 0.84 99.14 Trace 

Core 664-667 0.03 0.80 99.17 Trace 

Core 664-667 0.05 1.46 98.49 Trace 

Flow test 663-671 Trace 7.19 92.79 0.02 

Flow test 663-671 Trace 7.23 92.76 0.01 

Propane 

(%) 

Trace 

Trace 
302 THE FUTURE OF ENERGY GASES 

(87 to 99 percent methane) (written commun., 1983, P. 

Barker, Arco Alaska Inc., Anchorage, Alaska). 

Well-log data from an additional 445 North Slope wells 

were examined for possible gas-hydrate occurrences (Collett 

and others, 1988). This review of all available data revealed 

that gas hydrates probably occur in 50 of the surveyed wells. 

Many of these wells have multiple gas-hydrate-bearing 

units, and individual occurrences range from 3 to 31 m thick. 

The gas hydrates inferred from well logs occur in six laterally continuous sandstone and conglomerate units and are 

geographically restricted to the east end of the Kuparuk 

River production unit and the west end of the Prudhoe Bay 

production unit (figs. 5, 6). The six gas-hydrate-bearing rock 

units have each been assigned a reference letter (units A 

KUPARUK RIVER UNIT 1 D-8 ---- 25 KM ---- PRUDHOE BAY UNIT 0-3 

Ugnu 

sands 

West 

Sak 

sands 

0 PRESENT-DAY SEA LEVEL 

Gubik Formation ? 

t 

Sagavanirktok Formation 

(sandstone and conglomerate; 

nonmarine) 

0 

GR RES 

500 

PLIOCENE AND 

MIOCENE 

MIOCENE AND 

OLIGOCENE 

EOCENE 

PALEOCENE 

UPPER 

CRETACEOUS 

Figure 4. Well-log correlations between Kuparuk River Unit lD-8 and Prudhoe Bay Unit Q-3 wells showing the North Slope 

stratigraphic relations and terminology used in this report. Locally the Sagavanirktok Formation is overlain by the Gubik Formation. 

Depths are in meters measured from the kelly bushing. GR. gamma ray; RES, resistivity. 
NATURAL GAS PRODUCTION FROM ARCTIC GAS HYDRATES 

t5o oo· 

"'"" ~ 

Oliktok Point 

70 30' 

Harrison 

Bay 

Milne Point ' / "' <;:;. -

303 

I 

through F); unit A is stratigraphically the deepest (fig. 6), 

Recently completed three-dimensional seismic surveys have 

documented the probable occurrence of a gas-hydrate/freegas contact at the base of the methane-hydrate stability field 

in the west end of the Prudhoe Bay production unit (public 

presentation, 1987, C.G. Guderjahn, British Petroleum Exploration Inc., Anchorage, Alaska). Open-hole logs from 

wells in the west end of the Prudhoe Bay field also indicate 

the presence of a large free-gas accumulation trapped stratigraphically downdip from four of the log-inferred gas hydrates (figs. 5, 6; units A, B, C, D). The total mapped area of .t--Free 

~ Figure 5. Composite map showing location of all six gashydrate/free-gas units (A-F) in Prudhoe Bay-Kuparuk River area 

(modified from Collett and others, 1988). Also shown are locations of the N.W. Eileen State No. 2 well and the cross section in 

figure 6. Dots, well locations. 

SW 

Kuparuk River Unit 1 D-6 Kuparuk River Unit 1 C-6 

70, 15' 

COMPOSITE OF UNITS A-F 

NE 

NW. Eileen State No.2 

. / 

!..- gas 

Gas hydrate 

0 5 KM ,_____________, 

0 3 MILES 

0~--~~~~~------~--~~~~------------------~~~~~- G RES ~ GR RES ~ eve 

~ F f r 

100 ~ ~ -3.2 km- ). ~} - 6.4 km - i ~ ~ \ 

j ' } _'j ,• ) ~ 

200 __ )f.: ___ -- ,~------- ------------\} _______ £, ____ r~~~~~:~_hydra~~--~--- _,__ ~ f ~ stability field i 

; 

300 

~ 400 

~ 

-'= 

£ 

"!1. 

~ 500 

600 

600 

900 

? 

" ) 

~ ' --, 

~ 

/ -----;--

~ EXPLANATION 

I t D Gas hydrate 

/ ~Free gas 

Figure 6. Cross section showing lateral and vertical extent of gas hydrates and underlying free-gas occurrences in Prudhoe 

Bay-Kuparuk River area. See figure 5 for location of cross section. Gas-hydrate-bearing units are identified with reference 

letters A through F. Gamma-ray (GR) and resistivity (RES) logs are shown for three wells. Solid lines are log correlation 

markers used to construct regional stratigraphic framework. Dot-and-dashed lines bounding units are known boundaries; 

dashed lines are inferred boundaries. Modified from Collett and others (1988). 
304 THE FUTURE OF ENERGY GASES 

Figure 7. Schematic west-to-east cross section through Prudhoe Bay-Kuparuk River 

area illustrating possible gas migration paths 

and spatial relations between gas hydrates, 

free gas, oil, Eileen fault zone, base of icebearing permafrost (BIPF), and gas-hydrate 

stability field (modified from Carman and 

Hardwick, 1983, fig. 13). The Brookian sequence is primarily a passive-margin deposit 

composed of clastic sedimentary rocks derived from the Brooks Range to the south. 

The Ellesmerian sequence is composed of 

clastic and carbonate strata that were deposited on a south-facing margin of a stable 

continental landmass. 

KUPARUK RIVER PRUDHOE BAY 

West OIL FIELD OIL FIELD East 

EXPLANATION 

ftll::t) Gas hydrate 

[illS] Free gas ._ M1gration path 

Eocene 

unconformity 

Note: Not to scale 

all six gas-hydrate occurrences is about 1 ,643 km2; the areal 

extent of the individual units ranges from 3 to 404 km2 

(Collett and others, 1988). Porosities calculated from well 

logs and measured from core samples of the gas-hydrate 

reservoir rocks range from 37 to 42 percent, and the average 

degree of gas-hydrate saturation within these reservoirs is 

about 85 percent (Collett and others, 1988). The potential 

volume of gas within the identified gas hydrates (exclusive 

of the associated free gas) of the Prudhoe Bay-Kuparuk 

River area is approximately l.Ox l 0 12 to 1.2x I 0 12 cubic meters, or approximately 37 to 44 trillion cubic feet, of gas at 

standard temperature and pressure (STP). 

Geochemical similarities suggest that oil, and presumably the associated gas, within the Sagavanirktok Formation was "spilled" from the underlying reservoirs in the 

Sadlerochit Group of the Prudhoe Bay field as a consequence of regional tilting d!)ring middle to late Tertiary 

time (Carman and Hardwick, 1983). As shown in figure 7, 

most of the gas hydrates and shallow heavy oils occur either updip from or near the Eileen fault zone. This fault 

zone may have acted as a conduit for free-gas and oil migration from deeper hydrocarbon accumulations. Geochemical analysis of headspace gases evolved from drill cuttings 

collected from seven development wells drilled in the Prudhoe Bay and Kuparuk River oil fields suggests that methane 

is the principal hydrocarbon gas in the near-surface (0 to 

1,500 m) strata (Collett and others, 1990). The plot of the 

carbon (b 13C) and hydrogen (bD) stable isotopic compositions of the methane (fig. 8) from the hydrate-bearing rock 

units indicates that most of the methane is from mixed microbial and thermogenic sources. The natural-gas genetic 

classification diagram in figure 8 also suggests that the microbial gas was generated by biogenic carbon dioxide re-

·11 0 

-100 

-90 

:::J 

i -80 a: 

u.J 

~ -70 u.J 

z 

<t 

J: 

1-

u.J 

::;: -50 (.) 

M 

,... 

vo -40 

-30 

-20 

-1 0 

-400 -350 -300 -250 -200 -150 -100 

liDMETHANE (PERMIL) 

Figure 8. Natural-gas genetic classification diagram (modified 

from Whiticar and others, 1986) depicting the carbon ( 6 13C) and 

hydrogen (liD) stable isotopic compositions (dots) of the methane 

within the hydrate-bearing rock units of two wells drilled in the 

west end of the Prudhoe Bay production unit. MIX indicates mixture of microbial (FERMENTATION and C02 REDUCTION) 

and thermogenic (THERMAL) gases. 

duction of the in-situ organic matter. Vitrinite reflectance 

(R0 ) measurements of about 0.4 percent show that the gashydrate-bearing rocks have never been subjected to temperatures within the thermogenic hydrocarbon window, which 
NATURAL GAS PRODUCTION FROM ARCTIC GAS HYDRATES 305 

ranges from about 0.6 to 2.0 percent. Thus, the thermogenic 

gas must have migrated from greater depths. 

The gas cap of the Prudhoe Bay field is composed primarily of methane (83 to 88 percent) along with small 

quantities of ethane (5 to 7 percent) and propane (I to 2 

percent) (written commun., 1989, M.C. Davidson, BP Exploration, Anchorage, Alaska). If the gas within the nearsurface sediments migrated from deeper structures, the 

shallow gas should have geochemical constituents similar 

to those of the deeper gas; however, no significant amounts 

of ethane or propane were detected within the interval of 

gas-hydrate stability. The depletion of heavier hydrocarbons such as ethane and propane from gas mixtures by 

stripping during migration has been suggested by Schoell 

(1983) and Jenden and Kaplan (1986) to explain natural 

gases containing thermogenic methane but only minor 

amounts of heavier hydrocarbons. The thermogenic component of the gas within the interval of gas-hydrate stability may have been stripped of most of its heavier 

hydrocarbons. Such a process could account for the molecular and isotopic compositions observed. 

The carbon isotopic composition of the methane (613C) 

within the gas-hydrate-bearing rock units averages approximately -49 permil, suggesting that the hydrates contain a 

mixture of thermogenic and microbial gases. By comparing 

the methane carbon isotopic composition (613C) of this apparent gas mixture to the isotopic composition of the Prudhoe Bay gas cap it is possible to calculate the relative 

volume of gas from thermogenic versus microbial sources 

within the hydrate stability field. The methane-carbon isotopic value (613C) of the Prudhoe Bay gas cap averages 

approximately -39 permil (written commun., 1989, M.C. 

Davidson, BP Exploration, Anchorage, Alaska). The methane component from a microbial source likely had an original methane isotopic composition ranging from -60 to -70 

permil. Because the mixing of two gases results in a linear 

and proportional change in isotopic composition (Schoell, 

1983), it is estimated that about 50 to 70 percent of the 

methane within the hydrate stability field has migrated from 

the Prudhoe Bay gas cap. Thus, the occurrence of gas hydrates is controlled by the availability of a significant quantity of migrated thermogenic hydrocarbon gas. 

To describe the history of gas-hydrate formation, I 

have modified a generalized cross section (fig. 7) from 

Carman and Hardwick (1983, fig. 4). As thermogenic gas 

moved up the Eileen fault zone, some of the gas may have 

been rechanneled updip along relatively porous and permeable northeast-dipping sandstone units of the Sagavanirktok Formation. The updip-migrating gas probably 

mixed with the in-situ microbial methane and collected in 

structural or stratigraphic traps where subsequent temperature changes deepened the permafrost sequence and converted the trapped gas into gas hydrate. Conversely, the 

updip migrating gas may have been cpnverted to gas hydrate upon entering the pressure-temperature regime of 

gas-hydrate stability, thus forming its own trap. Because 

·so little is known about the history of temperatures on the 

. North Slope and the presence of traps for free gas in this 

area, either of these models is plausible. 

Thermal conditions conducive to the formation of gas 

hydrates have probably persisted in northern Alaska since 

the end of the Pliocene (about 1.65 Ma); however, regional temperature fluctuations throughout the Pleistocene 

(about 1.65 to 0.01 Ma) have been great enough to repeatedly thicken and thin the zone of gas-hydrate stability 

(Collett and others, 1988). At this time adequate knowledge of climate and geologic changes on the time scale 

necessary to accurately assess the history of gas-hydrate 

formation in northern Alaska is not available; however, it 

is safe to say that the North Slope gas hydrates are likely 

no older than Pleistocene, and they could be as young as 

late Pleistocene (Wisconsin Stage; about 0.07 to 0.01 Ma). 

MESSOYAKHA GAS-HYDRATE 

ACCUMULATIONS 

The Messoyakha gas field was discovered in 1968, and 

it was the first producing field in the northern part of ·the 

West Siberian basin (fig. 1 ). By the mid-1980's, more than 

66 gas fields had been discovered in the West Siberian 

basin, containing an estimated total gas reserve of 22 trillion cubic meters (777 trillion cubic feet)-approximately 

one-third of the world's reserves (Grace and Hart, 1986). 

Between 1969 and 1987 about 14.4 billion cubic meters 

(508 billion cubic feet) of gas were produced from the 

Messoyakha field and delivered by pipeline to the city of 

Noril'sk (Makogon, 1988). The geology (fig. 9) and petroleum geochemistry of the West Siberian basin is described 

in detail in many English language publications (Kortsenshteyn, 1970; Makogon and others, 1972; Alekseyev, 1974; 

Trofimuk and others, 1977; Kruglikov and others, 1983; 

Krason and Ciesnik, 1985; Grace and Hart, 1986; Galimov, 

1988; Makogon, 1988; and Peterson and Clarke, 1989). 

Production in the northern part of the West Siberian basin 

is principally from the Neocomian reservoirs of the Vartov 

and Megion suites (average depth, 2,800 m) and the Cenomanian reservoirs of the Pokur suite (average depth, 1,100 

m); about two-thirds of the region's gas production is from 

the Cenomanian reservoirs (Grace and Hart, 1986). The 

Pokur suite is a 700- to 800-m-thick complex of interbedded marine and nonmarine sandstone and shale that was 

deposited during an Aptian to Coniacian marine regression. 

Coal and plant debris are also prevalent within the nonmarine parts of the Pokur suite. The Pokur suite is overlain by 

the shale sequence of the Kuznetsov suite, which forms a 

regional seal for most of the gas in the underlying sandstone reservoirs. Regional analyses of subsurface temperatures, formation pressures, and pore-water salinities 

suggest that the methane-hydrate stability zone may extend 
306 THE FUTURE OF ENERGY GASES 

E VI Q) Q) 

(i) ·~ Stage Grace and Hart (1986) >. 

(/) (/) 

Overlying beds Tibeysalin suite 

ITertiarv\ 

Maestrichtian 

Gankin suite 

Campanian 

Oi Santonian 

0.. Kuznetsov suite 0.. 

::> Coniacian 

(/) Turonian ::> 

0 

w 

u Cenomanian 

<t: 

1- Pokur suite w 

a: 

u 

Albian 

Oi 

~ 

0 

...J 

Aptian Vartov suite 

Barremian 

c Hauterivian co .E 

0 Valanginian Megion suite (.) 

0 

Q) 

z Berriasian 

Underlying beds Bazhenov suite 

(Jurassic) 

Figure 9. Stratigraphic column for northern West 

Siberian basin (modified from Grace and Hart, 

1986). 

ARCTIC ocEAN 

SCALE UNKNOWN 

Figure 10. Depth (in meters) to base of methane-hydrate stability 

field in continental areas of Russia. Dashed line is southern 

boundary of former U.S.S.R. Modified from Makogon (1981). 

to depths of approximately I ,000. m in the northern part of 

the West Siberian basin (fig. I 0). The Messoyakha gas accumulation is confined to the Dolgan Formation of the 

Pokur suite, and production has been established from the 

depth interval between 720 and 820 m. The upper part 

(about 40 m) of the Messoyakha field lies within the zone 

of predicted methane-hydrate stability (fig. II). By assuming a reservoir pressure of 78 kg/cm2, Makogon and others 

(I972) determined that the 10°C isotherm defines the lower 

limit of the in-situ gas hydrates, thus separating the Messoyakha field into an upper gas-hydrate accumulation and a 

lower free-gas accumulation (fig. 12). 

Unusually low gas yields from production tests in the 

upper part of the Messoyakha reservoir were the first 

physical evidence of possible in-situ gas-hydrate occurrences (production data discussed in more detail later in 

this paper). Analysis of spontaneous-potential, caliper, and 

gamma-ray well logs from 62 wells drilled in the Messoyakha field reveal the presence of apparently "frozen" rock 

intervals within the Dolgan Formation (Makogon and others, 1972). Because these "frozen" layers are more than 

250 to 350 m below the zone of permafrost and are at 

equilibrium formation temperatures near l0°C, they have 

0 

Methane-hydrate 

200 stability curve 

Base of (/) 

a: 

w 

1-

w 

::2: 

~ 400 

::i 

1-

0.. 

w 

D gradient 

600 

800 

·8 ·4 0 4 8 12 

TEMPERATURE, IN DEGREES CELSIUS 

Figure 11. Phase diagram illustrating depth-temperature zone in 

which methane hydrates are stable in the area of the Messoyakha 

field of the West Siberian basin (modified from Sloan, 1990). 
NATURAL GAS PRODUCTION FROM ARCTIC GAS HYDRATES 307 

been interpreted to contain in-situ gas hydrates rather than 

ice. Further analysis of electrical-resistivity well logs also 

indicates the presence of gas hydrates in the upper part of 

the Messoyakha gas accumulation (Makogon, 1981 ). The 

gas-hydrate and free-gas parts of the Messoyakha field are 

depicted in the generalized cross section in figure 12. The 

detailed cross sections in figure 13 (Makogon and others, 

1972; fig. 3) reveal that the well-Jog-inferred gas hydrates 

occur within a series of discrete, laterally continuous sandstone sequences that are separated by interbedded shales 

and siltstones. The Messoyakha structure as described by 

Makogon and others (1972) is a dome having dimensions 

~ 700 

'"' .... 

'"'750 

~ 

z 

...... 

:c 800 

t 

~ 

109 

WELLS 

121 150 

FREE GAS 

WATER ZONE 

142 7 

850~--------------------------------~ 

Figure 12. Generalized cross section illustrating the distribution 

of the gas-hydrate and free-gas parts of the Messoyakha field 

(modified from Makogon, 1988). 

690 

730 

(f) 770 

cr: 

w 810 Iw 

~ 

z 

I 

I0... 690 

w 

0 

730 

770 

810 

121 109 

WELLS 

151 135 

150 

of 12.5 by 19 km (fig. 14). Studies of cores, well cuttings, 

and well logs show that in the free-gas part of the Messoyakha field the Dolgan Formation is characterized by 

porosities ranging from 16 to 38 percent; permeabilities 

average about 125 millidarcies. Water saturations in the 

Dolgan Formation are reported to average about 40 percent (Makogon and others, 1972). Prior to production, the 

calculated total gas reserves within the gas-hydrate and 

free-gas parts of the Messoyakha accumulation were estimated to be about 80x 1 o9 cubic meters (2.8 trillion cubic 

feet), with about one-third of the reserves within the gas 

hydrates (Krason and Ciesnik, 1985). 

The Cenomanian reservoirs of the Pokur suite in northern West Siberia contain mostly methane (92.5 to 99 percent), the source of which is a matter of controversy 

(reviewed by Grace and Hart, 1986). Elemental and isotopic compositions of the hydrocarbon gases within the West 

Siberian basin are available from several sources, including 

Yermakov and others (1970), Alekseyev (1974), and Galimov ( 1988). Most of the published isotopic data are limited 

to only stable methane carbon compositions. Additional 

isotopic data are required to accurately ascertain the source 

of a gas. However, by assuming that a gas with a stable 

methane-carbon isotopic composition of -50 permil and 

heavier is thermally generated and that an isotopic composition of -60 permil or lighter is indicative of methane from 

a microbial source (isotopic ranges from Schoell, 1983), it 

130 131 

135 142 

Gas hydrate in EJ . sandstone 

- Free gas in 

sandstone 

~ Shale 

•• Base of hydrate 

•• stability field 

HORIZONTAL 

SCALE UNKNOWN 

Figure 13. Multi-well cross sections showing the lateral and vertical extent of gas hydrates and underlying free gas in the 

Messoyakha field (modified from Makogon and others, 1972). Specific location of cross sections and horizontal scale are unknown. 
308 THE FUTURE OF ENERGY GASES 

EXPLANATION 

··· Gas-hydrate/free-gas contact 

-....... Depth, in meters, to top of 

Dolgan Formation 

• Well 

SCALE UNKNOWN 

Figure 14. Structure map of the top of the gas-hydrate-bearing 

Dolgan Formation in the Messoyakha field (modified from Krason and Ciesnik, 1985). 

is possible to approximate the source of a gas. Due .to the 

arbitrary nature of these analytical boundaries, I have defined an isotopic transitional or mixing zone (values ranging from -65 to -45 permil) between the thermogenic and 

microbial end-members. The reported stable carbon isotopic compositions (o 13C) of the methane within the Neocomian reservoirs of the West Siberian basin range from -48 to 

-38 permil (Messoyakha values range from -44.2 to -38.5 

permil), which are indicative of gases generated by mostly 

thermogenic processes. The Cenomanian reservoirs, however, contain methane with a stable carbon isotopic composition ranging from -68 to -41 permil (Messoyakha values 

range from -48.0 to -41.0 permil) (reviewed by Grace and 

Hart, 1986), which falls mostly within the transitional or 

mixing zone between the thermogenic and microbial endmember gases. The Messoyakha Cenomanian reservoirs, 

therefore, may contain gas that was formed by either microbial or thermogenic processes. The thermogenic gas component within the near-surface ( <900 m) Cenomanian 

reservoirs of the Messoyakha field may have migrated from 

the deeper (about 2,600 m) Neocomian reservoirs or directly from Jurassic hydrocarbon source rocks. Kruglikov and 

others ( 1983) conclude from studies of argon isotopic data 

from the West Siberian basin that both deep (thermogenic) 

and shallow (microbial) sources have contributed to the Cenomanian reservoirs. Galimov (1988), however, has suggested that the methane within the Cenomanian reservoirs 

may have been generated in situ by early-stage (low-temperature) geochemical transformation of terrestrial organic 

matter. His geochemical model suggests that the humic organic matter in the Cenomanian sedimentary deposits has a 

high methane-generation capacity at relatively low maturities and that the observed stable methane-carbon isotopic 

compositions indicate this low-temperature alteration. 

Some fraction of the methane in the hydrates of the Messoyakha field is probably from the microbial alteration of 

in-situ organic matter in the Cenomanian sediments; however, there is evidence that some methane has migrated 

from deep thermogenic sources. Most certainly, additional 

geochemical data are required to fully assess the source of 

the gas within the Cenomanian reservoirs of the West Siberian basin. 

Several authors (Kortsenshteyn, 1970; Trofimuk and 

others, 1977; and DuRochet, 1980) suggest that conditions 

conducive to the formation of permafrost and gas hydrates 

have persisted in the northern part of the West Siberian 

basin since the early Pleistocene (about 1.65 Ma). Russian 

geologists generally conclude that pre-existing free-gas accumulations were converted to gas hydrates during Pleistocene glacial advances and that the gas-hydrate pools were 

transformed back into free-gas accumulations during subsequent interglacial periods. The present-day Messoyakha 

field is in transition from a gas-hydrate to a free-gas accumulation and it has not completely converted back to its 

preglacial free-gas state. 

MESSOYAKHA PRODUCTION HISTORY 

Production tests in the early development history of the 

Messoyakha field yielded highly variable results (table 2). 

Measured flow rates from the free-gas part of the reservoir 

were substantially greater than those from the gas hydrates. 

To confirm the presence of gas hydrates within the upper 

part of the Messoyakha field, a series of hydrate-inhibitor 

injection tests were conducted (table 3). During these tests, 

substances, such as methanol and calcium chloride, which 

destabilize and prevent the formation of gas hydrates, were 

injected into the suspected gas-hydrate-bearing rock units. 

Table 2. Production-test data from the Messoyakha field, West 

Siberia (Makogon, 1981) 

Well No. 

121 

109 

150 

195 

131 

Distance above(-) or below 

Depth of tested (+)the gas-hydrate/free-gas 

interval (m) contact (m) 

716-727 --64 

748-794 -6 

741-793 +6 

779-795 +29 

771-793 +59 

Gas flow 

(1,000 m3/day) 

26 

133 

413 

626 

1,000 
NATURAL GAS PRODUCTION FROM ARCTIC GAS HYDRATES 309 

Table 3. Production results from gas-hydrate-inhibitor injection 

test in the Messoyakha field, West Siberia (from Sumetz, 1974, 

and Makogon, 1981) 

Gas flow before Gas flow after 

Well No. Type of inhibitor treatment treatment 

(1,000 m3/day) (1,000 m3/day) 

129 Methanol----------------- 30 150 

131 Methanol----------------- 175 275 

133 Methanol----------------- 25 50 

50 100 

100 150 

150 200 

200 250 

138 Methanol and CaCI2 --- 200 300 

139 Methanol and CaCI2 --- 120 180 

141 Methanol and CaCI2 --- 150 200 

142 Methanol----------------- 5 50 

10 100 

25 150 

50 200 

Most of these tests (summarized by Sumetz, 1974, and Makogon, 1981) resulted in dramatic increases in production 

rates, which was attributed to the dissociation of the in-situ 

gas hydrates. 

Long-term production from the gas-hydrate part of the 

Messoyakha field has been achieved by a simple depressurization scheme. The reservoir-pressure and production 

history of the Messoyakha field are depicted in figure 15. 

As production began in 1969, the reservoir-pressure decline curve followed the predicted path; however, in 1971 

the measured reservoir pressures began to deviate from the 

8 

"' 0.. 6 

6 

w 

a: 

:::> 

(/) 

(/) 

w 

a: 4 0.. 

2 

1970 

II 1111 I IV 

.--- Measured reservoir pressure 

1975 1980 

YEAR 

v 

1985 

C> 

0 

2 ~ C) 

0 

w 

(.) 

:::> 

0 

1 0 

a: 

0.. 

Figure 15. A plot of reservoir pressures and production history 

as a function of time for the Messoyakha field (modified from 

Makogon, 1988). The roman numerals across the top of the figure denote the stages of production discussed in the text. MPa, 

megapascal. 

predicted values. This deviation has been attributed to the 

liberation of free gas from dissociating gas hydrates. The 

17 -yr production history of the Messoyakha field has been 

divided into five stages (fig. 15): 

Stage I. From 1969 to 1971, the reservoir pressure did 

not fall below gas-hydrate stability conditions and gas production was only from the deeper free-gas part of the field. 

Stage II. From 1971 to 1975, the actual reservoir pressures exceeded predicted reservoir pressures. This departure marked the start of gas-hydrate dissociation and gas 

production from the gas-hydrate part of the field. 

Stage III. From 1976 to 1977, the volume of gas withdrawn from the reservoir was equal to the amount of gas 

liberated from the dissociating gas hydrates. 

Stage N From 1978 to 1981, production from the 

Messoyakha field was reduced and eventually halted. The 

reservoir pressures began to rise as the gas hydrates continued to dissociate. 

Stage V. Since 1982 there has been only modest production from the Messoyakha field. During this period the 

amount of gas liberated from the hydrates has been equal 

to the amount of gas produced. 

Throughout the production history of the Messoyakha 

field, the depth of the gas-water contact has not changed, 

and it is estimated that about 36 percent (about 5.17x109 

cubic meters or about 183 billion cubic feet) of the gas 

withdrawn from the field has come from the gas hydrates 

(Makogon, 1988). For more information on gas-hydrate 

production methods, see Yousif and others (1988) and 

Sloan (1990). 

POTENTIAL PRODUCTION FROM THE 

PRUDHOE BAY-KUPARUK RIVER 

GAS-HYDRATE ACCUMULATION 

Production data from the Prudhoe Bay-Kuparuk River 

gas-hydrate accumulation are limited to a single drill-stem 

test of the cored gas-hydrate interval of the N.W. Eileen 

State No. 2 welL The maximum gas-flow rate from the 

N.W. Eileen State No.2 well of 112 cubic meters per day is 

similar to the production rates reported by Makogon ( 1981) 

for the untreated gas-hydrate intervals in the Messoyakha 

field (table 2). Other similarities between the Messoyakha 

and the Prudhoe Bay-Kuparuk River gas-hydrate accumulations suggest that the production history of the Messoyakha 

field may be used as an analog to predict the production 

potential of the Alaskan gas hydrates. For example, both 

the Messoyakha and the Prudhoe Bay-Kuparuk River gashydrate accumulations are in a series of friable sandstone 

reservoirs that are characterized by high porosities and low 

water saturations. Geochemical analyses suggest that the 

gas hydrates of the Messoyakha and Prudhoe Bay-Kuparuk 

River fields are almost identical in composition, and they 

have been interpreted to contain a mixture of thermogenic 
310 THE FUTURE OF ENERGY GASES 

methane that migrated from deep, mature sources and insitu, microbial methane. These similarities suggest that the 

origin of both accumulations may be similar. The presence 

of a significant volume of free gas trapped below both the 

Messoyakha and the Prudhoe Bay-Kuparuk River gashydrate accumulations is most important when considering 

the potential production characteristics of [he gas hydrates 

in Alaska. Use of the gas-hydrate-depressurization method 

of production requires that a portion of the accumulation be 

in a free-gas state. Therefore, the presence of free gas 

below the Prudhoe Bay-Kuparuk River gas hydrates suggests that the depressurization production method used in 

the Messoyakha field may work in northern Alaska. The 

most striking difference between the Messoyakha and the 

Prudhoe Bay-Kuparuk River gas-hydrate/free-gas accumulations is their size. The total mapped area of all six gashydrate occurrences in the Prudhoe Bay-Kuparuk River 

area is about 1,643 km2

, whereas the Messoyakha field 

covers an area of only about 238 km2. This difference in 

field size accounts for the vast difference between the estimated gas reserves in the Messoyakha gas-hydrate/free-gas 

accumulation (80x!09 cubic meters; 2.8 trillion cubic feet) 

and those in the Prudhoe Bay-Kuparuk River gas-hydrate 

accumulation (1.2xl012 cubic meters; 44 trillion cubic 

feet). This difference suggests that the ultimate production 

capacity of the Prudhoe Bay-Kuparuk River gas-hydrate 

accumulation may be much greater than the historical production from the Messoyakha field. 

CONCLUSIONS 

The production history of the Messoyakha field in West 

Siberia has demonstrated that gas hydrates are an immediate producible source of natural gas and that production can 

be started and maintained by conventional methods. The 

geologic comparison of the Messoyakha and Prudhoe BayKuparuk River gas-hydrate accumulations suggests that the 

Alaskan gas hydrates may also be a producible source of 

natural gas. The gas hydrates of the Prudhoe Bay-Kuparuk 

River area are estimated to contain approximately 1.0 to 1.2 

trillion cubic meters of gas, which is about fifteen times 

greater than the estimated gas reserves in the Messoyakha 

field. This estimate indicates that the gas hydrates of northern Alaska may be an important source of natural gas in the 

near future. 

ACKNOWLEDGMENTS 

This study was funded by the U.S. Department of Energy (interagency agreement No. DE-AI21-83MC20422) 

and the U.S. Geological Survey Climate Change Program. 

REFERENCES CITED 

Alekseyev, F.A., 1974, Zonality in oil and gas formation in the 

earth's crust based on isotopic studies: Geologiya Nefti i 

Gaza, April, p. 62-67: [English] Journal of Petroleum Geology, v. 12, p. 191-192. 

Bily, C., and Dick, J.W.L., 1974, Natural gas hydrates in the 

Mackenzie Delta, Northwest Territories: Bulletin of Canadian Petroleum Geology, v. 22, no. 3, p. 340-352. 

Carman, G.J., and Hardwick, Peter, 1983, Geology and regional 

setting of the Kuparuk oil field, Alaska: American Association of Petroleum Geologists Bulletin, v. 67, no. 6, p. 1014-

1031. 

Cherskiy, N.V., Tsarev, V.P., and Nikitin, S.P., 1985, Investigation 

and prediction of conditions of accumulation of gas resources in gas-hydrate pools: Petroleum Geology, v. 21, p. 65-89. 

Collett, T.S., 1983, Detection and evaluation of natural gas hydrates from well logs, Prudhoe Bay, Alaska, Proceedings of 

the Fourth International Conference on Permafrost, Fairbanks, Alaska: Washington, D.C., National Academy of Sciences, p. 169-174. 

Collett, T.S., Bird, K.J., Kvenvolden, K.A., and Magoon, L.B., 

1988, Geologic interrelations relative to gas hydrates within 

the North Slope of Alaska: U.S. Geological Survey OpenFile Report 88-389, 150 p. 

Collett, T.S., Kvenvolden, K.A., and Magoon, L.B., 1990, Characterization of hydrocarbon gas within the stratigraphic interval of gas-hydrate stability on the North Slope of Alaska: 

Applied Geochemistry, v. 5, p. 279-287. 

Du Rochet, J., 1980, Une explication paleoclimatique des grands 

gisments superficiels de gaz sec du norde de Ia Siberie Occidentale (A paleoclimatic explanation for the shallow giant 

gas reserves of northern West Siberia): Bulletin des Centres 

de Recherches Exploration-Production Elf-Aquitains, v. 4, 

p. 119-142. 

Galimov, E.M., 1988, Sources and mechanisms of formation of 

gaseous hydrocarbons in sedimentary rocks: Chemical Geology, v. 71, p. 77-95. 

Grace, J.D., and Hart, G.F., 1986, Giant gas fields of northern 

West Siberia: American Association of Petroleum Geologists 

Bulletin, v. 70, no. 7, p. 830-852. 

Jenden, P.O., and Kaplan, I.R., 1986, Comparison of microbial 

gases from the Middle American Trench and Scripps Submarine Canyon-Implications for the origin of natural gas: 

Applied Geochemistry, v. 1, p. 631-646. 

Judge, A.S., 1988, Mapping the distribution and properties of 

natural gas hydrates in Canada: Proceedings of the American 

Chemical Society Third Chemical Congress of the North 

American Continent, June 6-7, Toronto, Ontario, Abstract 

Number 29. 

Kortsenshteyn, V.N., 1970, Effect of periodic glaciations on the 

formation of the enormously large gas fields in the northern 

part of the Tyumen Oblast: Akaderniya Nauk SSSR Doklady, 

v. 19l,p. 1366-1369. 

Krason, J., and Ciesnik, M., 1985, Geological evolution and 

analysis of confirmed or suspected gas hydrate localities, 

Volume 5-Gas hydrates in the Russian literature: Report 

for U.S. Department of Energy, Office of Fossil Energy, 
NATURAL GAS PRODUCTION FROM ARCTIC GAS HYDRATES 311 

Morgantown Energy Technology Center, Morgantown, West 

Virginia, Contract No. DE-AC21-84MC21181, 164 p. 

Kruglikov, N.M., Prasolov, E.M., Yakov1ev, O.N., 1983, Gidrogeologicheskaya sostav1yayuchaya prognoza neftegazonosnosti: All Union Scientific-Research Institute for Geologic 

Exploration, p. 4-27: [English] Journal of Petroleum Geology, v. 20,p.481-485. 

Kvenvolden, K.A., 1988, Methane hydrate-A major reservoir of 

carbon in the shallow geosphere?: Chemical Geology, v. 71, 

p.41-51. 

Kvenvolden, K.A., and McMenamin, M.A., 1980, Hydrates of 

natural gas-A review of their geologic occurrences: U.S. 

Geological Survey Circular 825, 11 p. 

Makogon, Y.F., 1981, Hydrates of natural gas: Tulsa, Okla., Penn 

Well Publishing, 237 p. 

---1988, Natural gas hydrates-The state of study in the 

USSR and perspectives for its use: Paper presented at the 

Third Chemical Congress of North America, Toronto, Canada, June 5-10, 18 p. 

Makogon, Y.F., Trebin, F.A., Trofimuk, A.A., Tsarev, V.P., and 

Cherskiy, N.V., 1972, Detection of a pool of natural gas in a 

solid (hydrate gas) state: Doklady Academy of Sciences 

U.S.S.R., Earth Science Section, v. 196, p. 197-200. 

Peterson, J.A., and Clarke, J.W., 1989, West Siberian oil-gas province: U.S. Geological Survey Open-File Report 89-192, 142 p. 

Potential Gas Committee, 1981, Potential supply of natural gas in 

the United States (as of December 31, 1980): Potential Gas 

Agency, Colorado School of Mines, Golden, Colo., 199 p. 

Schoell, Martin, 1983, Genetic characterization of natural gases: 

American Association of Petroleum Geologists Bulletin, 

v.67, no. 12,p. 2225-2238. 

Sloan, E.D., 1990, Clathrate hydrates of natural gases: New 

York, Marcel Dekker, 641 p. 

Sumetz, V.I., 1974, Prevention of hydrate formation in gas wells 

zone: Gazovaya Promishlennost, v. 2, p. 24-26. 

Trofimuk, A.A., Cherskiy, N.Y., and Tsaryov, V.P., 1977, The role 

of continental glaciation and hydrate formation on petroleum 

occurrence, in Meyer, R.F., ed., The future supply of naturemade petroleum and gas: New York, Pergamon Press, 

p. 919-926. 

Werner, M.R., 1987, Tertiary and Upper Cretaceous heavy oil 

sands, Kuparuk River area, Alaskan North Slope, in Tailleur, 

I.L., and Weimer, Paul, eds., Alaskan North Slope geology: 

Bakersfield, California, Pacific Section, Society of Economic 

Paleontologists and Mineralogists and the Alaska Geological 

Society, Book 50, v. 1, p. 109-118. 

Whiticar, M.J., Faber, E., and Schoell, M., 1986, Biogenic 

methane formation in marine and freshwater environments; 

C02 reduction vs. acetate fermentation-Isotopic evidence: Geochimica et Cosmochimica Acta, v. 50, p. 693-

709. 

Yermakov, V.I., Lebedev, V.S., Nemchenko, N.N., Rovenskaya, 

A.S., and Grachev, A.V., 1970, Isotopic composition of carbon in natural gases in the northern part of the West Siberian Plain in relation to their origin: Akademiya Nauk SSSR 

Doklady, v. 190, p. 683-686. 

Yousif, M.H., Abass, H.H., Selim, M.S., and Sloan, E.D., 1988, 

Experimental and theoretical investigation of methane gas 

hydrate dissociation in porous media: Proceedings of the 

63rd Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, October 2-5, Houston, Tex., 

p. 571-583. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Gas Hydrates on the Atlantic Continental Margin of the 

United States-Controls on Concentration 

By William P. Dillon1, Myung W. Lee2, Kristen Fehlhaber1

, and Dwight F. Coleman1 

CONTENTS 

Abstract ......................................................................... 313 

Introduction .. ... .. ..... .... ... .. ... .... .... ... . ... . ... ... .. . .. .. .. . . .. . . ... . . . 313 

Detecting Hydrates ....................................................... 314 

Distribution of Gas Hydrate on the U.S. Atlantic 

Continental Margin ....................................................... 315 

Volume of Gas Hydrate ......................................... 315 

Thickness of the Zone of Hydrate Stability .......... 318 

Geological Controls on Gas Hydrate Distribution ....... 318 

Sediment Deposition .............................................. 318 

Faulting and Diapirism .......................................... 320 

Mass Movement ..................................................... 323 

Gas Traps ...................................................................... 326 

Summary and Conclusions ........................................... 328 

Acknowledgments ........................................................ 329 

References Cited ........................................................... 329 

ABSTRACT 

Large volumes of gas hydrates exist within oceanfloor deposits at water depths exceeding about 300 to 500 

m. They cement a surface layer of sediments as much as 

about 1 ,000 m thick, limited at its base by increasing temperature. Gas hydrates are identified by drilled samples 

and by their characteristic responses in seismic reflection 

profiles. These seismic responses include, at the base of 

1

U.S. Geoiogical Survey, Bldg. B, Quissett Campus, Woods Hole, 

MA02543. 2U.S. Geological Survey, Federal Center, P.O. Box 25046, MS 960, 

Denver, CO 80225. 

the hydrate-cemented surface layer, a marked velocity decrease and a sea-floor-paralleling reflection (known as the 

bottom-simulating reflection, or BSR) and, within the hydrate-cemented layer, a reduction in amplitude of seismic 

reflections (known as blanking), which is apparently 

caused by cementation of strata. By using seismic-reflection data we have mapped the volume of hydrate and 

thickness of the hydrate-cemented layer off the U.S. East 

Coast. Concentrations of gas hydrate are located at sites of 

present or past rapid deposition of sediments and at a linear group of diapirs and associated faults. The sources of 

gas at these concentrations are probably bacterial generation of methane at the locations of rapid deposition, and 

possibly the migration of deep, thermogenic gas up faults 

near diapirs. The thickness of the gas-hydrate layer decreases markedly at landslide scars, possibly due to breakdown of hydrate resulting from pressure reduction caused 

by removal of sediment by the slide. Gas traps appear to 

exist where a seal is formed by the gas-hydrate-cemented 

layer. Such traps are observed (1) where the sea floor 

forms a dome, and therefore the bottom-paralleling, hydrate-cemented layer also forms a dome; (2) above diapirs, 

where the greater thermal conductivity of salt creates a 

warm spot and salt ions act as antifreeze, both effects resulting in a local shallowing of the base of the hydrate; 

and (3) at locations where strata dip relative to the sea 

floor, and the updip regions of porous strata are sealed by 

the gas-hydrate-cemented layer to form a trap. In such situations the gas in the hydrate-sealed trap, as well as the 

gas that forms the hydrate, may become a resource. 

INTRODUCTION 

Natural-gas hydrates are stable at the temperature and 

pressure conditions that exist near and just beneath the sea 

313 
314 THE FUTURE OF ENERGY GASES 

floor almost everywhere in the world's oceans where water 

depths exceed 300 to 500 m (Kvenvolden, this volume). 

Hydrates in this setting probably contain very large quantities of methane (Kvenvolden, 1988). Furthermore, hydrates seem to have the capacity to fill sediment pore 

space and reduce permeability, so that hydrate-cemented 

sediments act as seals for gas traps. Thus, there are two 

ways in which hydrates can create deposits of energy 

gases (primarily methane, but other hydrocarbon gases as 

well): (1) by binding gas into hydrates within sediments 

and (2) by creating a trap, using hydrate-cemented sediments as the seal. 

Where are the ice-like hydrates located in the marine 

setting? Temperature and pressure conditions are appropriate in deep-ocean water, but hydrates do not exist there 

because methane saturation generally does not exist. Furthermore, if hydrate did form in the water, it would float 

upward into warmer water and melt. Gas hydrates do exist 

within sea-floor sediments because the hydrate is trapped 

in intergranular pores and because gas is available, either 

biogenic gas produced by bacteria or thermogenic gas rising from deeper strata. Temperature increases downward 

through the sediments along the geothermal gradient, and 

although pressure also increases (which tends to make hydrate more stable), the conditions eventually become too 

hot for hydrate to exist. Because the thermal gradient is 

fairly constant within a restricted region, this stability limit 

will be reached at approximately the same subbottom 

depth everywhere in the region. The result is a zone of 

hydrate-cemented sediment that extends down from the sea 

floor and that is of fairly uniform thickness, commonly 

several hundred meters. Our work has focused on these 

questions: Where is the hydrate located? How much hydrate exists? What geological factors control its presence? 

We have concentrated our studies on the U.S. Atlantic continental margin. 

DETECTING HYDRATES 

How do we locate and map hydrate-cemented sediment in the deep sea? Although hydrates have been recognized in drilled cores, their presence over large areas can 

be detected much more efficiently by acoustical methods, 

using seismic-reflection profiles (Tucholke and others, 

1977; Shipley and others, 1979; Dillon and Paull, 1983; 

Collins and Watkins, 1985; Miller and others, 1991; Rowe 

and Gettrust, 1993). Hydrate has a very strong effect on 

acoustic reflections because it has a very high acoustic velocity (-3.3 km/s-about twice that of sea-floor sediments; 

Sloan, 1990), and thus cementation of grains by hydrates 

produces a high-velocity deposit due to the mixing of hydrate with the sediment. Sediments below the hydrate 

zone, if water saturated; have lower velocities (acoustic velocity of water is -1.5 km/s), and if gas is trapped in the 

sediments below the hydrate, the velocity is much lower 

(even with just a few percent of gas; Brandt, 1960). Because reflection strength is proportional to the change of 

acoustic impedance, which is the product of velocity times 

density, the base of the hydrate-cemented zone produces a 

strong reflection. The reflection is also sharply defined, because the phase boundary is a distinct, not diffuse, limit to 

hydrate occurrence. The top of hydrate within the sediments has no such precisely defined boundary, so it does 

not produce a sharp reflection. As noted above, the base of 

hydrate stability occurs at an approximately uniform subbottom depth throughout a small area, and therefore the 

reflection from its base roughly parallels the sea floor. The 

reflection has become known as the bottom-simulating reflection or BSR; the BSR is characteristic of hydrate-bearing sediments. A very strong BSR is shown in figure 1. 

Note how it approximately parallels the sea floor, which 

·dips to the right, and cuts through reflections from sedimentary strata, which dip slightly to the left. The coincidence in depth of the BSR to the theoretical, extrapolated 

pressure and temperature conditions that define the hydrate 

phase boundary and the sampling of hydrate above BSR's 

give confidence that this seismic indication of hydrates is 

dependable (Kvenvolden and Barnard, 1982, 1983; Shipley 

and Didyk, 1982; K venvolden and Kastner, 1990). 

A second significant seismic characteristic of hydratecementation, called blanking, is also well displayed in figure 1; blanking is the reduction of the amplitude of seismic reflections caused by hydrate cementation. The 

amplitudes of reflections (shown by the excursions of the 

filled wiggle traces) are much smaller above the BSR, 

where sediments are cemented by gas hydrates, than they 

are below the BSR. This phenomenon consistently appears 

in sediments containing gas hydrates, indicating that the 

changes in acoustic impedance between the strata are 

much reduced by hydrate cementation. A third characteristic of gas hydrates in a near-bottom layer of sediment is 

the abrupt velocity decrease at the BSR caused by moving 

from hydrate-cemented sediments above to noncemented 

sediments below that are water- or even gas-filled. This 

downward velocity decrease, known as an "inversion", is 

detected with some seismic techniques; for example, see 

Lee and others (this volume). 

The three manifestations of hydrates in sea-floor sediments noted above (BSR, blanking, and velocity inversion) have all been used to recognize gas hydrates in 

seismic profiles on the U.S. Atlantic continental margin 

(Tucholke and others, 1977; Shipley and others, 1979; Dillon and others, 1980; Paull and Dillon, 1981; Krason and 

Ridley, 1985). The BSR and velocity inversion are related 

just to the bottom boundary of the hydrate zone. The 

blanking effect, however, occurs across the entire hydratecemented zone and can be quantified and mapped to estimate the amount of gas hydrate that is present (Lee and 

others, this volume; Lee and others, 1992; Lee and others, 
GAS HYDRATES ON THE ATLANTIC CONTINENTAL MARGIN OF THE UNITED STATES 315 

in press). We calculated the amount of hydrate in the most 

intensively blanked sediments by using known hydrate velocity from published laboratory studies, velocities that we 

determined for sea-floor sediments from multichannel seismic profiles, and porosity in our study area determined in 

scientific drilling. We assume that such a material is an 

end member, and in our computed seismic model, we 

mathematically "mix" it with a similar deposit having no 

hydrate, in order to model the range of possible blanking 

effects. The effect on reflection amplitudes of various mixtures of end-member, hydrate-cemented sediment with hydrate-free sediment is shown in figure 2. The increase of 

blanking with increase of hydrate is apparent. Three classes of blanking have been assigned; the boundaries between classes represent a change in the power of 

reflections by a factor of two. The class boundaries are 

indicated on figure 2, and these classes can be related to 

overall average amounts of hydrate in bulk sediment of 

approximately 7 percent (class 3), 12 percent (class 2), 

and 15 percent (class I) in this example. To recognize 

classes in a profile, we determine and plot the amount of 

blanking (the reduction in reflection amplitude) along the 

profile in a subbottom window within the hydrate zone 

(0.25 to 0.5 s (two-way traveltime) below the sea floor); 

an example is shown in figure 3. These measured values 

are used as a calibration, and the extent of the three classes is interpreted by eye along the profile. The total thickness for each class is plotted along each profile, and the 

total volume of each class is estimated by interpolating bew 4 ~ 

~-W(f) 

>O 

<!Z 

0::0 

~u 

w 

~~ 

3: I 

0 

3: 

~ 5 

tween adjacent profiles in the area being mapped. Once 

the volumes for each class are estimated, they are multiplied by the appropriate percentages, and a volume estimate of hydrate is made. 

DISTRIBUTION OF GAS HYDRATE 

ON THE U.S. ATLANTIC 

CONTINENTAL MARGIN 

VOLUME OF GAS HYDRATE 

The amount of gas hydrate within the sediments of the 

U.S. Atlantic continental rise south of Hudson Canyon is 

shown in figure 4. The map indicates the volume of hydrate by isopach contours that show the thickness of hydrate that would appear if all hydrate were extracted from 

the sediment pores and piled on the sea floor. 

The map shows that the greatest amount of gas hydrate is present south of 34° N., where we identify three 

major concentrations; a fourth concentration occurs at the 

northern end of our survey area. One occurs in very deep 

water, greater than 5,000 m, between 71.5° and 74° W. on 

the Lower Rise Hills, which are sediment waves built on 

the Hatteras Outer Ridge (Mountain and Tucholke, 1985; 

EEZ Scan 87, 1991; Schlee and others, 1992). A second 

concentration occurs on the Blake Ridge, mainly from 75° 

to 76° W. and 31° to 32.5° N. The third southern concentration is contiguous with the Blake Ridge hydrates and 

BSR 

Figure 1. Part of U.S. Geological Survey 48-channel seismic-reflection profile BTl off North Carolina, 

showing clear examples of the kind of effects of gas hydrate that are observed in seismic profiles. The base 

of hydrate-cemented sediments in contact with water- or gas-plus-water-filled sediments forms a very 

strong reflecting horizon that parallels the sea floor, known as the bottom simulating reflection, or BSR. 

Note that the BSR cuts through reflections from strata that dip to left in this example. Above the BSR, in 

the region where sediments are cemented by gas hydrate, the amplitude of reflections is reduced, a phenomenon known as blanking. 
316 

NO 

HYDRATE 

%HYDRATECEMENTED 

SEDIMENT 

BULK% OF 

HYDRATE 

0 

0 

THE FUTURE OF ENERGY GASES 

2 

I 

CLASS 

3 

25 

4.5 

3 

50 

9 

4 

60 

CLASS 

2 

5 

10.8 

70 

12.6 

6 

80 

14.4 

CLASS 

I 

7 

90 

16.2 

Figure 2. Synthetic seismograms showing the modeled effect of various amounts of gas-hydrate cement on 

the amplitude of reflections from acoustic impedance differences comparable to those of sedimentary strata. 

The reduction in reflection amplitude caused by hydrate cementation is the parameter called blanking. BULK 

% OF HYDRATE is percentage of hydrate relative to total volume of sediment (grains plus pore space 

containing hydrate plus pore space containing water). 

0 

.·.· 

CLASS 3 : 

(at - 6 dB) 

ID 

"0 

z -10 

UJ (at -12 dB) Cl 

::::> 

t::: 

....J 

c. 

::::: 

<t 

·20 

720 1440 2160 2880 

CDP NUMBER 

Figure 3. Plot of amplitude variations along profile in window from 0.25 to 0.5 seconds (two-way traveltime) 

below the sea floor, which is within the zone of hydrate cementation. Solid line is a moving average. Amplitude 

reductions related to blaniUng classes shown in figure 2 are indicated. dB, decibel; COP, common depth point. 
GAS HYDRATES ON THE ATLANTIC CONTINENTAL MARGIN OF THE UNITED STATES 317 

extends north-northeastward from 31.5° N., 7r W. to 34° 

N., 75.5° W.; it is labeled Carolina Trough diapirs. 

North of 34° N., a series of relatively small, weak 

concentrations extend along the upper rise to 38° N. At the 

I '-

wv / 

_I 

. ...._ ) "' 

..._/ 

VA 

NC 

northeast corner of the map, an extensive but relatively 

weak concentration of hydrate, labeled Hudson-Wilmington drape area, covers the region from approximately 3r 

to 39° N. and 71° to 72° W. 

0 

"' ~'"" ~~::::::::::: ;&. ~'"'~ 

o~~~ THICKNESS IN METERS 

v ~:~~45 

/00 

15-30 

0-15 

200 KILOMETERS 

Figure 4. Contours of volume of gas hydrate existing within sediments of U.S. Atlantic continental margin. Volume is indicated as 

thickness in meters of total amount of pure hydrate existing in pore space. Volumes are estimated by mapping extent of blanking in 

seismic profiles in depth region where hydrate is stable and using a modeling approach to relate the blanking to proportion of gas 

hydrate in the sediment (Lee and others, this volume). Straight, lightweight lines are locations of seismic profiles used in this study. 
318 THE FUTURE OF ENERGY GASES 

As an example of the inferred amount of hydrate and 

gas implied by figure 4, we calculated the amount of gas 

hydrate in the Blake Ridge concentration within the small 

area inside the main 30-m contour on the Blake Ridge 

(-31.5°-32° N., 75°-76° W.) on the basis of results sl)own 

in figure 4. The area within this 30-m contour is approximately 3,000 km2. The calculated volume of hydrate within this area, 1.13x 1011 m3, would contain a volume of 

methane at standard temperature and pressure (STP) approximately equal to 1.8x10 13 m3

, or 645 trillion cubic 

feet (Tcf) of methane. 

THICKNESS OF THE ZONE OF 

HYDRATE STABILITY 

A map of the depth of the BSR below the sea floor is 

shown in figure 5; this interval-from sea floor to BSRrepresents the zone in which gas hydrate is stable. ]3ecause 

the thermal gradient is fairly constant oyer the continental 

rise region, and because gas hydrate becomes stable at higher temperatures as pressure increases, one would expect a 

simple pattern in which the BSR would become uniformly 

deeper as the water becomes deeper (Kvenvolden and Barnard, 1982). Clearly the pattern is far more complicated (fig. 

5). A general trend of greater BSR depth with deeper water 

is shown in a plot of data from several profiles in the Blake 

Ridge area (fig. 6, from Dillon and Paull, 1983), but the 

scatter is great. In some places, such as the Hudson-Wilmington drape area (fig. 5), the tendency is reasonably pronounced to proceed from shallow to deep subbottom BSR 

as water depth increases. In mass movement areas, such as 

the Cape Lookout and Cape Fear slides (fig. 5), a distinct 

thinning of the hydrate zone is associated with the slide 

scars. Extreme complexity of the thickness of the hydratestable zone occurs in the Carolina Trough diapir area. 

GEOLOGICAL CONTROLS ON 

GAS HYDRATE DISTRIBUTION 

SEDIMENT DEPOSITION 

The most significant control on hydrate accumulation 

appears to be rate of sediment deposition. Of the four concentrations of hydrate noted above, three are associated 

with areas of high deposition. The northernmost (HudsonWillmington drape area, fig. 4) occurs in a region of undisturbed recent sedimentation (Schlee and others, 1992) 

between the Hudson and Wilmington sea valleys. The valleys form two major channelways for transportation of 

sediments across the continental rise. The area between 

the valleys is a depocenter where more than 300 m of late 

Pliocene to Holocene sediment accumulated (Mountain 

and Tucholke, 1985). 

The southeastern, deep-water hydrate concentration 

occurs on the Lower Rise Hills (fig. 4), a region of sediment-wave deposition that also was active in late Pliocene 

to present. Hydrates have not been sampled in either this or 

the drape area, but their abundance in these areas, as indicated by seismic interpretation, is not surprising. Most marine gas hydrates have been formed from biogenic methane 

(Kvenvolden and McMenamin, 1980). Areas of rapid hemipelagic deposition tend to accumulate considerable 

amounts of organic detritus and preserve it from oxidation 

at the sea floor by rapid burial, so that it is converted to 

abundant methane by bacteria within the sediments (Claypool and Kaplan, 1974). Therefore, abundance of gas hyqrate in areas of rapid deposition would be expected. 

The third concentration of gas hydrate in the mapped 

area is at the Blake Ridge (fig. 4). This also is a major 

depocenter, but at the site of the gas-hydrate concentration, the principal accumulation of sediments (to a maximum thickness of more than 1,200 m) occurred in middle 

Miocene to late Pliocene time (Mountain and Tucholke, 

1985). Deposition has continued more recently at a center 

slightly to the south of the main hydrate concentration. 

The source of gas in the Blake Ridge has been bacterial 

decay of organic material that accumulated in the sediment 

drift deposits (Kvenvolden and Barnard, 1983). A profile 

across the Blake Ridge (fig. 7) shows marked blanking of 

reflections. Blanking is strongest in the lower part of the 

hydrate zone just above the BSR. The blanking seems reasonably uniform across the ridge, indicating that the 

amount of hydrate in the sediments and the sediment velocities in the hydrate zone of stability are reasonably uniform. The profile also shows a very strong BSR under the 

crest of the ridge and a weak BSR under the flanks. The 

change in strength of the BSR probably is caused by significant changes of velocity beneath it from relatively high 

velocity on the flanks of the ridge to extremely low velocity beneath the crest region-a low velocity caused by the 

presence of gas in the sediment pore space. 

. The great volume of hydrate within the Blake Ridge 

sediments, which is the highest concentration observed, results from the anticlinal shape of the ridge and the capacity of hydrate-cemented sediments to trap gas. The Blake 

Ridge is a thick sediment drift deposit that accumulated 

rapidly in a ridge configuration between the late Oligocene and Holocene; accumulation rates ' reached 160-190 

m/m.y. (Mountain and Tucholke, 1985). As the sediment 

accumulated, the ridge built upward and the deeper sediments became warmer; in essence, the surfaces of constant 

temperature-the isotherms-migrated upward as the sediment surface rose. This warming caused the hydrate in the 

deeper, older sediments to break down, releasing gas that 

moved upward through the sediments and was trapped at 

the relatively impermeable base of hydrate-cemented sediments, which, by its configuration, acted as a trap. The 

trapped free gas penetrated the hydrate-cemented zone by 
GAS HYDRATES ON THE ATLANTIC CONTINENTAL MARGIN OF THE UNITED STATES 319 

diffusion or perhaps along pathways provided by small 

compaction faults, and it was immediately converted to 

hydrate there, thus causing a concentration of hydrate at 

the base of the hydrate-stable zone. The trapping of gas at 

the axis of the ridge beneath the hydrate zone (beneath the 

VA 

NC 

" 

BSR) is shown by the variation in BSR strength in figure 

7, and the densest concentration of hydrate in the lower 

part of the hydrate zone is indicated by the presence of the 

strongest blanking there, just above the BSR. The process 

described accounts for the great concentration of hydrate 

0 

\ \ 

METERS BELOW SEA FLOOR 

. >750 

600-750 

500-600 

<500 

100 200 KILOMETERS 

Figure 5. Contours in meters of thickness of layer of hydrate stability within sediments of U.S. Atlantic continental margin. This is 

distance from sea floor to bottom-simulating reflection (BSR). BSR represents bottom of zone of phase stability for gas hydrates. 

Contour interval for distance from sea floor to BSR is 50 m. 
320 

(/) 

n:: 

w 

fw 

~ 

0 

_j 

::.:: 

I 2 

f0... 

w 

0 

n:: 

w 

f-

<X: 

S:3 

THE FUTURE OF ENERGY GASES 

X 

X 

X X 

X 

X X 

X X 

0.4 0.6 

BSR DEPTH BELOW SEA FLOOR 

(KILOMETERS) 

sw 

~ X 

Xx X 

X 

0.8 

at the fast-depositing sediment drift of the Blake Ridge. It 

also explains why the main concentration occurs not at the 

depocenter of most recent accumulation (late Pliocene to 

Holocene) (Mountain and Tucholke, 1985), but rather at 

an older depocenter (middle Miocene to late Pliocene), 

where the upbuilding of the ridge and the resulting recycling of hydrate gas has gone on longer. 

FAULTING AND DIAPIRISM 

We mentioned above that free gas trapped beneath the 

BSR (beneath the zone of stability for gas hydrate) is likely to migrate upward through pathways provided by faults. 

Analysis of several seismic profiles (fig. 8, for example) 

shows (1) small offsets of reflections that represent faults 

and are marked by arrows (best seen below the BSR, 

where reflections are stronger); (2) presence of "fingers" 

of more intense blanking that extend upward from the 

BSR above the visible faults-this pattern seems to indicate that gas which has migrated upward through the 

~ Figure 6. Plot of depth of bottom-simulating reflection 

(BSR) below sea floor versus water depth for several profiles in 

Blake Ridge area (from Dillon and Paull, 1983). 

NE 

3.5-

ZONE OF HYDRATE 

STABILITY IN SEDIMENTS 

CREST OF 

BLAKE RIDGE 

VERY WEAK BSR BLANKED 

REFLECTIONS 0 

STRONG BSR 

5 KM 

Figure 7. Seismic-reflection profile across Blake Ridge. This is a single-channel, digitally recorded and processed profile shot with a 

160-cubic-inch airgun as the seismic source. Intensive blanking of reflections above bottom-simulating reflection (BSR) indicates 

considerable amount of gas hydrate cementing the sediments. Variations in strength of BSR probably are caused by differences in 

velocity below the BSR, from moderately slow on the flanks of the ridge, where hydrate-cemented sediments probably overlie watersaturated sediments, to extremely slow under the BSR beneath the crest, where we infer the presence of free gas in addition to water 

in the sediments. 
GAS HYDRATES ON THE ATLANTIC CONTINENTAL MARGIN OF THE UNITED STATES 321 

sw 

SP. 200 .......... 3.5 (f) 

0 

z 

0 

u 

w 

(f) 

-

w 

~ 

I-

_.J 

w 4.0 

> <! 

0::: 

I-

>-

~ I 

0 

3: 

I- 4.5 

400 

+ + + + + + + + 

NE 

600 

5 KILOMETERS 

Figure 8. Seismic-reflection profile on flank of Blake Ridge, similar to figure 7. Small faults, marked by arrows, are indicated by 

offsets of stratal reflections best seen below bottom-simulating reflection (BSR), where reflections are stronger. These faults are 

probably caused by compaction of the thick sedimentary accumulation. Above BSR, fingers of more intense blanking extend upward 

above the faults into the hydrate-stable zone. This pattern may indicate increased amounts of hydrate at these locations, formed from 

gas that migrated up the fault channelways. SP, shotpoint. 

faults has caused enrichment in the hydrate accumulation; 

(3) an increase in reflection strength of reflections below 

the BSR on moving away from faults-this pattern suggests that velocity contrasts are changing along strata, consistent with an increase in amount of gas away from 

faults, and that gas may be escaping up the faults (this 

pattern is not apparent on fig. 8 because of processing parameters designed to emphasize the faults). Of course, gas 

would be expected to form gas hydrate on entering the 

hydrate-stable zone, but warmer gas rising from below 

along newly opened fractures might penetrate a considerable distance before it cooled off and formed hydrate. 

Migration of deeper gas along faults may be a major 

factor in concentrating hydrate in a fourth hydrate concentration that we identified, along the Carolina Trough diapirs 

(fig. 4). This concentration does not appear to be associated 

with a sedimentary depocenter, as are the other three. In the 

Carolina Trough diapir region a linear group of diapirs, 

probably formed of salt, extends along the seaward side of 

the deep Carolina Trough, one of the four major continental 

margin basins of the eastern. United States (Dillon and others, 1983; Dillon and Popenoe, 1988). A profile through 

one of these diapirs in which a few of the associated faults 

are marked with arrows is shown in figure 9. The distribution of diapirs in relation to the volume of gas hydrate is 

shown in figure 10. The Carolina Trough diapirs and, presumably, their associated faults rise from as deep as 12 km 

(Dillon and others, 1983). The faults may provide channelways that feed gas to shallow levels where hydrate is 

formed from deep, thermogenic sources in the Carolina 

Trough sediments. Whether the gas in these hydrates has a 

deep, thermogenic source, or a shallow, biogenic source is 

unknown at present and awaits sampling and analysis. 

However, as the Carolina Trough diapir trend is the only 

major diapir trend on the U.S. Atlantic continental margin 

and it is associated with the only concentration of hydrate 

in the survey area that is not correlated with a distinct depocenter, derivation of gas from a deep source appears likely. 

Although gas hydrates are concentrated around the diapirs (fig. I 0), a diapir itself (fig. 9) disrupts the seismic 

evidence for hydrate (BSR and blanking). Even when a 

diapir fails to reach up to the zone of hydrate stability, the 

BSR is observed to rise above the diapir, indicating that 

the hydrate-stable layer becomes thinner (Paull and Dillon, 

1981 ). The structure of the hydrate-stable layer is very 

complex in the vicinity of the diapirs (fig. II). Actually 

the correspondence of hydrate-layer structure to diapir location probably is much closer than indicated in figure 11, 
322 

SE o<) 

..... 

Q 

3 

..... Figure 9. Seismic- ...--.. 

reflection profile (2- CJ) 

0 

channel, 160-cubic-inch z 

airgun source, digitally 0 

u recorded and processed) w across diapir that rup- ~4 

tures sea floor on conti- w 

nental rise off North ~ 

Carolina, and that probably is salt-cored. A few ~ w 

of the possible faults are 

indicated by arrows. VE ~ a:: 5 is vertical exaggeration. ILightweight scale across 

top of profile shows lo- ~ s: cation of shotpoints. I 

0 

s: 

I6 

..... Figure 10. Locations of landslides 

and diapirs plotted on the map of gashydrate volume (fig. 4) for the Carolina 

Trough diapir and Blake Ridge regions. 

Volume of hydrate is indicated as isopach contours of amount of hydrate existing in sedimentary pores. 

0 

THE FUTURE OF ENERGY GASES 

IOKm 

VE=9.8 

THICKNESS IN METERS 

! ~;~45 . 15-30 

0-15 

1\1\lll\l\1 DIAPIR 

NW 
GAS HYDRATES ON THE ATLANTIC CONTINENTAL MARGIN OF THE UNITED STATES 323 

because the mapping of diapirs and the mapping of hydrate were, of necessity, done on different seismic-profile 

data sets. The effects on hydrates at salt diapirs may be 

related to the greater thermal conductivity of salt compared to sediment, which would produce a warm spot at a 

diapir, reducing the stability of hydrate (MacLeod, 1982). 

The effects also may be related to the presence of salt ions 

in interstitial fluids, which would act as ant;freeze. 

MASS MOVEMENT 

Sea-floor mass movements seem to have significant effects on structure of the hydrate layer and on the abun7JO 76° 

34° 

METERS BELOW SEA 

>750 

600-750 

500-600 

<500 

111\lll\ill DIAPIR 

33° 

dance of hydrate. The effect on hydrate-layer thickness is 

noticeable in figure 11, where the locations of two major 

sea-floor landslide scars south of Cape Hatteras have been 

indicated (fig. 5). The landslide scars have been accurately 

located from a long-range sidescan sonar (GLORIA) survey of the Atlantic continental margin (EEZ-Scan 87, 

1991 ), and part of the sidescan mosaic is reproduced in 

figure 12 to show the landslide effects. Of the two slides 

present in this area, the Cape Fear slide is obviously 

younger, as it crosses the Cape Lookout slide (fig. 12), and 

the Cape Fear slide also has the more significant influence 

on hydrate-layer thickness (fig. 11 ). These two major slides 

south of Cape Hatteras strongly affect the hydrate. North 

of Cape Hatteras, from Albemarle Canyon to Wilmington 

75° 74° 

Figure 11. Locations of landslides and diapirs plotted on map of thickness of gas-hydrate layer (fig. 5) 

for the Carolina Trough diapir and Blake Ridge regions. Thickness of hydrate layer is equivalent to 

depth of bottom-simulating reflection (BSR) below sea floor. 
324 THE FUTURE OF ENERGY GASES 

0 50 100 KILOMETERS 

Figure 12. Long-range sidescan sonar (GLORIA) mosaic of the Cape Fear and Cape Lookout slide scar area (EEZ-Scan 87, 1991 ). 

White dots delineate boundaries of landslides. 

sea valley (fig. 5), little seismic evidence of gas hydrate is 

observed in a region of complex smaller landslides and 

canyons on the middle and lower continental rise (figs. 4, 

5), providing further evidence that mass movement is correlated to reduced gas-hydrate thickness and volume. 

A profile across the Cape Fear slide scar (fig. 13) shows 

that the BSR disappears under the center of the slide, and 

that the BSR also rises slightly at the sides of the slide scar. 

Mapping shows that the BSR-to-sea-ftoor distance commonly decreases by 200 to 300 m from the center of the 

slide to surrounding, undisturbed areas (fig. 11 ), an amount 

greater than the thickness of slope strata removed by the 

mass movement. This shallowing of the BSR and the clear 

association of slide scars to thinning of the hydrate-stable 

zone suggest that removal of strata by mass movement 

causes breakdown of hydrate. This breakdown may result 

from a pressure reduction. Pore pressure within unconsolidated sediments is commonly considered to be hydrostatic, 

that is, equal to the height of a column of water from a point 

within the sediments to the sea surface; this assumption 

presumes that pressure is transmitted through the pore 

water. However, where hydrate fills the pore space and cements the sediments, that presumption may be incorrect. 

The deposits probably act as impermeable rock, in which 

overpressures are generated, and the pressure becomes lithostatic rather than hydrostatic. In such a case a landslide 

would reduce pressure in the sediments by removing overburden that acts like a slab of lithified rock. The pressure 

would be decreased, and this decrease would cause breakdown of hydrate where it is near its phase limit, at the BSR. 

We suggest in the previous paragraph that mass movement may reduce pressure and cause breakdown of hydrate, 

but the converse also probably is true. If hydrate breaks 

down for some reason other than mass movement, this 

breakdown can weaken the sediments and foster landslides. 

In locations where the BSR is fairly near the sea floor, 

beneath the upper continental rise, breakdown of the hydrate 

might facilitate sliding by substituting a weak layer of gascharged sediment for a zone that previously had been essentially indurated material and thus providing a lubricating 
GAS HYDRATES ON THE ATLANTIC CONTINENTAL MARGIN OF THE UNITED STATES 325 

layer for the slide. On the U.S. Atlantic continental margin, 

slopes of 6° or less would be expected to be stable given the 

materials that are present, but many landslide scars exist and 

thus some triggering or weakening mechanism is required 

(Booth and others, 1984, I 988). A plot of the distribution of 

frequency of the top of the landslide scars versus their water 

depth reveals a peak in frequency of landslides at a water 

depth from about 500 to 700 m, very near the shallow-water 

limit of the hydrate-stable region (Dillon and others, 1991; 

James Booth, written commun., I 992). This is only circumstantial evidence, but it suggests a relationship between 

Iandsliding and gas-hydrate breakdown. 

(/) 

0 

z 

0 

u 

w 

(/) 

w 

:2' 

f-

_J 

w 

~ 0:: 

f-

>-

~ I 

0 

5: 

fMarine gas hydrate certainly would have broken down 

during glacial episodes, when total pressure on the hydrate 

was reduced by the lowering of sea level caused by sequestering of water in continental glaciers. An estimate from the 

data of figure 6 suggests that a sea-level lowering of 120 m 

(the magnitude of lowering during the last glaciation) would 

cause a rise of the base of the hydrate (BSR) of about 20m 

(fig. 14), and this rise of the BSR could trigger landslides on 

VE=17 0 20Km '-----~-----' 

Figure 13. Seismic-reflection profile (similar to that in fig. 9) across Cape Fear slide scar. Bottom-simulating 

reflection (BSR) becomes shallower and weaker beneath slide scar. VE, vertical exaggeration. 

A 

120m 

SEA LEVEL I 

SEA LEVEL 2 

SEA 

LEVEL 

FALL 

ZONE OF GAS 

HYDRATE BREAKDOWN 

WITH FREE GAS 

SLUMPING 

ON WEAK 

GAS-CHARGED 

ZONE 

B 

Figure 14. Conceptual diagram of the effect on a sea-floor gas-hydrate layer of a sealevel fall of 120 m, comparable to the most recent glacial sea-level lowering. A, Reduction of pressure would cause a breakdown of gas hydrate just above the bottom simulating reflection (BSR), where gas hydrate is at its phase limit. B, This breakdown would 

produce a layer of gas-charged sediment that would be very weak and could provide a 

lubricating layer that would foster landsliding. 
326 THE FUTURE OF ENERGY GASES 

the ocean floor all over the world (Paull and others, 1991 ). 

Of course, if such a great volume of methane escaped, it 

would greatly increase the greenhouse effect in the atmosphere, because methane is a much more potent greenhouse 

gas than carbon dioxide (Mitchell, 1989; Lashof and Ahuja 

1990; Cole, this volume). 

GAS TRAPS 

The trapping of free gas beneath a seal formed by hydrate-cemented sediment has been indicated above to be 

important in the concentration of hydrate. Of course, such 

trapped gas might form a significant energy deposit as 

well (Dillon and others, 1980). The simplest case occurs 

where gas appears to be trapped in a dome of the hydratecemented sealing layer caused by a dome shape of the sea 

floor (fig. 7; diagrammed in fig. !SA). Even fairly small 

sea-floor hills can form potentially significant gas traps 

(fig. 16). 

A dome also can be formed in the gas-hydrate seal 

above diapirs strictly by thermal and geochemical factors 

(figs. 9, 15B). Figure 17 shows high resolution (fig. 17A) 

and deep penetration (fig. 17 B) profiles across a buried diapir on the North Carolina continental rise. The BSR in the 

deep penetration profile (fig. 17 B) appears as a reflection 

that cuts through other reflections caused by strata and rises 

over the diapir at the center of the profile. The high resolution profile (fig. 17A) gives a better view of the true nature 

of the BSR, which appears as a series of terminations of 

~ Figure 15. Possible configurations of sea-floor gas-hydrate 

layer that would produce gas traps with hydrate seal. A, Dome in 

gas-hydrate seal caused by dome in sea floor. B, Dome in gashydrate seal caused by thermal and chemical factors above a diapir. C, Gas-hydrate seal at updip end of permeable layer in set of 

dipping strata. 

sw 

I 

~ 4.5->: 

rSEA FLOOR 

B 

c 

0 

JJJJJJJJ 

NE 

5KM 

Figure 16. Seismic-reflection profile on Blake Ridge (similar to that in fig. 7) displaying probable gas traps beneath sea-floor hills, a 

situation comparable to that in fig. 15A. 
GAS HYDRATES ON THE ATLANTIC CONTINENTAL MARGIN OF THE UNITED STATES 

3 

NE 

0 

' 

§ ·J~,~~ z 3 S .· ~~AN KIN~ o . . ·@o r , .r 

u l ·. ~ w - (f) ---

-

5KM 

---

sw 

------

SEISMICJ 

PROFILE/ 

Figure 17. Two seismic-reflection profiles along same track (see small map to right of fig . 178) across diapir that does not 

reach sea floor on North Carolina continental rise. A, High-resolution profile collected with 5-cubic-inch airgun source; 8, 

Deep-penetration profile collected with pair of 540-cubic-inch airguns. Lower boundary of hydrate-cemented zone, shown 

by bottom-simulating reflection (BSR), is domed above the diapir, probably due to thermal and chemical changes in the 

sediments. The dome can trap gas as diagrammed in fig. 158. 

327 
328 THE FUTURE OF ENERGY GASES 

strong reflections against a blanked zone. The blanked zone 

is assumed to be hydrate-filled, and the strong reflections 

below it are inferred to represent gas-charged strata within 

the dome in the base of the hydrate seal. Several faults are 

suggested by these data, including the faults that allow subsidence of the graben above the diapir. 

In our surveys, a more common type of trap employing a hydrate seal is formed where dipping strata formed 

of alternating permeable and impermeable beds intersect 

the sea floor. In such cases a permeable layer can be 

sealed at its updip end by the gas-hydrate-cemented layer, 

forming a trap (15C). Locations where gas is trapped beneath the hydrate layer in dipping strata are marked by 

strong reflections below the BSR (figs. I 8, I 9). 

SUMMARY AND CONCLUSIONS 

I. Natural-gas hydrates (mostly methane hydrates) 

exist within marine sediments in a layer that extends from 

the sea floor down to a level where conditions are too 

warm for hydrate stability at the existing pressure. The 

layer commonly is several hundred meters thick and is 

present at water depths exceeding 300 to 500 m. 

C1> 

10 

co 

2. Gas hydrates have been sampled in drilling, and they 

also can be recognized in seismic-reflection profiles. Characteristics that allow hydrate detection in seismic profiles 

are (I) a bottom-simulating reflection, or BSR, which is a 

reflection that parallels the sea floor and cuts through reflections from strata; the BSR is a reflection from the base 

of the hydrate-cemented layer; (2) a velocity inversion in 

which the velocity of hydrate-cemented sediment above the 

BSR is observed to have higher velocity than the sediment 

below; and (3) a reduction in amplitude of reflections within the hydrate-cemented zone, known as blanking. The 

BSR and the blanking phenomena allow us to map the distribution of gas-hydrate-cemented sediments and amount of 

gas hydrate on the U.S. Atlantic continental margin. 

3. Four regions of gas-hydrate concentration have 

been mapped on the continental rise in the offshore region 

between New Jersey and Georgia. Three are correlated 

with sediment depocenters, and one occurs along a concentration of diapirs and their associated faults. 

4. Concentration at depocenters probably occurs because most gas in hydrate is biogenic, produced by bacteria that feed on organic material that is preserved in fastdepositing accumulations. Of the three hydrate concentrations that are associated with depocenters, two are sites of 

~--~--~--~--~--~--~--~--~--~--~~--------

....--... 

(f) 

0 

z 

0 

u 

w 

0 

VE=70 

~ 4 -------~~:.s-+.~I=--

IOKm 

Figure 18. Seismic-reflection profile on North Carolina continental rise (similar to that of fig. 9) showing dipping reflections representing strata that are interpreted to contain gas and that are sealed at their updip ends by gas-hydrate cementation, a situation 

comparable to that in fig. 15C. BSR, bottom-simulating reflection; VE, vertical exaggeration. Lightweight scale across top of profile 

shows location of shotpoints. 
GAS HYDRATES ON THE ATLANTIC CONTINENTAL MARGIN OF THE UNITED STATES 329 

(f) 

0 

z 

0 

u 

w 

(f) 

w 

~ 

~ 

sw 

. ,·.. .. :~ .. · . 

NE 

0 5KM 

TRAPPED GAS ? 

BSR .:- : 

_:~~t f . t~? ·~:> . ~ 4. 0 __::;.--.....,' ;-- '';" ·-:7.. ,,:_':'",...:;; ·~.;:__.-"'-; : -"7- - ~~;:;;;:::~~~~-t;..:;_.....:;~~::,.:.·:.o..;-;;; ' · ·._ 

<( 

0:: 

I-

~ 3:4.5-

1 

0 

3: 

I-

. .. 

.... ... ~ ~ ..... '

,.. . .~ .. .... ... ' ~ 

. ~"·· ...... .... 

Figure 19. Profile (similar to that in fig . 7) showing dipping strata truncated at sea floor on flank 

of Blake Ridge. Strongly reflecting layers below bottom-simulating reflection (BSR) probably 

represent gas-charged strata sealed as diagrammed in fig. 15C. 

active sediment accumulation. The third, and largest of all 

four hydrate accumulations, occurs at a depocenter that 

was most active in middle Miocene to late Pliocene time, 

implying that gas from hydrates that formed in older sediments has been recycled into younger hydrates. 

5. Faults seem to form channelways for the passage of 

gas upward into the hydrate layer, as interpreted in seismic 

profiles. A major concentration of hydrate, one not related 

to a distinct depocenter, is associated with a trend of diapirs with their associated faults. 

6. Breakdown of gas hydrate and thinning of the hydrate layer has occurred at sites of mass movement, probably caused by reduction of pressure due to removal of 

sediment during landsliding. Conversely, breakdown of hydrate may cause mass movements by substituting a weak 

layer of gas-rich sediment for a strong layer of hydratecemented sediment. The hydrate breakdown that initiates 

landslide movement might be caused by pressure reductions that result from glacial sea-level lowerings. We are 

faced with a possible cascading chain of events in which a 

breakdown of hydrate could trigger landslides that would 

cause further breakdown of hydrate and result in considerable loss of methane from the marine hydrate reservoir. 

7. Reduction in the amount of hydrate and thinning of 

the hydrate layer are also observed at diapirs, probably due 

to thermal and chemical anomalies caused by the diapirs. 

8. Gas-hydrate-cemented sediments can form an impermeable seal and, if appropriately configured, will form 

traps. Gas traps with hydrate seals are observed at sea-floor 

hills and diapirs, and at locations where dipping strata intersect the sea floor and are sealed at their updip ends by gas 

hydrate. Production of gas from such traps would result in 

extraction of the free gas and of additional gas derived from 

the breakdown of the hydrate seal by depressurization. 

ACKNOWLEDGMENTS 

We gratefully acknowledge the support provided by 

the U.S. Department of Energy, Morgantown Energy Technology Center, through Interagency Agreement DE-AI21-

83MC20422. Discussions regarding gas hydrates with 

Charles Paull, Keith K venvolden, Rodney Malone, Eric 

Schmuck, Michael Max, and many others have been invaluable. We thank the reviewers, James Booth, David 

Howell, and Michael Fanelli. 

REFERENCES CITED 

Booth, J.S., O'Leary, D.W., Popenoe, P., Robb, J.M., and 

McGregor, B.A., 1988, Map and tabulation of Quaternary 

mass movements along the United States-Canadian Atlantic 

continental slope from 32°00' to 47°00' N latitude: U.S. 

Geological Survey Miscellaneous Field Studies Map MF2027, scale 1:2,000,000. 

Booth, J.S., Silva, A.J., and Jordan, S.A., 1984, Slope-stability 

analysis and creep susceptibility of Quaternary sediments 

on the northeastern U.S. Continental Slope, in Denness, B., 

ed., Sea mechanics, International Union of Theoretical and 

Applied Mechanics-International Union of Geodesy and 
330 THE FUTURE OF ENERGY GASES 

Geophysics Symposium Proceedings: London, Graham and 

Trotman, London, p. 65-75. 

Brandt, H., 1960, Factors affecting compressional wave velocity 

in unconsolidated marine sand sediments: Journal of the 

Acoustical Society of America, v. 32, p. 171-179. 

Claypool, G.E., and Kaplan, I.R., 1974, The origin and distribution of methane in marine sediments, in Kaplan, I.R., ed., 

Natural gases in marine sediments: New York, Plenum 

Press, p. 99-139. 

Collins, B.P., and Watkins, J.S., 1985, Analysis of a gas hydrate 

off southwest Mexico using seismic processing techniques 

and Deep Sea Drilling Project Leg 66 results: Geophysics, 

v. 50, p. 813-828. 

Dillon, W.P., Booth, J.S., Paull, C.K., Fehlhaber, K., Hutchinson, 

D.R., and Swift, B.A., 1991, Mapping sub-seafloor reservoirs of a greenhouse gas-Methane hydrates, in Kumar, 

M., and Maul, G.A., Symposium Directors, Proceedings of 

the International Symposium on Marine Positioning: Marine 

Geodesy Committee, Marine Technology Society, Washington, D.C., p. 545-554. 

Dillon, W.P., Grow, J.A., and Paull, C.K., 1980, Unconventional 

gas-hydrate seals may trap gas off southeast U.S.: Oil and 

Gas Journal, v. 78, no. 1, p. 124, 126, 129, 130. 

Dillon, W.P., and Paull, C.K., 1983, Marine gas hydrates-IT; 

Geophysical Evidence, in Cox, J.L., ed., Natural gas hydrates-Properties, occurrences and recovery: Boston, Butterworth Publishers, p. 73-90. 

Dillon, W.P., and Popenoe, Peter, 1988, The Blake Plateau and 

Carolina Trough, in Sheridan, R.E., and Grow, J.A., eds., 

The Atlantic Continental Margin, U.S.: Boulder, Colorado, 

Geological Society of America, The Geology of North 

America, v. 1-2, p. 291-328. 

Dillon, W.P., Popenoe, Peter, Grow, J.A., Klitgord, K.D., Swift, 

B.A., Paull, C.K., and Cashman, K.V., 1983, Growth faulting and diapirism-Their relationship and control in the 

Carolina Trough, eastern North America, in Watkins, J.S., 

and Drake, C.L., eds., Studies in continental margin geology: American Association of Petroleum Geologists, Memoir 

No. 34, p. 21-46. 

EEZ-Scan 87, 1991, Atlas of the U.S. Exclusive Economic Zone, 

Atlantic continental margin: U.S. Geological Survey Miscellaneous Investigations Series Map 1-2054, 174 p. 

Krason, J., and Ridley, W.l., 1985, Geological evolution and 

analysis of confirmed or suspected gas-hydrate localities, 

vol. 1., Blake-Bahama Outer Ridge-U.S. East Coast: DOFJ 

MC/21181 (DE86001006), 100 p. 

Kvenvolden, K.A., 1988, Methane hydrate-A major reservoir of 

carbon in the shallow geosphere?: Chemical Geology, v. 71, 

p. 41-51. 

Kvenvolden, K.A., and Barnard, L.A., 1982, Hydrates of natural 

gas in continental margins, in Watkins, J.S., and Drake, 

C.L., eds., Studies of continental margin geology: American 

Association of Petroleum Geologists Memoir No. 34, 

p. 631-640. 

--1983, Gas hydrates of the Blake Outer Ridge, Site 533, 

Deep Sea Drilling Project Leg 76, in Sheridan, R.E., and 

Gradstein, F., and others, Initial reports of the Deep Sea 

Drilling Project, v. 76: Washington, D.C., U.S. Government 

Printing Office, p. 353-365. 

Kvenvolden, K.A., and Kastner, M., 1990, Gas hydrates of the 

Peruvian outer continental margin, in Suess, E.R., von 

Huene, R., and others, Proceedings of the Ocean Drilling 

Program, Scientific Results: Washington, D.C., U.S. Government Printing Office, v. 112, p. 517-526. 

Kvenvolden, K.A., and McMenamin, M.A., 1980, Hydrates of 

natural gas-A review of their geological occurrences: U.S. 

Geological Survey Circular 825, 11 p. 

Lashof, D.A., and Ahuja, D.R., 1990, Relative contributions of 

greenhouse gas emissions to global warming: Nature, v. 344, 

p. 529-532. 

Lee, M.W., Dillon, W.P., and Hutchinson, D.R., i992, Estimating 

the amount of gas hydrate in marine sediments in the Blake 

Ridge area, southeastern Atlantic Margin: U. S. Geological 

Survey Open-File Report 92-275, 24 p. 

Lee, M.W., Hutchinson, D.R., Dillon, W.P., Miller, J.J., Agena, 

W.F., and Swift, B.A., in press, A method of estimating the 

amount of in situ gas hydrates in deep marine sediments: 

Marine and Petroleum Geology. 

MacLeod, M.K., 1982, Gas hydrates in ocean bottom sediments, 

American Association of Petroleum Geologists Bulletin, 

v. 66, p. 2649-2662. 

Miller, J.J., Lee, M.W., and von H~ene, Roland, 1991, An analysis of a seismic reflection from the base of a gas-hydrate 

zone, offshore Peru: American Association of Petroleum Geologists Bulletin, v. 75, p. 910-924. 

Mitchell, J.F.B., 1989, The "greenhouse" effect and climate 

change: Reviews of Geophysics, v. 27, p. 115-139. 

Mountain, G.S., and Tucholke, B.E., 1985, Mesozoic and Cenozoic geology of the U.S. Atlantic continental slope and rise, in 

Poag, C.W., ed., Geologic evolution of the United States Atlantic Margin: New York, Van Nostrand Reinhold, p. 293-341. 

Paull, C.K., and Dillon, W.P., 1981, Appearance and distribution of 

the gas-hydrate reflection in the Blake Ridge region, offshore 

southeastern United States: U.S. Geological Survey Miscellaneous Field Studies Map MF-1252, scale 1:1,000,000. 

Paull, C.K., Ussler, William, Ill, and Dillon, W.P., 1991, Is the 

extent of glaciation limited by marine gas hydrates?: Geophysical Research Letters, v. 18, p. 432-434. 

Rowe, M.M., and Gettrust, J.P., 1993, Fine structure of methane 

bearing sediments on the Blake Outer Ridge as determined 

from deep-tow multichannel seismic data: Journal of Geophysical Research, v. 98, p. 463-473. 

Schlee, J.S., Dillon, W.P., Popenoe, Peter, Robb, J.M., and O'Leary, 

D.W., 1992, GLORIA mosaic of the deep sea floor off the 

Atlantic coast of the United States: U.S. Geological Survey 

Miscellaneous Field Studies Map MF-2211, scale I :2,000,000. 

Shipley, T.H., and Didyk, B.M., 1982, Occurrence of methane 

hydrates offshore southern Mexico, in Watkins, J.S., Moore, 

J.C., and others, Initial Reports of the Deep Sea Drilling 

Project, vol. 66: Washington, D.C., U.S. Government Printing Office, p. 547-555. 

Shipley, T.H., Houston, M.H., Buffler, R.T., Shaub, F.J., McMillen, K.J., Ladd, J.W., and Worzel, J.L., 1979, Seismic evidence for widespread possible gas-hydrate horizons on 

continental slopes and rises: American Association of Petroleum Geologists Bulletin, v. 62, p. 2204-2213. 

Sloan, E.D., Jr., 1990, Clathrate hydrates of natural gases: New 

York, Marcel Dekker, 641 p. 

Tucholke, B.E., Bryan, G.M., and Ewing, J.l., 1977, Gas-hydrate 

horizons detected in seismic profile data from the western 

North Atlantic: American Association of Petroleum Geologists Bulletin, v. 61, p.698-707. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Velocity and Amplitude Structures on Seismic-Reflection 

Profiles-Possible Massive Gas-Hydrate Deposits 

and Underlying Gas Accumulations in the Bering Sea Basin 

By David W. Scho111 and Patrick E. Hart1 

CONTENTS 

Abstract ... .. ....... ................. ............................................ 331 

Introduction ....................................................... ............ 332 

HDL and BSR's ............................................................ 333 

History of Vamp Observations and Interpretations ...... 335 

Field Observations and VAMP's .................................. 335 

Occurrence and Dimensional Characteristics ........ 337 

Stratigraphic Setting .............................................. 343 

Geochemical and Thermal Flux ................ ............ 343 

Acoustic Analyses and Properties of VAMP's ............. 345 

General Information ............................................... 345 

Velocity Anomalies and Estimates of Hydrate 

and Gas Concentration .... ....................................... 345 

Discussion ............................ .......... ..... ........ ............. ..... 346 

Evolution of Hydrate BSR .................................... 346 

VAMP Formation ................................................... 347 

Sources of Methane ................ ............................... 348 

Volume of Methane ............................................... 348 

Future Research Directions ......... .................... ............. 349 

References Cited ........ ............. ...................................... 350 

ABSTRACT 

Regional geologic and geophysical data imply that 

large areas of the deep-water (3,700-4,000 m) floor of the 

1 U.S. Geological Survey, 345 Middlefield Rd., Menlo Park, CA 

94025. 

Bering Sea Basin are underlain by pore-filling deposits of 

methane gas hydrate. Hydrate deposits are hypothesized to 

occur in diatomaceous turbidite beds of middle Pliocene 

and younger age that cap the basin's 2- to 12-km-thick 

sedimentary fill. Methane hydrate deposits can theoretically occur only within the uppermost -450 m of surficial 

sediment, which thus constitutes the basin's hydrate layer 

(HDL). 

Distinctive acoustic velocity and amplitude anomalies 

(VAMP's) are recorded widely within- the HDL. VAMP's 

are displayed on seismic reflection records as vertical columns (1-2 km wide) of downflexed horizons commonly 

stacked directly beneath the crestal region of a series of 

arched or domed horizons. VAMP structures are most 

commonly recorded within flat-lying beds and in nonstructural settings. A prominent bottom simulating reflector 

(BSR) of negative polarity separates the upward arch from 

the underlying columns of downflexed horizons. The BSR 

is recorded at a subsurface depth closely matching that of 

the theoretical base of the HDL. These observations are 

interpreted to mean that VAMP's are compound-velocity 

pseudostructures (a pullup over a pushdown) recording a 

localized body of massive gas hydrate of high acoustic velocity overlying a column of low-velocity sediment containing free interstitial gas. Within the HDL, hydrate 

deposits are thus inferred to occur in two principal modes: 

(I) disseminated deposits occupying probably less than 

<10-20 percent of available pore space, and (2) massive 

accumulations (>10-20 percent) localized at VAMP structures and mainly concentrated in the basal beds of the 

HDL. 

VAMP's occur over an area of approximately 400,000 

km2, roughly equivalent to that of the states of Nevada 

331 
332 THE FUTURE OF ENERGY GASES 

and Utah combined. At VAMP's, a basinwide inferred average pull up effect of 10 ms is acoustically equivalent to 

at least a 12.5-m-thick column of solid methane hydrate, 

and a measured average underlying pushdown of 23 ms is 

acoustically equivalent to a 77-m-thick column of sediment with pore space charged with at least 2 or more percent free gas. If VAMP's are discrete bodies of massive 

hydrate and free gas, then a conservatively estimated 

12,000 VAMP's occur in the Bering Sea Basin. The corresponding total volume of methane occurring at them is approximately 1,100 trillion cubic feet (Tcf)-about 900 Tcf 

in the form of massive hydrate and about 200 Tcf as free 

gas: This basinwide volume is a minimum or low-end estimate of the methane potentially available in the Bering 

Sea Basin. The volume potentially available at a single 

large VAMP structure is about 0.3 Tcf. The methane is 

thought to be chiefly of thermogenic origin. 

EXPLANATION 

• VAMP 

190 

+DSDP SITE 

8-80 

-SEISMIC PROFILE 

CL___!00 KILOMETERS 

A major advance in information is needed to accurately map and model VAMP structures, to confirm their inferred relation to massive hydrate deposits, and to resolve 

the special geologic history that favors the widespread formation of VAMP's in the Bering Sea Basin. 

INTRODUCTION 

Anomalous acoustic structures in flat-lying basinal deposits are widely recorded on time-base seismic-reflection 

profiles from the abyssal floor (3,700-4,000 m) of the Bering Sea Basin (fig. 1; Cooper and others, 1987). These 

structures, termed VAMP's (velocity-amplitude anomaly), 

are displayed as vertical columns of downflexed horizons 

commonly nestled beneath a domed or upward-arched set 

of horizons. The domed, upper half of VAMP structures is 

. .. . . . . .•.. . ·. . .. 

BASIN 

180" 

17z0 

so• 

172 

Figure 1. Index map of Bering Sea Basin showing location of velocity and amplitude structures (VAMP's) in the Aleutian and Bowers 

Basins known prior to 1980 and locations of seismic sections displayed on other figures. Other VAMP locations are shown on figure 5. 

Deep water Bering Sea Basin comprises the separate Komandorsky, Bowers, and Aleutian subbasins. 
VELOCITY AND AMPLITUDE STRUCTURES IN THE BERING SEA BASIN 333 

not always observed (approximately 58 percent; Rearic 

and others, 1988); hence, the defining or diagnostic attribute of a VAMP's is the anomalous column of downflexures. Typical recordings of VAMP's are displayed on 

figures 2, 3, 4, and ?(see also Scholl and Cooper, 1978; 

Cooper and others, 1978, 1979, 1987). 

The following general relations are typical of VAMP 

structures: 1) The sets of domed and downflexed horizons 

are vertically superimposed; 2) The sets of domed and 

downflexed horizons occur as isolated deflections within 

otherwise flat-lying beds; 3) Thousands of VAMP's occur, 

most of which are not localized over specific elements of 

basement relief; 4) A prominent negative-polarity reflection 

horizon, which is also a bottom simulating reflector (BSR), 

lies at the base of the arched horizons and at the top of the 

columns of downflexures; 5) The BSR separating the opposite flexed horizons occurs at a subsurface depth theoretically equivalent to that of the base of the methane-hydrate 

stability field; 6) The recorded vertical relief of both the 

domed and downflexed horizons increases with subsurface 

depth; 7) At some VAMP's, vertically beneath the column 

of downflexures a shallow depression is recorded in the 

surface of the underlying igneous oceanic crust. 

Based on these observations, and others noted elsewhere 

in this paper, VAMP's are not interpreted as deformational 

structures but rather as acoustic artifacts or pseudostructures 

oflarge size (>1 km across). They are thought to be caused 

by the vertical superposition (duplexing) of a velocity pullup 

over a more prominent velocity pushdown. Following the 

suggestion of Scholl and Cooper (1978), VAMP structures 

are thus hypothesized to record the localized occurrence of 

massive hydrate deposits (> 10-20 percent of pore space 

occupied by hydrate) of anomalously high acoustic velocity 

(pull up) overlying and sealing gaseous sediment of anomalously low velocity (pushdown). Minshull and White (1989) 

reasoned similarly that acoustic pseudostructures from the 

Gulf of Oman which are akin to Bering Sea VAMP's, are 

pods of gas entrapped beneath localized concentrations of 

hydrate deposits. 

In this paper we summarize information about 

VAMP's occurring within the Bering Sea Basin and draw 

inferences concerning their probable origin as hydrate-related structures and about the volume of methane occurring in them. It is recognized that although the acoustic 

characteristics and field relation of VAMP's are consistent 

with vertically superimposed methane-hydrate and methane-gas accumulations, the concept has not been rigorously field tested nor "groundtruthed" by drilling. 

HDL AND BSR'S 

Regional heatflow data (Cooper and others, 1987) and 

the temperature/pressure constraints of the methane-hydrate stability field (Kvenvolden, 1993, this volume) imply 

that only the upper 400-500 m of the basin's 2- to 12-kmth}ck sedimentary section can contain methane-hydrate deposits. Using the regional thermal gradient of 55°C/km for 

the Aleutian and Bowers Basins (Cooper and others, 

1987), the corresponding temperature at a depth of 450 m 

is approximately 25°C. In these basins, deeper sediment is 

too warm to accumulate hydrate deposits, and interstitial 

methane in excess of pore-water solubility can only exists 

as free gas (Kvenvolden, 1987, 1993). The roughly 450-ftthick surficial section that can contain methane-hydrate deposits is defined as the hydrated layer (HDL). The actual 

thickness of the HDL varies laterally because the basin's 

geothermal gradient is not everywhere the same. The HDL 

can theoretically include either disseminated or nonmassive deposits (>10-20 percent saturation of pore space), 

massive hydrate deposits (> 10-20 percent), or no hydrate 

deposits at all. Hydrate deposition within the HDL depends upon the occurrence of methane in excess of porewater solubility. 

The occurrence of lower velocity, potentially gas-bearing sediment beneath higher velocity, potentially hydratebearing basal beds of the HDL should, in theory, generate 

a high-amplitude, phase-inverted reflection event (see 

Shipley and others, 1979; Kvenvolden, 1993, this volume; 

Lee and others, this volume). This prominent reflection 

hori~on should follow the subsurface isotherm marking the 

base of the hydrate stability field and thus roughly parallel 

the isotherm that is coincident with the overlying seafloor. 

A reflection horizon marking the base of the HDL should 

therefore be an example of a bottom simulating reflector 

(BSR) (Scholl and Creager, 1973). 

Cooper and others (1987) emphasized that in the Bering Sea not all BSR's are linked to the occurrence of hydrate deposits. Drilling on Deep Sea Drilling Program 

(DSDP) Leg 19 determined that a prominent BSR is also 

generated by the diagenetic alteration of diatomaceous deposits, in particular the downsection conversion of biogenic silica, opal-A, to opal-CT (Scholl and Creager, 1973; 

Hein and others, 1978). As a note of historical interest, the 

expression "bottom simulating reflector" was coined to describe the seabed-emulating reflection horizon generated 

by the opal-CT diagenetic front that is widely recorded in 

the Bering Sea (Scholl and Creager, 1973). Below the 

flanking slopes of the Aleutian Basin, the gas-hydrate BSR 

(BSR-GH) occurs at a shallower subsurface depth than 

the silica-diagenetic-boundary BSR, (BSR-DB) of Cooper 

and others (1987). 

The sea floor of the Aleutian and Bowers Basins is 

virtually horizontal and parallel to the stratification of underlying deposits. Thus, except where differential compaction or slight structural or depositional tilting has occurred, 

all BSR's parallel bedding, and their identification as distinct reflection horizons is difficult. On figure 2, two BSR's 

are identified that crosscut basin-floor deposits tilted by differential compaction over a deeply buried basement high 
COP Ul Ul Ul Ul m m m m m m m m m -..J CD lD (Sl ru w COP _.,.. Ul m -..J (Sl (Sl (Sl (Sl (Sl (Sl (Sl (Sl (Sl (Sl (Sl (Sl 

(Sl (Sl (Sl (Sl (Sl (Sl (Sl (Sl (Sl (Sl (Sl (Sl 

3 3 3 3 3 3 3 3 3 3 3 3 

4.00 _l_ _L 4.00 

5.00 1 rSEA FLOOR, 3855 m 5.00 

Hydrate, =- __ -~ ---- ~- - ---- _______ ---c -~ ~~~=:,:~ :_,~ __ .- __ ,----- Hydrate, BSR-GH~ ~. ::::__:___-=-===--~: ---=--=-=-~ = .=..; __ -:..::: .--:.- '"'------ --~-:-:-: ~-- ~~ --=~~BSR-GH 

~ B~~~os'~ ICT -~- ~~= --~ -----C _ ---=---~-~ ---- -- --~-=---~~-----_~_=_ _-; . Opai-C;,· oo -- -: ~~~~-:.: _:-:~ ~,-=-- -:=~ ~:- :::.., .. -·------=----- ~ - ,...__ BSR-DB ::-=~--=- ---- - - -- .........-.....---:- =- - --- - ---~-~.- -=:-- ~~~~ -- ---:. ..... ---- ---

. ;~('~ ) __ -----'-- ' 7.00 

6.00 

-· 9.00 

0 

Figure 2. Migrated relative-amplitude plot of section of multichannel seismic reflection line L-44 (1976). Boxed area is velocity and amplitude structure (VAMP) 5820, 

which is shown ' in larger scale on fi gures 7 and 8. Other VAMP's are indicated by 

vertical arrows. Line of section is located on figure 5 (see also fig. 6). Both an 

upper gas-hydrate bottom simulating reflector (BSR-GH) and an inferred deeper 

silica-diagenic-boundary bottom simulating reflector (BSR-DB) (opal-CT) are identified (see Cooper and others, 1987). The BSR's cut across differentially tilted beds 

.· ..... .. '·· ~-·_·_· .. · RIDGE B 

~i~~- ·--·.;;.;, . . · .... . ·:;~~~--~:-~ 

. ~ .~ 

25 KILOMETERS 

7.00 

8 . 00 

- 9.00 

draped over buried seamount of Ridge B (Marlow and others, 1987) that rises above 

Vitus Arch (see fig. 5). No VAMP structures are localized over Ridge B. Insert 

di agram displays two reflection traces documenting that polarity of hydrate BSR is 

negative with respect to positive reflection event from sea floor. The deeper, positive-polarity BSR-DB is presumably top of latest Miocene and older strata or earliest Pliocene siliceous mudstone deposits, which exhibit weak internal reflectivity 

downsection. 

UJ 

UJ 

.,. 
VELOCITY AND AMPLITUDE STRUCTURES IN THE BERING SEA BASIN 335 

(Ridge B). The upper BSR, which is recorded at a two-way 

reflection time of 0.45-0.55 s, can be traced laterally as a 

prominent reflection event that tops the downflexed columns of VAMP structures. Adopting an average interval 

velocity of 1.75 km/s based on averaging the drilling results 

at Site 190 (Creager and others, 1973) and multichannel 

seismic reflections (MCS) stacking velocity analyses, the 

reflection time of 0.45-0.55 s corresponds to a subsurface 

depth of approximately 400-480 m. In the Aleutian and 

Bowers Basins this depth matches well with that of the 

theoretical base (roughly 450 m) of methane-hydrate occurrence (in other words, the base of the HDL). 

The upper BSR is also a negative-polarity reflection 

event with respect to that of the overlying sea floor (fig. 2). 

The shallower of the two BSR's is thus interpreted as a 

BSR-GH, most likely (see discussion below) generated by 

the occurrence of low-velocity, gas-bearing sediment beneath the base of the HDL. The prominent velocity pushdowns at VAMP's support this notion. However, the 

amount of free gas associated with a BSR-GH is poorly 

understood (Max, 1990; Miller and others, 1991; Singh 

and others, 1993; Rowe and Gettrust, 1993; K venvolden, 

1993; Carson and others, 1993; Bangs and others, in press) 

and the presence of much gas is questioned by Hyndman 

and Spence (1992). Throughout the Bering Sea Basin, the 

upper BSR is most conveniently identified as a prominent, 

polarity-negative horizon separating the base of the acoustic pullup from the top of the velocity pushdown (figs. 3, 

4). Beneath the Aleutian Basin the hydrate BSR is laterally 

discontinuous, but it is particularly prominent in the immediate vicinity of VAMP's and related acoustically anomalous structures (Rearic and others, 1988) 

The deeper BSR identified on figure 2 is presumably 

the opai-CT or BSR-DB diagenetic front. This reflection 

horizon is coincident with the top of the indurated mudstone of Miocene age reached at a subbottom depth of 615 

mat DSDP Site 190 (fig. 1; Creager and others, 1973). A 

relatively high acoustic velocity of 2.6-2.9 km/s is characteristic of the indurated mudstone (Cooper and others, 

1987). Unless otherwise stated, the notation "BSR" as 

used elsewhere in this text and on illustrations refers only 

to the BSR-GH or hydrate BSR. 

HISTORY OF VAMP OBSERVATIONS AND 

INTERPRETATIONS 

In the late 1960's and early 1970's, reconnaissance reflection profiling with low-power, single-channel seismic 

(SCS) technology first recorded anomalous structures beneath the abyssal floors of the Aleutian and Bowers Basins. 

These early profiles were collected by the U.S. Geological 

Survey and the U.S. Navy operating from the research vessels Davis, Bartlett, and Bent. Figure 3 exhibits examples 

of these early VAMP recordings. The high vertical exaggerations of these records emphasize the upper dome structure 

but in particular the defining characteristics of VAMP'sthe slender columns of concave horizons starting at a subseafloor depth of 400-500 m. The reconnaissance studies 

established that VAMP's are numerous (hundreds) but tended to be most abundant beneath the central region of the 

Aleutian Basin (figs. 1, 5). 

The first digital recording of VAMP structures was acquired in the middle 1970's, in particular along two MCS 

lines, one collected by Exxon Exploration and the other, 

line L-44 (figs. 6, 5), by the U.S Geological Survey from 

the RIV S.P. Lee. Both lines crossed the north-south width 

of the Aleutian Basin (Cooper and others, 1987). Additional industry (proprietary) MCS data cover some parts of 

the northernmost floor of the Aleutian Basin (Worrall, 

1991). The entire network of nonindustry MCS data available for acoustic analyses and mapping of VAMP's covers 

approximately 2,000 km2 (fig. 6). MCS data collected by 

the RIV S.P. Lee in 1976 verified evidence from older analog SCS records that many of the downflexed columns 

were capped by a prominent, phase-inverted reflection horizon (in other words, a BSR) (figs. 2, 4, 7, 8). 

Not shown on figure 6, which displays tracklines of 

digitally recorded reflection data available for study, are the 

locations of an eclectic collection of low-power analog SCS 

profiles recorded by various institutions and agencies between the mid-1960's and 1986. In 1977, a reconnaissance 

study was carried out from the RIV Sea Sounder, then operated by the U.S. Geological Survey, to specifically learn 

more about the geologic setting and acoustic structure of 

VAMP's (Cooper and others, 1979). During the course of 

this exploration, SCS (180 kJ sparker) reflection profiles, 

geopotential data, cores of surface sediment, and heatflow 

data were gathered in target areas of the Aleutian Basin. No 

additional fieldwork focusing on the origin and implication 

of Bering Sea VAMP's has since been carried out. 

In 1986 and 1987, a USGS program of GLORIA sidescan imaging conducted from the RIV Farnella included 

the collection of nearly 20,000 km of digitally recorded, 

low-power (160 in3 airgun) SCS data. The Farnella survey covered the entire area of Bowers Basin and most of 

the Aleutian Basin (fig. 6). The tracklines, which are nearly parallel, are spaced roughly 30 km apart and generally 

trend northwestward. These profiles provide regional information on the stratigraphy of the late Cenozoic beds 

that contain the HDL and included VAMP's. Although the 

deeper sedimentary sequences are only indistinctly imaged, the Farnella SCS profiles supply regional stratigraphic information on pre-Pliocene deposits filling the 

Aleutian and Bowers Basins. 

FIELD OBSERVATIONS AND VAMP'S 

Except for their occurrence within the thick sedimentary sequence of the Gulf of Oman (northwestern Indian 
336 THE FUTURE OF ENERGY GASES 

BN-204 ARCHED HORIZONS ++ f + 3860 M 5 

HDL[W~~~~~E 

BS 

VELOCITY PULLDOWNS 

I ~ 

! .. 0 50 . . . . . - _; -------~ ~- -- ._! ....L-'---......_.....6__,1 ·· .. .. ,. :· -. :_· .. i.'-:..: 

B-80 

3880 

E \ 

VERTICAL EXAGGERATION-50:1 ::_ ;: 

KILOMETERS . . . <?~· ~:~ : ~ .. r -. " ' or · .. ·: •• • .. :': .• 

Sea floor 

.. 

~ !! : ;! ~ ~~ ~~~~~~-

:::.;.: . 

0 5 10 

VERTICAL EXAGGERATION-9:1 

KILOMETERS 

6 

7 

Two-way reflection, 

·· . in seconds 

HDL 

6 

7 

in seconds 
VELOCITY AND AMPLITUDE STRUCTURES IN THE BERING SEA BASIN 337 

Ocean; White and Louden, 1983; Minshull and White, 

1989), VAMP structures are not c~~monly reported outside of the Bering Sea Basin. The bulk of the information 

concerning VAMP structures and the HDL has been acquired as a by-product of efforts to explore the framework 

geology of the Bering Sea Basin (fig. 1; Cooper and others, 1987) or to sonographically image its abyssal floor 

(Rearic and others, 1988, Huggett and others, 1992). The 

great abundance of VAMP's recorded in the Bering Sea 

Basin implies a history of basin evolution and sediment 

infilling that has especially favored their formation (Scholl 

and Stevenson, 1987, 1990; Scholl and others, 1989). As a 

subject of research, the origin and geologic implications of 

VAMP's can thus be best pursued in the Bering Sea, in 

particular the Aleutian Basin. 

OCCURRENCE AND DIMENSIONAL 

CHARACTERISTICS 

VAMP's occur over a large region of the Aleutian and 

Bowers Basins. The area of occurrence is approximately 

400,000 km2 (-150,000 square statute miles), which is 

roughly equivalent to that of the states of the Utah and 

Nevada combined (fig. 1 ). The occurrence region of VAMP's 

falls largely within the Exclusive Economic Zone (EEZ) of 

the United States, but the western part of the occurrence 

region lies west of the 1867 Convention Line and thus within 

the EEZ of Russia (figs. 1, 6)(Rearic and others, 1988). 

Sufficient single-channel seismic reflection data exist in 

the Bering Sea to document that VAMP's are abundant. 

Rearic and others ( 1988) noted that acoustically "anomalous reflector zones" also occur widely. These VAMP-kindred structures exhibit one of the common attributes of 

VAMP's, typically evidence of localized zones of amplitude-enhanced reflection horizons (BSR-GH ?), but they 

lack a distinctive or narrow pushdown. The Rearic and others (1988) investigations established that the occurrence 

density of VAMP's increases toward the south-toward the 

bathymetrically deeper part of the basin floor (fig. 5). Their 

occurrence density is also high over the southwestern part 

of a deeply buried, northeast-trending basement swell, 

~ Figure 3. Examples of high vertical-exaggeration singlechannel reflection profiles collected in the early 1970's that were 

among the first to record velocity and amplitude (VAMP) structures. Arrows point to VAMP's; location of sections shown on 

figure I. HDL, hydrated layer; HDL, which is based on a thermal 

gradient of 50~0°C/km (see fig. 9), is the theoretical thickness 

of approximately 450 m of surficial sediment that in the Aleutian 

Basin can contain methane-hydrate deposits. BSR-GH identifies 

a prominent, presumably phase-inverted, bottom simulating reflector generated by the occurrence of free gas in sediment underlying the HDL, the basal beds of which are presumed to 

contain gas-hydrate deposits. 

termed Vitus arch by Cooper and others(l992). A number 

of seamounts occur along Vitus Arch; for example, Ridge B 

of figures 5 and 2. VAMP-kindred structures are also common over the southwestern part of Vitus Arch. 

Assuming that the SCS profiles sample the shallow subsurface with an effective beam width of one Fresnel zone, 

then for a water depth of 3,800 m, the individual VAMP's 

plotted on figure 5 occur somewhere below an area of seafloor approximately 1.0 km in width centered along the 

vessel's trackline. Correspondingly, the average occurrence 

density of VAMP's within the shaded area ( -150,000 km2) 

of the north-central basin floor outlined on figure 5 is 4.3 

VAMP's/100 km2 (213 VAMP's within a total swath area of 

5,000 km2

; Rearic and others, 1988). The range about this 

average, determined along trackline segments 250-400 km 

in length, is 0.3-9.7 VAMP's/100 krn2. In the northern area 

of figure 5 VAMP density is only about 21100 km2

, but to 

the south, toward deeper water, the occurrence density progressively increases to a regional value of about 7/100 km2. 

During the 1977 R/V Sea Sounder cruise, a 450-km2 area of 

the northern region was surveyed with a line density possibly adequate to determine the included VAMP density. Thirteen VAMP's identified within the surveyed area correspond 

to an occurrence density of about 3/100 km2 (Cooper and 

others, 1979), which compares favorably with that based on 

the R/V Parnella s SCS records. 

In the north-central area of the Aleutian Basin, where 

VAMP's are ubiquitous, Rearic and others (1988) compiled 

information on both the areal distribution and attributes or 

characteristics below the sediment-water interface of 246 

VAMP's occurring in the outlined and shaded area of figure 5 ( -170,000 km2). Although nearly three-fourths of the 

R/V Parnella s SCS data remain to be similarly examined, 

the statistical results from Rearic and others' (1988) study 

area (table 1) are representative of a major occurrence region of VAMP's and VAMP-kindred structures. 

Table 1. Velocity and amplitude anomaly (VAMP) dimensional 

characteristics. 

[Data are for VAMP's from outlined and shaded area shown in figure 5; data from 

Rearic and others, 1988] 

Characteristic 

(I) Mean depth to top of arched strata--------

(2) Mean depth to top of push-down----------

(3) Mean width of arched strata----------------

(4) Mean time-delay relief of pushdowns----

Numerical data 

360 ms• 

610 msb 

1.3 km (0.5-3.8 km) 

23 ms 

"If overlying sediment velocity averages I. 7 km/s, corresponding depth 

below the sediment-water interface is about 310 m. 

blf overlying sediment velocity averages 1.7 km/s, corresponding depth 

below the sediment-water interface is about 535 m. The reflection 

depth to the top of the pushdown is below that of the overlying 

bottom simulating reflector, which is typically recorded at 450-550 

ms (400-480 m). 
338 

o-fs 

BSR-GH 

THE FUTURE OF ENERGY GASES 

VAMP's 

.{ ~ 

STRATIGRAPHY 

INFERRED FROM DSDP 

SITE 190 

WITH 

T~DITES 

WITH 

DI.UOM 

OOZE 

QUATERNARY 

AND PLIOCENE 

DIATOMACEOUS 

SILTY CLAY 

SEMII>URATED 

-, , , 

2.:1 KY/S~ REFRACTOR 

MIOCENE 

MUDSTONE 

lssR-os 

I 

I 

.... 

KILOMETERS Two-way 

BELOW reflection, 

SEA FLOOR in seconds MASSIVE HYDRATE 5 

SEA FLOOR DE~OSITS 

HYDRATE 

BASE 0~-i~~'lilif//~~~~~ -/ 

ZONE'\. " ~ <ZZ:Z:> 

4111~ •• 0 ••• :•.·:· ··.·:·.· 

ZONE 

WITH 

POCKETS 

OF FREE 

GAS 

1--------~:-~:~~-;--------~-~---;:~--~:~-----~ ..... 

···.· 

... 

·.·.·· 

. . 

········ .:.·:.· ... ::.· . :• . ---...;.:.;.:..=~,.,·""; ==··="~--t 

~r. ..__ ··- ---~ 

--==-- ------- ------ --- --

1 

2 

KILOMETERS 

BELOW 

SEA FLOOR 

WITH 

T~DITES 

WITH 

DIATOM 

OOZE 

QUATERNARY SEM6 AND PLIOCENE N>URATED 

DIATOMACEOUS 1 

SILTY CLAY BSR-08 

, , , _::Ill , INDURATED 

2.:1 KM/S _./ I REFRACTOR 

MIOCENE 

MUDSTONE 

Two-way 

reflection, 

in seconds 

. . 

• 

.... 

Figure 4. Upper, Multichannel profile of two unarched velocity 

and amplitude (VAMP) structures in western part of Aleutian 

Basin (see fig. I for location). Stratigraphic and lithologic columns inferred from drilling results at DSDP Site 190 (figs. I and 

5) (Creager and others, 1973). Lower, Schematic model (adapted 

from Cooper and others, 1979) of VAMP structures showing 

thin, localized lenses of massive hydrate deposits at the base of 

the hydrate layer (HDL) overlying a prominent phase-reversed 

gas-hydrate bottom simulating reflector (BSR-GH) and localized 

columns of sediment containing free interstitial gas. Because velocity pullups are not recorded, massive hydrate deposits along 

line of profile probably occur only in basal 10-30 m of the HDL, 

and, on the basis of studies elsewhere, the saturation level probably does not exceed 20-30 percent. 
VELOCITY AND AMPLITUDE STRUCTURES IN THE BERING SEA BASIN 339 

A EXPLANATI 

VAMP SEISM 

LINE - 8..-/ 

Contours, km, on l-4~ .. /~ Igneous basement _,/ ,)(~.,~ 

/ 

//' 

1.. .... __ , 

ss"N 

_fLG . · .. - ? .... ___ .. ·· . . ·. ---:..o .• g... . . ... ...., ··. .. 

176"E 178"E 

Figure 5. A, Distribution of velocity and amplitude (VAMP) 

structures in the west-central sector of Aleutian Basin along the 

dominantly northwest-trending tracklines surveyed on R/V Farnella cruise F2-86 (Rearic and others, 1988). Occurrence density of VAMP's increases southward toward basin's bathymetrically deepest part and somewhat in the vicinity of the 

buried basement highs along the southwestern part of Vitus 

Arch (see fig. 2). Water depth of the abyssal floor is approximately 3,800 m, hence thickness in kilometers of basinal sedi-

'· ', ....... . '~-----

180" 

0 

-- 178"W 

ment can be approximated by subtracting 4 from structural 

contours on igneous crustal basement. If VAMP's are discrete 

podlike deposits of hydrate and gas, it is estimated that about 

12,000 VAMP structures underlie the abyssal floors of the Aleutian and Bowers Basins combined (see fig. I). B, Index map 

showing area of figure A with topographic contours showing 

outline of Aleutian Basin. Shaded and outlined box indicates region in which 246 VAMP's were mapped and characterized by 

Rearic and others ( 1988). 
180 176W 

500 

KM 

EXPLANATIO 

MULTICHANNEL OAt 

R/V LEE 

SINGLE-CHANNEL DATA 

R/V FARNELLA 

Figure 6. Trackline chart of available digitally recorded single-channel (RN Famella, I 986, I 987) and multichannel (RN S.P. Lee, 1976-1982) seismic 

reflection data from abyssal region of Bering Sea Basin. Location of seismic line L-44 also shown on figure 5. 
VELOCITY AND AMPLITUDE STRUCTURES IN THE BERING SEA BASIN 341 

COP 

5.00 

s.lim 

5.2110 

5.391-l 

s.sae 

5. "/Pil 

s. e~e 

6.00 

7.00 

HDL 

Ul 

-.....J 

Ul 

tSl 

3 

0 

Ul 

CXl 

tSl 

tSl 

3 

Figure 7. Velocity and amplitude (VAMP) structure 5820, located along a segment of multichannel seismic reflection line L-44 

(see figs. 5 and 2 for location). Plot is a standard common depth 

point (CDP) stack of 24-fold data. A migrated section is shown 

on figure 8 (see also fig. 2). Diffractions are "bow ties" that reUl 

CXl 

Ul 

tSl 

3 

Ul 

CD 

tSl 

tSl 

3 

COP 

5.00 

S.lllB 

5.2111'1 

5.390 

5. 41!0 

5.590 

SR-GH 5.71!0 

5.81lll 

5.91l0 

6.00 

6.Jil0 

6.Jil0 

6. 4~1"l 

6.7iltl 

6.920 

7.00 

5 KILOMETERS 

suit from plotting of unmigrated data that does not properly 

image the narrow velocity pushdown structure. BSR-GH denotes 

a negative-polarity reflection horizon identified as a bottom simulating reflector generated by free gas underlying sediment containing gas-hydrate deposits. 
342 THE FUTURE OF ENERGY GASES 

COP Ul Ul --.] --.] 

CD CD 

OJ CD 

3 3 

5.00 

5. I~>' 

5.2ilfl 

::.JNl 

<;: _ 4~~ 

5 - c ~~~~ 

o:_om'l 

s. g~e 

6.00 

6. I~.:' 

7.00 

Ul Ul 

OJ --..J 

ISl Ul 

ISl ISl 

3 3 

0 

I 

Ul 

OJ 

ISl 

ISl 

3 

Figure 8. Migrated seismic section of velocity and amplitude 

structure (VAMP) 5820 located along multichannel seismic reflections (MCS) line L-44 (see figs. 2 and 5 for location). Horizon A marks the top of an 8-ms velocity pullup, which is most 

pronounced at the hydrate-related gas-hydrate bottom simulating 

reflector (BSR-GH). The pullup is inferred to record a localized 

body of massive hydrate deposits, filling from 15 to 55 percent 

Ul 

OJ 

Ul 

ISl 

3 

Ul 

CD 

ISl 

ISl 

3 

5 KILOMETERS 

I 

COP 

5.00 

5. ~ 

5 . ~~ 

s. ~~ 

5.900 

5 . 100 

b.2llll 

t. mm 

of available pore space depending upon assumptions of the vertical distribution of hydrate concentration. Horizons B, C, and D 

exhibit the progressively accumulating time-delay effect of an 

underlying velocity pushdown, presumed to be caused by free 

interstitial gas below the BSR-GH. Horizon D is thought to be a 

silica-diagenetic-boundary bottom simulating reflector (BSRDB) (see fig. 2). HDL, hydrate layer. 
VELOCITY AND AMPLITUDE STRUCTURES IN THE BERING SEA BASIN 343 

STRATIGRAPHIC SETTING 

The Aleutian and Bowers Basins are underlain by a 

virtually undeformed sequence of mostly Eocene and 

younger sedimentary beds overlying igneous oceanic crust 

of Cretaceous or possibly earliest Tertiary age (fig. 2). Although the sedimentary sequence is as thick as 12 km 

(Cooper and others, 1987), in particular along the southern 

and northern borders of the Aleutian Basin, the typical 

thickness beneath the central basin region is 2-4 km 

(fig. 5). VAMP's have not been reported from the Komandorsky Basin, the geologically young, far western region of 

the Bering Sea Basin (fig. 1; Baranov and others, 1991). 

As noted, in the Aleutian Basin the base of the upper 

domed structure of VAMP's and the position of the phaseinverted BSR, occur commonly at an estimated depth of 

400-500 m. It can be inferred from the sedimentary sequence drilled at DSDP Site 190 (fig. 1) that the upper or 

domed part of the VAMP structure occurs within a sequence of diatom silty clay (see fig. 4). The base of the 

domed reflection horizons-the BSR-appears to correspond roughly with the downsection transitions (375 m at 

Site 190) from weakly indurated diatom and silty turbidite 

beds to an underlying sequence of semi-indurated, wormburrowed, and more richly diatomaceous silty clay. The 

entire 630-m-thick sequence of diatom silty clay includes 

.ash layers and turbidite beds; however, these components 

are apparently more abundant, and the turbidite beds 

coarser, in the upper part of the drilled section. 

The turbidite deposits penetrated at Site 190 are part 

of a basinwide sequence of diatomaceous-rich terrigenous 

beds that flooded the basin floor beginning in the late Cenozoic (Ewing and others, 1965; Cooper and others, 

1987). Because Site 190 is located along the western edge 

of the Aleutian Basin and over a buried basement high 

(Scholl and Cooper, 1978; Cooper and others, 1979, 

1987), the turbidite sequence is thin with respect to the 

turbidite sequence underlying the central basin area to the 

east, where the sequence thickens to more than 1 km. Presumably, as is globally typical of other ocean-margin basins, the diatomaceous-rich terrigenous body accumulated 

in part as a consequence of glacially induced fluctuations 

in sea level and the accelerated flushing of terrigenous material to the ocean basins. Based on the appearance of icerafted detritus in north Pacific deep-sea sediment (Rea and 

Schrader, 1985) and the beginning of loess accumulation 

in interior Alaska (Westgate and others, 1990), rapid turbidite deposition in the Bering Sea Basin should have 

been well established by 2.5-3.0 Ma. 

Paleontologic data and sediment accumulation rates 

indicate that at DSDP Site 190 the age of the basal finer 

grained and more diatomaceous beds of the turbidite sequence is somewhat older. Most probably, initial deposition of the upper turbidite sequence began in early 

Pliocene time at 4-5 Ma. At Site 190, the upper turbidite 

beds unconformably overlie an indurated section of mudstone draped over a buried seamount or basement high. 

The mudstone regionally exhibits a relatively high acoustic velocity of about 2.7 kmls (fig. 4; Cooper and others, 

1979, 1987). The top of the mudstone section appears to 

be a silica-diagenesis (opal-CT front or BSR-DB) boundary rather than a chronostratigraphic horizon. Limestone 

beds in mudstone recovered at DSDP Site 190 enclose diatoms of middle Miocene age. However, on the basis of 

the implications of regional DSDP drilling results, the top 

of the mudstone sequence adjacent to the buried high at 

Site 190 is probably of latest Miocene or perhaps earliest 

Pliocene age (Creager and others, 1973 ). Little else is 

known about these mudstone deposits and older underlying beds., which on relative amplitude plots exhibit poor 

internal reflectivity (figs. 2, 7, 8). Inferences about the age 

and lithology of the older Tertiary deposits of the Aleutian 

Basin are summarized by Scholl and others (1986 ), Cooper and others (1987, 1992), and Worrall (1991). 

GEOCHEMICAL AND THERMAL FLUX 

On the basis of the examination of seven, 2-m-long 

gravity cores, which were specially collected for shipboard 

geochemical analyses, the upper layer of bottom sediment 

exhibits a downward gradient of increasing concentration 

of pore-water methane of biogenic origin (Cooper and others, 1979). The gradient may be slightly higher in the vicinity of VAMP's than away from them. Along the short 

length of the cores, no evidence was found for a surface 

flux of thermogenic gases. However, considering that the 

sampling density is 1 core/60,000 km2 of central Aleutian 

Basin floor, only conjectures are justified concerning the 

flux of gaseous hydrocarbons across the sediment-water 

interface-either at or away from VAMP's. However, as 

noted by Cooper and others ( 1979) the recording of disrupted reflection horizons in the shallow subsurface section (upper 100-200 m) overlying VAMP structures may 

be evidence that venting occurs at VAMP structures. Also, 

lateral disruptions in reflection-horizon continuity may signal localized deposition of denser hydrate deposits in the 

upper part of the HDL. 

Thirty-one heatflow measurements are available from 

the central region of the Aleutian Basin (Cooper and others, 1987). On the basis of these determinations, the basinwide average thermal flux is 1.44 heatftow units (1 

HFU=l.O microcalories/cm2/s, fig. 9). Langseth and others 

(1980), using basically the same data, calculated an average flux of 55 m W /m2. The corresponding thermal gradient is relatively high, 50-60°C/km. Cooper and others 

(1992) noted that locally the thermal flux is higher over 

the south-central part of Vitus Arch, a possible reflection 

of early Tertiary crustal generation along this backarc 

basement swell. As noted, VAMP-kindred structures are 
\, /\ //~~ , ___ > 

(.-1713 

I 

+1.38 \ 

~.. ~ ~ •1.25 •1.63~ ~ \ +1.66 \"-~ 

1.97 ·~ (+1.44 +1.39 '1.0[;"-'(/1 \ 

2.35 • ~ ~ 1.41 • 

1

"

38 ---"" 1z '\ ~ + 1.2~ VAMP-++ 1.16 + 1.49 \_~ P,(, \_ 

• 3.21 ) ) .. 

0 

+ 1.50 .1.14 1.0 0 '-'\__-:;·:'--~~ 1.68 I + 1·81 \ 11 0 ·+ (_? ',, 3 32 ~ . 1.93 { 

• ,'v 1.71·•1.49- + 1.30 + 1.71 /~ 

' \\ +1.09 .r-------- +1.39 +1.60 : " \~ ,.ooO "'- o l.NNAK 

~ ~ k~- ___)~ ~1 50 0 90 'PLATEAU + ..?--_,..-1.92 ++ 'ib • + • DSDP ~+1 11 

1.55 2.10 184 71- . ' -..._ +1.58 rt' ~ 

~ ;-~ \ 1.00 ;· . !) ) r} ~,.,. __ t/~ ~ :x:~~ATION ~ ~~" __ __.-2 4~!o,- ~-~ 

-2.00- HEATFLOW r!J'V~~ '-~" , 

~._ • mi~~oo-- r_e;;.- [1 hfu=1 microcalorie/cm2fs] ~, ~ ~ 

Figure 9. Heatftow data (in heatftow units, hfo) from various sources summarized by Cooper and others(l987). The corresponding basinwide geothermal gradient for Aleutian and Bowers Basins is 50-60°C/km, sufficient to generate thermogenic gases at subsurface depths as shallow as 2 km. Water 

depth in meters. 
VELOCITY AND AMPLITUDE STRUCTURES IN THE BERING SEA BASIN 345 

concentrated along this warm sector of the arch (Rearic 

and others, I 988). 

ACOUSTIC ANALYSES AND 

PROPERTIES OF VAMP's 

GENERAL INFORMATION 

In 1976, 1840 km of 24-fold common-depth-point 

(CDP) MCS data were acquired by the RN S. P Lee using 

a 24-channel, 2,400-m-Iong hydrophone streamer and a 

tuned source array of five airguns (approximately 1,325 in3 

at 2,000 psi). MCS line L-44 of the 1976 data set (figs. 5, 

6) crosses the north-south width of the Aleutian Basin and 

records a number of VAMP's, several examples of which 

are shown on figure 2. Data processing for the relative amplitude display of figure 2 includes spherical divergence 

gain correction, spiking deconvolution, velocity analysis, 

stack, migration, and bandpass filter. Migration was necessary to properly image the VAMP velocity pushdowns. 

Many of these pseudosynclines have buried foci and appear as "bow ties" on unmigrated displays (fig. 7) 

On figure 2, the prominent structure at VAMP 5820 

shows both the velocity pullup, attributed to a velocity enhancement caused by an increase in either hydrate concentration or thickness or both, and the more prominent 

underlying pushdown, attributed to a low velocity gaseous 

zone. A prominent reflector at the base of the upwardarched horizons exhibits a negative polarity with respect 

to that of the sea floor (see insert fig. 2). This distinctive 

horizon is interpreted to be a BSR generated by the occurrence of free gas in sediment underlying the base of the 

HDL (see, for example, Shipley and others, 1979; Miller 

and others, 1991; Singh and others, 1993; Rowe and 

Gettrust, 1993; Carson and others, 1993; Bangs and others, in press). 

Adjacent to VAMP 5820, the BSR can be traced within 

flat-lying deposits to the sediment-draped basement high 

(Ridge B; Marlow and others, 1987) at CDP 6600 on figure 2. Here the BSR reveals itself by crosscutting bedding 

planes tilted by differential compaction. The slight shallowing of the BSR over the Ridge B most likely reflects a 

localized increase in subsurface temperatures caused by the 

elevated position of the igneous basement. After correction 

for spherical divergence, the amplitude of the BSR reflection in the vicinity of the ridge is approximately 60 percent 

of that of the overlying seafloor. At VAMP 5820, the amplitude ratio is approximately 50 percent. The recorded 

amplitude brightness of the BSR varies considerably, and 

in many places along the section of line L-44 (fig. 2) the 

reflective amplitude is much lower than that of the seafloor. 

Although tuning and interference between closely spaced 

parallel reflections affect the recorded amplitude, the lateral variability may signify horizontal changes in either the 

hydrate concentration at the base of the HDL or the occurrence of underlying free gas. 

The amount of gas hydrate filling pore space can be 

estimated by measuring sediment-layer interval velocity 

(Vp), which increases with increasing degree of hydrated 

saturation (percentage of pore space filled with gas hydrate) (Miller and others, I 991; Hyndman and Spence, 

I 992; Bangs and others, in press). Similarly, the presence 

of free· gas below the BSR is indicated by a significant 

drop in Vp (Domenico, 1976, Singh and others, 1993; Carson and others, 1933; Bangs and others, in press). Because 

the error involved in calculating interval velocities with the 

Dix (1955) equation is inversely proportional to the ratio 

of the thickness of an interval of sediment to its depth 

below the sediment-water interface (Hajnal and Serada, 

1981), existing MCS data cannot accurately measure Vp 

and the inferred hydrate saturation within the HDL. The 

Dix ( 1955) equation calculates the interval velocity for reflectors from a sequence of flat-lying, parallel layers with 

small offsets. The uncertainty in Vp for the -450-m thickness of the HDL is greater than ±300 m/s, which implies 

that the thickness-average hydrate saturation in the HDL 

could vary from 0 to 50 percent. The error range is even 

larger when assuming that hydrate occurrence is concentrated primarily in the lowermost beds of the HDL. The 

consistency of dozens of velocity analyses establishes that 

the average interval velocity of I ,800 m/s calculated for 

the HDL along MCS line L-44 (fig. 2) is much more than 

±300 m/s. Nonetheless, small lateral variations in calculated stacking velocity may be partly due to seismic resolution problems and cannot with any certainty be attributed 

solely to lateral changes in hydrate saturation or lithology. 

VELOCITY ANOMALIES AND ESTIMATES OF 

HYDRATE AND GAS CONCENTRATION 

Velocity pullups and pushdowns associated with 

VAMP's provide a feasible method to calculate lateral velocity changes that can be ascribed to changes in hydrate 

saturation and volume of interstitial gas. Measured above 

the BSR, the magnitude or relief of the velocity pullup at 

VAMP 5820 is 8 ms (fig. 8). It is assumed that the sediment 

involved is flat lying and that the VAMP structure is caused 

entirely by lateral velocity changes. The pullup begins at 

Horizon A, indicating that assumed denser hydrate occurrence is confined to the lower 200 ms ( -170 m) of the 450-

ms-thick HDL. If a velocity of approximately 1.75 krn!s is 

assumed for the lower part of the HDL at some distance 

away from the VAMP structure, then a lateral velocity increase of 4 percent would create the observed 8-ms pullup 

beneath VAMP 5820. This calculation is insensitive to the 

actual velocity value assumed. 

The effect of hydrate saturation on V p can be calculated 

using a three-phase, time-average equation (see Miller and 
346 THE FUTURE OF ENERGY GASES 

others, 1991 ). For a 170-m-thick sequence of lower HDL 

Sediment taken to have a minimum average porosity of 60 

percent (range is approximately 75-60 percent), a 4-percent 

velocity increase can be caused by a 10 percent increase in 

average hydrate saturation (in other words, with respect to 

flanking areas, I 0 percent more of the total available pore 

space is filled with hydrate at the VAMP). Where a prominent BSR is recorded, the hydrate saturation in the lower 

10-30 meters of the HDLimmediately adjacent to the VAMP 

pullup structure is estimated by analogy with other areas to 

range from 10 to 30 percent (Miller, 1991; Hyndman and 

Spence, 1992; Kvenvolden, 1993, this volume; Bangs and 

others, in press). If a conservative estimate of 5 percent 

background saturation (see, for example, Hyndman and 

Spence, 1992; Carson and others, 1993; Bangs and others, in 

press) is applied to the entire 170-m-thick section involved 

in the cumulative pull up, then the average hydrate saturation 

in these beds is 15 percent of available pore space. 

Although hydration should occur throughout the HDL 

(Kvenvolden and Barnard, 1983; Kvenvolden, 1993), 

where vertically migrating or diffusing methane nourishes 

hydrate formation, a circumstance which is thought to 

occur at VAMP structures (see below), hydration mainly 

takes place at the base of the HDL (Hyndman and Davis, 

1992). It is likely, therefore, that pore-space saturation is 

highest immediately above the BSR and trails off in concentration upward (see, for example, Max, 1990, and 

Hyndman and Davis, 1992). This expectation may be verified by the observation that pullup arching increases in 

amplitude downward (figs. 3, 8). If, for example, hydrate 

deposition at VAMP 5820 is mainly concentrated in the 

basal 50 m of the HDL, then to achieve the 4-percent relative velocity pullup, hydrate saturation within the HDL 

could be as much as 34 percent over background saturation. If the average background saturation in the lower 

beds of the HDL is 10-20 percent, then basal hydrate saturation at VAMP 5820 is approximately 45-55 percent. 

A similar approach can be taken to analyze free gas 

accumulations beneath the HDL at VAMP structures. Again 

it is assumed that the "synclines" observed at VAMP's are 

entirely caused by a low velocity zone and no structural 

component is involved. Domenico (1976) and Singh and 

others (1993) demonstrated that if as little as 2 percent of the 

pore space (sediment porosity=60 percent) below the base of 

the HDL is filled with gas, then the in-place Vp would be 

lowered from 1. 7 to 1.3 km/s. For every 10 vertical meters of 

gaseous sediment, this velocity drop increases two-way traveltime to underlying reflection horizons by 3.0 ms. 

Figure 8 documents that the time-delay relief of the 

downflexures increases from a 1 O-ms pushdown at horizon 

B, to 25 ms at horizon C, and 80 ms at horizon D. Several 

factors are involved in considering the implication of these 

readings. For example, the time-delay relief of the velocity 

pushdown must be based on the traveltime of primary rather 

than internal (peg leg) reflection events. Because horizons 

B, C, and D are each regional in extent and prominent in 

recorded amplitude, they are presumed to be primary reflections from lithologic elements acoustically detected by only 

one-roundtrip ray path through the low velocity zone. For 

example, horizon D is presumably the top of the mudstone 

sequence, which is also a prominent silica diagenesis ·BSRDB (fig. 2). Where a velocity pushdown underlies a pullup, 

measurement of the time delay of the pushdown includes 

the effect of the overlying pull up. The total time-delay relief 

of pushdown is thus the sum of the pullup and pushdown. 

The time-delay relief of the velocity pushdown also only 

measures the localized or relative increase in free gas with 

respect to immediately flanking areas. 

Adjacent to VAMP's, where the reflective amplitude 

of the BSR is low compared to that of the sea floor 

(fig. 2), the thickness of a gaseous zone below the HDL, if 

present, is probably only a few meters. However, on the 

basis of the implications of studies elsewhere, where the 

BSR amplitude is prominent, the thickness of gaseous sediment is probably between 10 and 20 m (Shipley and others, 1979; Miller and others, 1991; Singh and others, 1993; 

Rowe and Gettrust, 1993; Carson and others, 1993; Bangs 

and others, in press). As shown above, a 30-m-layer of >2 

percent gas saturation would create a 9-ms pushdown 

(30m x 3 ms/10 m) relative to flanking areas that contain 

little or no gas. Away from VAMP's, no acoustic measurement can be satisfactorily linked to either the saturation 

level or thickness of gas-charged sediment. It is assumed 

that thick (>10m) sub-HDL gaseous zones are localized 

only at VAMP structures. 

Although a small percentage of free gas significantly 

lowers the Vp, saturation levels greater than 2 percent have 

negligible additional effect (Domenico, 1976 ). Therefore, 

although the thickness of a zone of about 2 percent gaseous 

sediment can be calculated that would effect the observed 

9-ms delay, the actual upper percentage of gas saturation 

within the column cannot be constrained. The cumulative 

pushdown at VAMP 5820 is 80 ms; the calculated effective 

thickness of the corresponding column of gaseous sediment 

is thus -270 m. (80 ms x 10 m/3.0 ms). It is important to 

note that at most VAMP's for example those on figures 3, 4, 

and 8, the observed downsection increase in pushdown accumulates over a stratigraphic thickness of several hundred 

to more than 500 m. Accordingly, and presuming that no 

peg-leg reflection delays are involved, the actual column of 

sediment containing pockets of gas-charged sediment is 

much thicker than the effective thickness calculated270m in the example of VAMP 5820. 

DISCUSSION 

EVOLUTION OF HYDRATE BSR 

Bangs and others (in press) stress that pooling of gas 

beneath a BSR is an enigma because it seems unlikely to 
VELOCITY AND AMPLITUDE STRUCTURES IN THE BERING SEA BASIN 347 

them that the concentration of interstitial hydrate above 

the BSR, generally estimated at filling no more than 10-30 

percent of available pore space, would be sufficient to seal 

off vertically migrating fluids. Methane dissolved in rising 

pore fluids should pass undeposited through the HDL and 

vent to overlying basin waters. Bangs and others (in press) 

reason that BSR's record the temporary residence of interstitial gas trailing an upward-moving front of melting or 

disassociating hydrate deposits. 

In the Aleutian and Bowers Basins, deposition of the 

upper turbidite sequence, beginning most likely in earliest 

Pliocene time, should have caused a BSR to migrate upward through and in company with the thickening of this 

surficial unit. Over the central basin region, the upper diatomaceous turbidite pile accumulated at approximately 

250 m/m.y. (uncorrected for compaction effects). Deposition of these increasingly coarser grained and less waterrich beds would have enhanced subsurface geothermal 

warming and both the silica diagenesis and the flow of 

thermogenic hydrocarbons from the underlying mudstone 

section into the accumulating turbidite beds. In conjunction with rapid basin-floor sedimentation, both a hydrate 

BSR and an underlying opal-CT BSR-DB would have 

migrating upward at a rate of about 250 rnlm.y. 

VAMP FORMATION 

Within the HDL, conditions that localize the formation 

of unusually dense hydrate concentrations are hypothesized to cause the recording of the commonly observed 

domed horizons of VAMP structures (figs. 3, 7, 8). Acoustic arching caps 58 percent of the VAMP structures in the 

north-central Aleutian Basin (Rearic and others, 1988). As 

earlier calculated for VAMP 5820 (figs. 2, 8), average 

methane hydrate clogging of as little as a 20 percent for a 

170-m-thick section and to as much as 64 percent of available pore space for a 50-m-thick section can account for 

the observed acoustic arching of 8 ms. These calculations 

are sensitive to the thickness of hydrated HDL beds., the 

vertical distribution of hydrate saturation within them, and 

the background hydration levels in beds immediately surrounding the pullup structure. 

It is recognized that differential compaction over buried basement highs can contribute to the amplitude of the 

upper arched horizons of VAMP's (Cooper and others, 

1979). But Rearic and others ( 1988) determined that most 

VAMP's are not localized over basement-specific structural closures. Intriguingly, bathymetric and seismic profiles 

across VAMP's reveal that some of them are associated 

with a slight swelling or doming of the sea floor by a few 

meters (Scholl and Cooper, 1978; Rearic and others, 

1988). The gentle sea floor upwarps can be viewed as supporting evidence for the occurrence of localized bodies of 

massive hydrate within the HDL. For example, doming of 

the sea floor would be an expected consequence of slight 

differential compaction of turbidite and diatomaceous 

beds., which are strong and consolidate only slowly (Lee, 

1973) over a more rigid core of hydrate-cemented sediment in the lower part of the HDL. Because the density of 

gas hydrate is less than that of water (in other words, specific volume of gas hydrate is greater; Lewin and Associates Inc., 1983; Sloan, 1990), growth of a dense hydrate 

body can potentially occupy more space than the starting 

volume of pore-space water. Surface heave would accompany growth if rapid hydrate deposition prevented venting 

of the original volume of interstitial water available for 

conversion to hydrate. Arching of beds caused by differential compaction or heave lessen the calculated volume of 

hydrate, based on presuming that the relief of the domed 

section of VAMP's is entirely a velocity pullup effect. 

If the arched reflection horizons are caused by massive deposits of interstitial hydrate, then the pooling of gas 

beneath their central region can be ascribed to pore sealing. Similar to the hydrate BSR, VAMP structures must 

migrate upward in concert with depositional thickening 

and subsurface warming. On the basis of the stratigraphic 

section penetrated at DSDP Site 190, the top of the gascharged sediment at VAMP's may occur stratigraphically 

close to a downsection change from virtually unindurated 

to semi-indurated diatom silty clay (fig. 4). Speculatively, 

the change in induration might be linked to early sediment 

diagenesis promoted by the upward migration of the BSR 

(Hyndman and Davis, 1992) through the lower, finer 

grained beds of the turbidite sequence. 

In the underlying Miocene mudstone beds sediment 

diagenesis involved the solution-reprecipitation conversion 

of biogenic opal-A of the frustules of diatoms and other 

siliceous microfossil-taxa to opal-CT (Hein and others, 

1978) and at greater depth possibly to chalcedonic quartz 

or chert. Each of these conversions causes a reduction of 

rock volume and expulsion of water. At least the middle 

and late Miocene beds of the mudstone sequence were formerly richly diatomaceous (Scholl and Creager, 1973). 

Therefore, it is likely that rapid burial and warming of the 

mudstone in response to deposition of the turbidite sequence caused the equally rapid upsection migration of 

one or more silica diagenetic fronts, the BSR-DB's of 

Cooper and others ( 1987). 

Diagenetic alteration of siliceous mudstone beds embrittles them. Siliceous mudstone is readily fractured in 

structural settings (see, for example, Sadler, 1990). But at 

non-structural locations sediment-volume reduction in response to burial diagenesis should initiate microfracturing. 

If diagenetic microfracturing is accompanied by overpressures induced by rapid burial, the preferred orientation of 

the microfractures would be in the vertical plane (Snyder 

and others, 1983). Water liberated by opal diagenesis in 

conjunction with compaction-induced overpressures would 

likely hydrofracture brittle porcelaneous and cherty layers 
348 THE FUTURE OF ENERGY GASES 

(Redwine, 1981). Fracturing would favor the vertical migration of thermogenic gases and other petroleum fluids. 

Lateral and vertical variability in the siliceous, terrigenous, 

and calcareous content of the mudstone would presumably 

determine the concentration and vertical continuity of the 

microfractures. Where they are particularly abundant, the 

fractures would provide localized, high-permeability ascent conduits for gases and liquid hydrocarbons generated 

from the Miocene mudstone and older underlying beds. 

Relatively porous and permeable layers within the turbidite sequence occur at the base of the methane-hydrate 

stability field (Cooper and others, 1979, 1987). If VAMP's 

reflect the subsurface location of high-permeability ascent 

columns or zones for thermogenic methane, then these 

basal beds provide a suitable reservoir for the localized 

formation of massive hydrate deposits that initiate the 

VAMP-forming process. 

SOURCES OF METHANE 

Bottom water in the Aleutian Basin is presently well 

ventilated, but high surface-water productivity and rapid 

sedimentation favors the preservation of organic matter in 

bottom sediment. Lisitsyn ( 1966) reported the total organic 

carbon (TOC) content of surface sediment ranges from 0.5 

to I percent. Other data summarized by Cooper and others 

(1979) give a similar range of values for both surface and· 

subsurface deposits, including limited carbon isotope studies that imply methane in surficial sediment is largely of 

microbial origin. On the basis of these observations, some 

or much of the methane in potential hydrate deposits near 

the top of the HDL may mostly be of biogenic origin 

(Kvenvolden and Bernard, 1983; Kvenvolden, 1993, this 

volume). 

At Bering Sea DSDP sites, thermogenic methane occurs 

in increasing quantities with subsurface depth, as well as 

where higher heatflow has been measured (Claypool and 

others, 1973). The basin's heatflow is sufficiently high to 

cause generation of thermogenic methane and other petroleum gases at depths as shallow as 2 km and at even shallower 

depths in the warmer Komandorsky Basin (figs. I, 9; Cooper and others 1987). Rearic and others (1988) observed 

that some pull-downs begin at depths near I km, depths 

which are near or at the base of the upper diatomaceous 

turbidite unit. The beginning of pulldowns at these great 

depths implies the accumulation of vertically migrating 

thermogenic gas. As speculated above, thermogenic gases 

may reach the basin's upper sedimentary sequence via fracture pathways in underlying deposits of diagenetically altered siliceous mudstone. Because the thickness of sediment 

within the petroleum-generation window is large (>1 km), 

the quantity of vertically migrating gas available to nourish 

hydrate deposition at the base of the HDL and localized gas 

pooling in warmer underlying beds is potentially large. 

VAMP's appear to be most numerous over the bathymetrically deepest area of the south-central basin floor and 

VAMP-kindred anomalous structures over the southwestern 

part of Vitus Arch, which may be associated with an elevated heatflux. The abundance distribution of VAMP's can 

speculatively be connected to the basin's depocenter of finer 

grained and more organic rich sediment, to residual warming related to the early Tertiary formation of Vitus Arch, 

and, during the past 4-5 m.y., to deeper burial of older 

mudstone beds by deposition of the late Cenozoic turbidite 

sequence. If prior to the Pliocene the basin had poor circulation, enhanced preservation of organic matter would have 

been favored in deeper basinal areas. Regional information 

supports the chance that in the early Tertiary the Aleutian 

Basin (Bering Sea) had restricted deep-water water exchange with the north Pacific, a circumstance that would 

have improved the likelihood that oxygen-poor waters periodically occupied the Aleutian Basin floor (Scholl and 

Stevenson, 1987, 1990; Scholl and others, 1989). 

VAMP's have not been reported from the Komandorsky Basin, which is a geothermally warm and geologically 

young basin formed by intrabasin spreading in middle to 

late Miocene time (Baranov and others, 1991 ). The missing VAMP's may reflect the fact that pre-Pliocene deposits 

are thin (-500 m; Cooper and others, 1987) and thus so 

are the source beds needed to nourish dense hydrate deposition in near-surface turbidite beds. A contributing factor 

may be the basin's high heatflow, which is approximately 

3 heat-flow units on a basinwide average (Baranov and 

others 1991; fig. 9). Possibly, thermogenic gas generation 

was largely complete prior to the deposition of reservoir 

beds favorable to the accumulation of massive hydrate deposits. Owing to the basin's high thermal flux, the sedimentary deposits below about 500 m are thoroughly 

altered and cemented (Stewart, 1977), thus hindering the 

vertical venting of petroleum gases into cooler overlying 

turbidite reservoirs. 

VOLUME OF METHANE 

The occurrence area of VAMP's for the Aleutian and 

Bowers Basins is approximately 400,000 km2• Rearic and 

others, ( 1988) concluded that because the cross-sectional 

width of VAMP pull-downs falls within a fairly narrow 

range about a mean of 1.3 km (table 1), the acoustic anomalies causing VAMP's are generally circular in plan. Accordingly, the planimetric cross-sectional area of the typical 

VAMP cylinder is 1.3 km2 (1.3x106 m2). If VAMP's are 

simple columns, then, by using a conservative estimate of a 

basinwide occurrence density of 3 VAMP's/100 km2 (see 

above), at least 12,000 discrete pull-down structures exist 

in the Bering Sea Basin. 

The velocity pullups allow for a relative measurement 

of the amount of hydrate deposits at VAMP structures. If 
VELOCITY AND AMPLITUDE STRUCTURES IN THE BERING SEA BASIN 349 

only disseminated or nonmassive hydrate deposits occur in 

sediment immediately adjacent to VAMP's, the volume of 

hydrate at them can be used to estimate the total basinwide 

volume of massive deposits. For example, the 8-ms velocity pullup at VAMP 5820 (fig. 8) requires a 10-percent increase in average hydrate saturation in the lower 170 m of 

the HDL. By using a sediment porosity of 60 percent for 

these beds (Cooper, and others, 1979), the total hydrate 

increase at VAMP 5820 is equivalent to an -1O-m-thick 

column of solid methane hydrate (170 mx0.6 percentxO.lO 

percent) centered beneath the crest of the Vitus Arch. 

Many pullups are less prominent than that of VAMP 5820, 

but many others exhibit a relief of as much as 25-30 ms 

(fig. 3), which corresponds to a crest-centered solid-volume thickness of methane hydrate of 30-40 m. 

Assuming a basinwide mean pullup of 10 ms, the corresponding column of solid hydrate is 12.5 m thick. If, for 

simplicity, the geometry of the massive hydrate mass is 

described as a low cone, then the volume at a typical 

VAMP of a 2-km-wide, 12.5-m-high lens of solid hydrate 

is 0.013 km3. Multiplying this term by the 12,000 estimated VAMP structures (discussed above) gives a basinwide 

solid volume of massive methane hydrate of approximately 160 km3 (160x109 m3), probably the bulk of which resides in the lower beds of the HDL. Converting to free gas 

at standard temperature and pressure (temperature at BSR, 

-25°C, is effectively equivalent to that of standard room 

temperature) requires multiplying the volume of solid 

methane hydrate by 164 (see Kvenvolden, 1993, this volume). The volume of methane stored in dense hydrate deposits at VAMP's is thus 26xl03 km3 (26x10 12 m\ 

which is equivalent to about 930 Tcf (trillion cubic feet). 

The above estimate has meaning only if the hydrate 

body capping the VAMP pushdown structure is a simple 

lens- or cone-shaped mass. However, the planimetric 

cross-sectional form of the inferred massive hydrate deposits and underlying gas column, which is assumed to be 

circular, is unknown. The common recording of VAMPkindred acoustic structures (the wide and narrow anomalous zones of Rearic and others, 1988) implies that many 

recordings of VAMP's are fragmentary or out-of-plane detections of irregular masses of hydrate and gas that may be 

laterally extensive and connected to other accumulations. 

Thus, it is unlikely that the number of VAMP's provides a 

quantitative measure of the basinwide volume of massive 

hydrate deposits; however, the calculated volume is a useful low-end estimate of the amount of massive hydrate deposits in the Bering Sea Basin. 

Rearic and others (1988) found an average pushdown 

at VAMP's of 23 ms (table 1), which, as calculated earlier, 

is equivalent to a 77-m-thick column of sediment of which 

at least 2 percent of the pore space (60 percent porosity) is 

occupied by free gas. Presuming that VAMP's are circular 

in plan and 12,000 in number, then the volume of 

sediment containing at least 2 percent free gas in existing 

pore space is 1,200 km3 (12,000x1.3 km2x0.077 km), or 

1.2x1012 m\ which converts to 0.014x1012 m3 (2 percent 

of 60-percent pore space) of in-place gas under an hydrostatic head of approximately 400 bars. At atmospheric 

pressure and at 25°C (temperature at BSR), this later volume expands to 5.8x1012 m3, which is a volume of roughly 200 Tcf. This volume must be viewed as a minimum 

estimate because of the planimetric reasons noted above 

and because the lowest possible saturation and inplace 

pressure (hydrostatic) terms were used in calculating the 

volume of gas causing the pushdown. The volume of gas 

could easily be many times greater. 

By combining the estimates of hydrated- and free-gas 

accumulations, a minimum of 1, 100 Tcf of methane gas is 

potentially available from the Aleutian and Bowers Basins. 

Approximately 80 percent of this volume is provided by 

the hydrate cap and 20 percent from underlying interstitial 

gas, but the amount of free gas is potentially much greater. 

Not included in this estimate is methane occurring away 

from VAMP structures, either as disseminated hydrate deposits or a free gas underlying the BSR. 

At particularly large VAMP's (fig. 3), the cumulative 

pullup is much as 25-30 ms and the underlying pushdown 

in as much as 80-100 ms. Accepting that VAMP's are circular structures and of the dimensions used above, a conservative estimate of the volume of methane gas stored at 

a single larger VAMP is 8.0x109 m3 (0.3 Tcf). This volume of methane is comparable to that found in large gas 

fields. 

FUTURE RESEARCH DIRECTIONS 

Although the supposition that VAMP's are acoustic artifacts caused by the vertically superimposed hydrate and 

gas accumulations is consistent with theoretical and observational data, the concept has not been rigorously field 

tested nor "groundtruthed" by drilling. The deficiency of 

HDL- and VAMP-specific information at both regional 

and local scales presently thwarts progress in hydrate research in the Bering Sea Basin. Major advances in information are needed to accurately characterize and model 

the structure and formative processes of VAMP and 

VAMP-kindred structures, assess their basinwide resource 

implications, and unravel the geologic history of the Bering Sea Basin that uniquely favors the widespread formation of these structures. 

The major tasks of a nondrilling, hydrate-focused field 

investigation would be to: (1) regionally map the vertical 

and horizontal acoustic fabric of the HDL (the "blanket" of 

Max, 1990), (2) map in both depth and time domains the 

three-dimensional physical and acoustic fabric of specific 

VAMP's and VAMP-kindred structures, and (3) determine 

the relation of VAMP's and VAMP-kindred structures to ( 1) 

the stratigraphy of immediately surrounding and underlying 
350 THE FUTURE OF ENERGY GASES 

Cenozoic strata, (2) regional and local basement relief, (3) 

regional and local heatflow, and (4) the geochemical flux of 

fluids and organic and inorganic compounds across the sediment-water interface at and away from VAMP's. 

REFERENCES CITED 

Bangs, N.L.B., Sawyer, D.S., Golovchenko, X., in press, Free 

gas at the base of the gas hydrate zone in the vicinity of the 

Chile triple junction: Geology. 

Baranov, B.V., Seliverstov, N.I., Murav'ev, A.V., and Muzurov, 

E.L., 1991, The Komandorsky Basin as a product of spreading behind a transform plate boundary: Tectonophysics, 

v. 199,p. 237-269. 

Carson, B.G., Westbrook, G., and Musgrave, R., 1993, Cascadia 

margin: JOIDES Journal, v. 19, no. 2, p.ll-16. 

Claypool, G.E., Presley, B.J., and Kaplan, I.R., 1973, Gas analyses in sediment sample from Legs 10, II, 13, 14, 15, 18, 

and 19, in Initial Reports of the Deep Sea Drilling Project, 

v. 19: Washington D.C., U.S. Government Printing Office, 

p. 879-884. 

Cooper, A.K., Marlow, M.S., Scholl, D.W., and Stevenson, A.J., 

1992, Evidence for Cenozoic crustal extension in the Bering 

Sea Region: Tectonics, v. II, p. 719-731. 

Cooper, A.K., Scholl, D.W., and Marlow, M.S., 1987, Structural 

framework, sedimentary sequences, and hydrocarbon potential of the Aleutian and Bowers Basins, Bering Sea, in Geology and Resource Potential of the Continental Margin of 

Western North America and Adjacent Ocean Basins, Beaufort Sea to Baja California: Circum-Pacific Council for Energy and Mineral Resources, Earth Science Series, v. 6, 

p. 473-502. 

Cooper, A.K., Scholl, D.W. Marlow, M.S., Childs, J.R., Redden, 

G.D and Kvenvolden, K.A., 1978, The Aleutian Basin, Bering Sea-A frontier area for hydrocarbon exploration: Proceedings of the Offshore Technology Conference, 1978, 

p: 353-359. 

Cooper, A.K., Scholl, D.W., Marlow, M.S., Childs, J.R., Redden, 

G.D., Kvenvolden, K.A., and Stevenson, A.J., 1979, Hydrocarbon potential of Aleutian Basin, Bering Sea: American 

Association of Petroleum Geologists Bulletin, v. 63, 

p. 2070-2087. 

Creager, J. S., and others, 1973, Initial reports of the Deep Sea 

Drilling Project, v. 19: Washington D.C., U.S. Government 

Printing Office, 913 p. 

Dix, C.H., 1955, Seismic velocities from surface measurements: 

Geophysics, v. 20, p. 68-86. 

Domenico, S.N., 1976, Effect of brine-gas mixtures on velocity 

in an unconsolidated sand reservoir: Geophysics, v. 41, 

p.882-894. 

Ewing, M., Ludwig, W.J., and Ewing, J. 1965, Oceanic structural 

history of the Bering Sea: Journal of Geophysical Research, 

v. 70,p.4593-4600. 

Hein, J.R., Scholl, D.W., Barron, J.A., Jones, M.G. and Miller, J., 

1978, Diagenesis of late Cenozoic diatomaceous deposits 

and formation of the bottom simulating reflector in the 

southern Bering Sea: Sedimentology, v. 25, p. 155-181. 

Huggett, Q.J., Cooper, A.K., Somers, M.L., and Stubbs, A.R., 

1992, Interference fringes on GLORIA side-scan sonar images from the Bering Sea and their implications: Marine Geophysical Research, v. 14, p. 47-63 

Hyndman, R.D., and Davis, E.E., 1992, A mechanism for the 

formation of methane hydrate and sea floor bottom-simulating reflectors by vertical fluid expulsion: Journal of Geophysical Research, v. 97, p. 7025-7041. 

Hyndman, R.D., and Spence, G.D., 1992, A seismic study of 

methane hydrate marine bottom simulating reflectors: Journal of Geophysical Research, v. 97, p. 6683-6698. 

K venvolden, K.A., 1987, Gas hydrates offshore Alaska and westem continental United States, in Geology and Resource Potential of the Continental Margin of Western North America 

and Adjacent Ocean Basins, Beaufort Sea to Baja California: 

Circum-Pacific Council for Energy and Mineral Resources, 

Earth Science Series, v. 6, p. 581-593. 

---1993, Gas-hydrates-Geological perspective and global 

change: Reviews of Geophysics, v. 31, p. 173-187. 

Kvenvolden, K.A., and Barnard, L.A., 1983, Hydrates of natural 

gas in continental margins, in Walkins, J.S., and Drake, C.L., 

eds., Studies in Continental Margin Geology: American Association of Petroleum Geologists Memoir 34, p. 631-640. 

Langseth, M.G., Hobart, M.A., and Horai, K., 1980, Heat flow in 

the Bering Sea: Journal of Geophysical Research, v. 85, 

p. 3740-3750. 

Lee, H.J., 1973, Measurements and estimates of engineering and 

other physical properties, Leg 19: Initial reports of the Deep 

Sea Drilling Project, v. 19: Washington D.C., U.S. Government Printing Office, p. 701-719. 

Lewin and Associates Inc., 1983, Handbook of gas hydrate properties and occurrence: Technical Information Center, Office 

of Scientific and Technical Information, U.S. Department of 

Energy, Morgantown, West Virginia. 

Lisitsyn, A.P., 1966, Recent Sedimentation in the Bering Sea: 

Academy of Sciences of the USSR, Department of Earth 

Sciences, Commission of Sedimentary Rocks, Institute of 

Oceanology, p. 614 [Translated from Russian, Israel Program for Scientific Translations, Jerusalem, 1969] 

Marlow, M.S., Carlson, P.R., Dadisman, S.V., Rearic, D.M., 

Maple, E.J., and Parson, L.P., 1987, GLORIA side-scan and 

geophysical surveys of the central Bering Sea, in Hamilton, 

T.H., and Gallow, J.P., eds., Geological Studies in Alaska by 

the U.S. Geological Survey during 1986: U.S. Geological 

Survey Circular 998, p. 152-156. 

Max, M.D., 1990, Gas hydrate and acoustically laminated sediments: potential environmental cause of anomalously low 

acoustic bottom loss in deep-ocean sediments: U.S. Naval 

Research Laboratory Report 9235, Washington D.C., 68 p. 

Miller, J.J., Lee, M.W., and Huene, R.V., 1991, An analysis of 

seismic reflection from the base of a gas hydrate zone, offshore Peru, American Association of Petroleum Geologists 

Bulletin, v. 75, p. 910-924. 

Minshull, T., and White, R., 1989, Sediment compaction and 

fluid migration in the Makran accretionary prism: Journal of 

Geophysical Research, v. 94, p. 7387-7402. 

Rea, D. K., and Schrader, H., 1985, Late Pliocene onset of glaciation: ice-rafting and diatom stratigraphy of north Pacific 

DSDP cores: Paleogeography, Paleoclimatology, Paleoecology, v.49, p. 313-325. 
VELOCITY AND AMPLITUDE STRUCTURES IN THE BERING SEA BASIN 351 

Rearic, D.M., Williams, S.R., Carlson, P.R., and Hall, R.K., 

1988, Acoustic evidence for gas-charged sediment in the 

abyssal Aleutian Basin, Bering Sea, Alaska: U.S. Geological 

Survey Open-File Report 88-677, 40 p. 

Redwine, L., 1981, Hypothesis combining dilation, natural hydraulic fracturing, and dolomitization to explain petroleum 

reservoirs in Monterey shale, Santa Maria area, California, 

in Garrison, R.E., Douglas, R.G., Pisciotta, K.E., Isaacs, 

C.M., and Ingle, J.C., eds., The Monterey Formation and 

Related Siliceous Rocks of California: Pacific Section, Society of Economic Paleontologists and Mineralogists, Los Angeles, CA, p. 221-248. 

Rowe, M.M., and Gettrust, J .F., 1993, Fine structure of methane 

hydrate-bearing sediments on the Blake Outer Ridge as determined from deep-tow multichannel seismic data: Journal 

of Geophysical Research, v. 98, p. 463--473 

Sadler, R.K., 1990, The relationship of lithology and tectonics to 

fracturing in the Monterey Formation, Point Arguello field, 

offshore California, in Keller, M.A., and McGowen, M.K., 

eds., Miocene and Oligocene Petroleum Reservoirs of the 

Santa Maria and Santa Barbara-Ventura Basins, California: 

Society of Economic Paleontologists and Mineralogists, 

Core Workshop 14, San Francisco, CA, Tulsa, Oklahoma. 

Scholl, D.W., and Cooper, A.K., 1978, VAMP's-Possible hydrocarbon structures in Bering Sea Basin: American Association 

of Petroleum Geologists, Bulletin, v. 62, p. 2481-2488. 

Scholl, D.W., and Creager, J.S., 1973, Geologic synthesis of Leg 

19 (DSDP) results; far North Pacific, Aleutian Ridge, and 

Bering Sea, in Creager, J.S., and Scholl, D.W., eds., Initial 

reports of the Deep Sea Drilling Project: v. 19: Washington 

D.C., U.S. Government Printing Office, p. 897-913. 

Scholl, D.W., and Stevenson, A.J., 1987, Ocean margin tectonics 

and north Pacific paleoceanography-Wonderments about 

the effects of the Pacific-Bering Sea connection, in Fourth 

International Congress on Pacific Neogene Stratigraphy, 

IGCP Project 246, Berkeley, California, July 29-31, 1987, 

Abstract Volume, Barron, J.A., and Blueford, J.R., eds.: Fremont, Calif., Math/Science Nucleus, p. 95-97. 

---1990, Was the Aleutian Basin more enclosed, its deeps 

oxygen deficient, and the geothermal gradient steepened in 

the middle Tertiary? Implications for the petroleum potential 

of the Bering Sea: American Association of Petroleum Geologists, Bulletin, v. 74, p. 1000. 

Scholl, D.W., Stevenson, A.J., Vallier, T.L., Ryan, H.R., and 

Geist, E.L., 1989, Aleutian arc-trench system: perspective of 

ocean margin evolution controlled by regional changes in 

plate-boundary conditions: 28th International Geological 

Congress, Abstracts, v. 3, p. 52-53. 

Scholl, D.W., Vallier, T.L., and Stevenson, A.J ., 1986, Terrane 

accretion, production, and continental growth-A perspective based on the origin and tectonic fate of the AleutianBering Sea region: Geology, v. 14, p. 68-71. 

Shipley, T.H., Houston, M.H., Huffier, R.T., Shaub, F.J., McMillen, K.J ., Ladd, J .W., and Worzel, J .L., 1979, Seismic evidence for widespread possible gas hydrate horizons on 

continental slopes and rises: American Association of Petroleum Geologists, Bulletin, v. 63, p. 2204-2213. 

Singh, S.C., Minshull, T.A., and Spence, G.D., 1993, Velocity 

structure of a gas hydrate reflector: Science, v. 260, p. 204-207. 

Sloan, E.D., Jr., 1990, Clathrate hydrates of natural gases: New 

York, Marcel Dekker Inc., 641 p. 

Snyder, W.S., Brueckner, H.K., and Schweickert, R.A., 1983, 

Deformational styles in the Monterey Formation and other 

siliceous sedimentary rocks, in Isaacs, C.M., Garrison, R.E., 

Graham, S.A., and Jensky, W.A., II, eds.: Petroleum Generation and Occurrence in the Miocene Monterey Formation, 

California: Pacific Section, Society of Economic Paleontologists and Mineralogists, Los Angeles, CA, p. 151-170. 

Stewart, R. J ., 1977, Neogene turbidite sedimentation in Komandorsky Basin, western Bering Sea: American Association of 

Petroleum Geologists, Bull., v. 61, p. 192-206. 

White, R.S., and Louden, K.E., 1998, The Makran continental 

margin: structure of a thickly sedimented convergent plate 

boundary, in Watkins, J. S., and Drake, C.L., eds., Studies in 

Continental Margin Geology: American Association of Petroleum Geologists Memoir 34, p. 499-513 

Westgate, J .A., Stemper, B.A., and Pewe, T. L., 1990, A 3 m.y. 

record of Pliocene-Pleistocene loess in interior Alaska: Geology, v. 18, p. 858-861. 

Worrall, D. M., 1991, Tectonic history of the Bering Sea and the 

evolution of Tertiary strike-slip basin of the Bering shelf: 

Geological Society of America Special Paper 257, 120 p. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Generation, Migration, and Resource Potential for 

Hydrocarbons in Accretionary Subduction Systems-A Large, 

Unconventional Hydrocarbon Resource? 

By Andrew J. Stevenson 1 

CONTENTS 

Abstract ......................................................................... 353 

Introduction ................................... ................................ 353 

Sediment Input to the Subduction Zone ...................... 354 

Structural Styles in Accretionary Settings ................... 356 

Thermal Structure of Accretionary Prisms .................. 357 

Origin and Migration of Fluids .................................... 359 

Favorable Settings for Maturation, Migration, and 

Entrapment of Hydrocarbons ....................................... 360 

Global Hydrocarbon Resource Potential from 

Accreted Sediment ........................................................ 361 

Conclusions . ... .. ... . .. . .. . .. ... . . .... ......... .. .. ..... .. .. ... . .. .. .. . . .. .... 361 

References Cited ........................................................... 362 

ABSTRACT 

Methane and other gaseous and liquid hydrocarbons 

are common components of accretionary complexes and 

have been observed in all environments within modem 

and fossil accretionary accumulations. Methane is generated in this setting by both microbial and thermal processes, 

but the limited number of samples analyzed prevents an 

accurate assessment of the relative importance of these 

two gas generation mechanisms. Large accretionary prisms 

are geologic settings which, owing to the large amounts of 

1

U.S. Geological Survey, MS 999, 345 Middlefield Rd. Menlo Park, 

CA 94025. 

organic detritus cycling through them, represent a large 

potential source of methane. Organic detritus in accretionary systems is primarily terrestrial in origin and thus gas 

prone. Variations in the sediment input, thermal structure, 

fluid flow regime, and structural style of accretion~ry 

prisms have a substantial effect on the amount of sediment 

that enters the gas generation window and on the amount 

and type of hydrocarbons generated. Factors favorable for 

maximum evolution of gas include a large, thick accretionary prism, a thick incoming sedimentary section, substantial axial trench sedimentation fed with continental 

detritus, development of the decollement near the top of 

the incoming section, substantial underplating, a young 

subducting plate, and slow to moderate plate convergence 

rates. On a worldwide basis, long-term methane generation 

potential is estimated at 1.5x 1010 m3 (0.5 trillion cubic 

feet or Tcf) per year in the accretionary subduction setting. 

No commercial accumulations of gas have yet been identified in this setting; this lack of accumulations implies that 

much of the gas generated may escape to the oceans and 

the atmosphere. However, accretionary complexes have 

not been extensively explored for hydrocarbons, and the 

trapping of even a small part of the gas generated could 

result in a substantial commercial resource. 

INTRODUCTION 

Submarine subduction zones worldwide are associated 

with the underthrusting of oceanic lithosphere beneath an 

overriding plate, and they represent a prominent site of marine sediment accumulation, burial, and storage. Marine sedimentary rocks and their included organic carbon overlying 

353 
354 THE FUTURE OF ENERGY GASES 

oceanic basement are transported into a regime of rising 

temperature and pressure; these conditions are likely to result in the generation of hydrocarbons from this sediment 

within a subduction zone. The potential amount of hydrocarbons generated in this environment is large owing to the 

constant entrainment of "fresh" sediment carrying new, or 

unreacted, organic carbon into the subduction zone (McCarthy and others, 1984; Kvenvolden and von Huene, 1985; 

Larue, 199 I). This constant rapid injection of fresh organic 

matter into a pressure/temperature regime conducive to the 

generation of gaseous and liquid hydrocarbons contrasts 

with the better understood sedimentary basin model of hydrocarbon generation. In the basin model, fresh organic matter enters the oil and gas kitchen comparatively slowly, via 

subsidence and burial, and the total available carbon is limited by the volume and tenor. Tenor is a mining term used to 

define the concentration of the economically important mineral in an ore. In this case it refers to the amount of organic 

matter contained in the sediment of the basin (Moore and 

Vrolijk, I 992, fig. 4). 

Hydrocarbon gases, primarily methane, are ubiquitous 

in accretionary complexes; they are present in venting 

thermal waters, mud volcanoes, diapirs, and they are also 

present as gas hydrates in the sedimentary section (Scholl 

and Hart, this volume; Lee and others, this volume; 

Brown, 1990; Kulm and Suess, I 990). Gaseous hydrocarbons have been found within and beneath accretionary 

complexes, from the seaward frontal thrust to their subaerial landward limits, and from inclusions trapped in the 

deepest exposed parts of fossil accretionary complexes 

(Bebout, 1991) to shallow (surface) vents. Methane in this 

environment can result from both microbial and thermal 

processes. Limited isotopic analyses of methane from surface vents and near-surface fluids indicate that the greater 

proportion is of microbial origin, but the number of analyses and the range of occurrences analyzed are insufficient 

to provide a comprehensive estimate of relative abundances. Thermogenic gases are common and have been observed in all parts of the accretionary system-their 

presence attests to the widespread thermal generation of 

gas in this environment. 

To evaluate the occurrence and hydrocarbon resource 

potential of accretionary systems, a brief description of the 

critical variables that influence the potential is discussed 

herein. Methane is not the only hydrocarbon species generated in accretionary complexes, but owing to the nature 

of the organic matter available for reaction it is the most 

dominant hydrocarbon species. 

SEDIMENT INPUT TO THE 

SUBDUCTION ZONE 

The composition of the sedimentary section and its included organic detritus entering a subduction zone is determined by the age and motion history of the plate upon 

which it resides coupled with the magnitude of the neartrench and trench-floor sediment supply. The interaction of 

two sedimentary regimes (open ocean pelagic and nearshore terrigenous) commonly results in a sedimentary section entering the subduction environment which changes in 

origin and character from base to top. At the base, the section is dominated by biogenic debris derived from plankton, airborne dust, and chemical precipitates from seawater 

(pelagic). Upsection, the sediment grades into clays and 

fine silts of terrestrial origin derived from subaerial weathering processes mixed with pelagic material (hemiterrigenous). The upper section is often dominated by coarse 

grained silts and sands of continental origin (terrigenous). 

A typical sedimentary section is shown in figure 1. 

Initial sediment deposition on newly formed oceanic 

crust usually occurs near a spreading center far from a terrestrial sediment source, so the section is dominated by 

pelagic deposits containing primarily type II kerogen (Tissot and Welte, 1984). The organic carbon content of this 

sediment is generally low ( <0.5 percent) but can be subTRENCH FLOOR 

AXIAL TRENCH FILL 

coarse-grained to fine-grained 

terrigenous sediments. 

DEEP SEA FAN BODY 

fine-grained terrigenous, 

hemiterrigenous, and 

subordinate amounts of 

pelagic sediment. 

PELAGIC SEDIMENTS 

includes pure pelagic and 

hemiterrigenous sediment. 

OCEANIC CRUST 

Figure 1. Generalized stratigraphic column showing typical succession 

of pelagic, hemiterrigenous, terrigenous, and coarse terrigenous sediments of a subduction environment. 
RESOURCE POTENTIAL FOR HYDROCARBONS IN ACCRETIONARY SUBDUCTION SYSTEMS 355 

stantially higher (>5 percent) if the plate has passed beneath zones of high surface-water biologic productivity 

associated with a depressed oxygen minimum zone. Globally, such conditions are rare, and, therefore, do not materially affect the average carbon content of sediment 

entering subduction zones. However, the coastal location 

of subduction zones may also be the site of upwelling currents that can increase the rate of pelagic deposition and 

enhance the amount of carbon preserved as the trench is 

approached. The thickness of pelagic sediment entering 

the subduction environment is variable-it ranges from nil 

for a young plate generated proximal to a subduction zone 

(for example, northern Cascadia subduction zone, Davis 

and Hyndman, 1989) to at least 400 m (for example, Kamchatka Trench, Ludwig and Houtz, 1979). 

In addition to pelagic sediment, many areas of the 

deep ocean floor are sites of significant terrigenous sedimentation. This sediment is primarily the result of continental (subaerial) erosion, and it is transported to the deep 

ocean by fluvial systems that feed large submarine fan 

systems. A subordinate amount of terrigenous sediment is 

contributed by airfall volcanic ashes and airborne dust. 

The organic carbon content of this sediment type is quite 

variable, but it is generally higher (>0.5 percent) than pelagic deposits (Larue, 1991, table 2). The sediment deposited on the oceanic plate hosts most organic carbon · 

available for thermal reaction. Under favorable conditions, 

total organic carbon (TOC) concentrations of more than 10 

percent result (Babaie and others, 1992). The origin of the 

organic carbon in the terrigenous sediment is predominantly terrestrial plant remains (type III kerogen of Tissot and 

Welte, 1984), with lesser amounts of type II organic matter derived from planktonic debris. The thickness of a 

hemiterrigenous-terrigenous sedimentary section can be 

substantial; it can range from a few meters to over 6 km 

seaward of an accretionary prism (for example, southern 

Barbados) (Speed and others, 1984; see also von Huene 

and Scholl, 1991, table 2 for summary). By far the greatest volume of terrigenous debris is found seaward of continental collision zones undergoing active tectonism (for 

example, in the northern Indian Ocean, Aegean Sea, and 

Gulf of Alaska) which, owing to continued rapid uplift, 

proximal location to an ocean basin, and enhanced erosion 

by water and ice, provide the vast majority of terrigenous 

sediment to the oceans globally (Milliman and Meade, 

1983). The incoming sediment, coupled with the axial 

trench sediment supply, are critical in initiating and maintaining an accretionary prism. 

As the oceanic plate nears a subduction zone, gradually 

increasing amounts of hemiterrigenous and terrigenous sediment are deposited. The amount and character of the terrigenous contribution to the sedimentary section seaward of 

the trench is strongly influenced by the type of subduction 

zone encountered. Intraoceanic island arcs generally contribute little or no sediment to the oceanic plate seaward of 

the trench owing to limited subaerial areas subject to high 

rates of erosion and the ability of the trench to accommodate the sediment supply from the arc-forearc region. Continental margin trenches fed by large fluvial systems can 

become filled and thereby allow turbidite deposition to prograde onto the ocean floor seaward of the trench. This progradation adds to the oceanic sedimentary section entering 

the subduction environment (for example, Cascadia subduction zone, Snavely and others, 1986). 

As the oceanic plate and its sedimentary cover transit 

the outer trench swell and enter the trench, substantial opportunities for further accumulation of sediment are encountered. In addition to the possibility of enhanced 

hemipelagic ·deposition, many trenches serve as zones of 

collection and transport of terrigenous material (Underwood and Bachman, 1982). Most trenches receive some 

sediment from the adjacent island or continental arc and 

many receive a substantial input from regions landward of 

the arc (continental interiors). Terrigenous sediment often 

flows axially down the trench and can be transported several thousand kilometers; this process introduces a significant 

terrigenous component onto a long reach of subducting 

plate (for example, Aleutian island arc, Scholl, 1974). The 

thickness of terrigenous material added to the sedimentary 

section immediately seaward of the subduction contact can 

be as great as 4 km (Scholl, 1982) and often forms the 

greater part of the sediment column. In terms of organic 

carbon content, sediment deposited in the trench shares the 

same characteristics as the terrigenous component of the 

deep ocean section, and it adds substantially to the carbon 

resource entering the subduction environment. 

Trench sedimentation is crucial in initiating, growing, 

and maintaining an accretionary prism. No modern examples of an accretionary prism being nourished by even the 

thickest sequence of pelagic and hemipelagic deposits of 

an oceanic sedimentary section are known. Investigations 

of subaerial fossil accretionary complexes have shown a 

paucity of pelagic facies (Underwood and Bachman, 1982; 

Howell and Murray, 1986); this lack of pelagic facies indicates that regardless of the presence or absence of an accretionary wedge, most or all of the pelagic component is 

subducted deep beneath the overriding plate. Therefore, a 

substantial terrigenous input is required for significant accretion to occur (von Huene and Scholl, 1991). With the 

exception of those subduction zones that are consuming 

substantial deep sea fan bodies (for example, eastern Aleutian trench), the terrigenous section necessary for accretion 

to occur must be deposited or augmented within the trench 

environment. 

This "ideal" superposition of depositional environments (fig. 1) leads to a coarsening upward sedimentary 

sequence (pelagic, hemipelagic, terrigenous) that may 

contain a significant proportion of sand in the trench-fill 

section. Proximal to sediment supplies from the continental interior, the trench wedge will likely contain mature, 
356 THE FUTURE OF ENERGY GASES 

quartz-rich sandstones capable of acting as reservoirs to 

host hydrocarbon accumulations (McCarthy and others, 

1984). 

STRUCTURAL STYLES IN 

ACCRETIONARY SETTINGS 

In an accretionary subduction zone, sedimentary rocks 

overlying oceanic basement can follow two general structural evolutionary paths, which are controlled by the position of the sediment with respect to the inter-plate contact, 

or decollement. Sediment that lies beneath the decollement 

remains, either temporarily or permanently, attached to the 

descending plate and is transported beneath the overriding 

plate. Underthrusting sediment may underplate the forearc 

region if the decollement moves downward through the 

sedimentary section, or, if the sediment remains below the 

contact, may be transported deep within the subduction 

zone to a depth where melting and reassimilation into the 

mantle is likely. Sediment located above the decollement 

becomes incorporated into the overriding plate either by 

frontal accretion or underplating and commonly forms an 

accretionary wedge composed of offscraped sediment of 

the descending plate overlain by slope sedimentary deposits derived from the overriding plate (Shipley and others, 

1990; fig. 2). 

The importance of frontal accretion versus underplating is difficult to assess in determining the structural style 

of large (>4 km maximum thickness) accretionary prisms, 

owing to the absence of deep drilling information and difficulty in obtaining an adequate seismic image of the 

deeper parts of the wedge. Underplating must play a major 

role in large accretionary prisms (von Huene and Scholl, 

1991), because the frontally accreted packets, even if 

stood on end, cannot account for the observed thickness of 

the wedge (fig. 2). For medium to small prisms, frontal 

accretion and thrust imbrication can account for the wedge 

geometry. In the upper regions of large prisms that can be 

imaged seismically, frontal accretion and packet imbrication appear to be the dominant structural styles. 

The process of frontal accretion and packet imbrication 

produces numerous antiforms, ramp anticlines, and drag 

folds in the uppermost part of the accretionary prism. 

These structures could act as traps to hydrocarbons migrating upward from deeper parts of the prism (fig. 3). These 

features are often large in plan view and have substantial 

structural relief. In the central Aleutian accretionary complex, 3- to 4-km-long folds with relief of I to 2 km have 

been delineated (McCarthy and others, 1984). Structures of 

similar morphology and size have been observed on seismic profiles from many large and medium size accretionary prisms (von Huene, 1986). Most fold structures are 

fault bounded on at least one side. These faults represent 

one possible path for focused fluid flow from deeper within 

the prism and from sediment subducted beneath the decollement. The close spatial arrangement of fluid, conduit, 

and trap provides an attractive site for pooling of migrating 

hydrocarbons generated deep within the prism and, if fault 

motion disrupts the subduction contact, for fluids traveling 

up the decollement. 

In accretionary complexes that form landward of 

trenches receiving a substantial supply of coarse continental sediment, the upper frontally accreted and imbricated 

part of the sedimentary section is likely to contain thick, 

coarse sand bodies that can become deformed to form potential structural traps (McCarthy and others, 1984). In addition to the accreted sedimentary deposits, hydrocarbon 

traps may be formed by slope sediment deposited unconformably upon the accreted section (fig. 2). These sediment accumulations can take several forms-a blanket laid 

uniformly over the wedge (Shipley and others, 1990), baSLOPE COVER DEPOSITS 0 

OUT-OF-SEQ.ENCE THRUST ' 

FRONTALACCiiT:IN:G~PA:C~K~IT~S~~=========:::::::~==~~~~~~~~~~~~~~i- 5 

10 

15 

0 km 10 

20 

km 

Figure 2. Structural elements of an accretionary prism. Modified from Moore and Vrolijk (1992). 
RESOURCE POTENTIAL FOR HYDROCARBONS IN ACCRETIONARY SUBDUCTION SYSTEMS 357 

sinal accumulations in interpacket structural lows, and, 

where a forearc basin is present, thick accumulations of 

sedimentary strata derived from the upper slope and shelf 

(von Huene, 1986). This sediment often shows less intense 

structural disturbance compared to the accretionary prism, 

and it can contain large antiform structures (Bally, 1983; 

Ryan and Scholl, 1989). 

THERMAL STRUCTURE OF 

ACCRETIONARY PRISMS 

Accretionary prisms are broadly characterized as zones 

of lower than average heat flow owing to the thermal insulating effect of the cool subducting plate beneath the wedge 

and the rapid mechanical thickening of the offscraped sediment, which causes isotherms to spread (fig. 4A). The constant underthrusting of new cool oceanic crust by the 

subduction process prevents the overlying accreted sediment from reaching a typical continental crustal temperature profile by absorbing geothermal heat that would 

otherwise reach the prism base (Burch and Langseth, 1981; 

Ferguson and others, 1993). 

Observed geothermal gradients in accretionary wedges 

range from 11 to 66°C/km (Larue, 1991 ), an exceptionally 

wide range. The observed values are also substantially greater than predicted by purely theoretical models (see Wang and 

Shi, 1984). The primary modulator of prism thermal structure is the age of the subducting lithosphere, which controls 

the amount of heat delivered to the base of the wedge (fig. 4 ). 

Other important processes that affect the thermal state of the 

prism are the convergence rate, the taper, or slope of the 

wedge, the thickness of the incoming sedimentary section, 

400 500 

and frictional heating at the base of the prism, all of which 

can vary independently (Langseth and others, 1990; Ferguson and others, 1993). Some thermal modeling studies of 

prisms underlain by old cold oceanic lithosphere, which use 

measured values obtained from surface probes and boreholes 

and which do not incorporate heat transfer by lateral fluid 

flow, show a low geothermal gradient throughout the wedge 

and moderate temperatures in the deepest parts of the prism 

(see Ferguson and others, 1993; fig. 4A). Prisms underlain 

by hot young crust can show a thermal structure that is quite 

different from the general case; prisms underlain by hot 

young crust have elevated isotherms, which result in a much 

higher temperature throughout the prism (fig. 4B; Hyndman 

and Wang, 1993). The discovery of submarine thermal 

springs, trench wedge geothermal anomalies (for example, 

Nankai margin), and recent Ocean Drilling Program drilling 

at the toe of large accretionary complexes (for example, 

Barbados and south Chile) attest that substantial, but onquantified, advective lateral and vertical heat transfer occurs 

via fluid flow. These processes introduce further uncertainties into any attempt to quantify a realistic geothermal model 

for accretionary wedges. The volumes of fluid involved and 

the high heat-transport capacity of water indicate that fluid 

flow can be an important process, at least locally, in modifying prism thermal structure. 

Therefore, it is difficult to predict where in an accretionary complex the hydrocarbon generation window might 

be located (50-250°C, Tissot and Welte, 1984). Beneath the 

decollement, similar uncertainty exists in predicting at what 

depth subducting sediment might encounter conditions 

favorable for the generation of hydrocarbons (compare 

figs. 4A, 48). The location of the hydrocarbon window 

represents one of the greatest uncertainties in any attempt 

600 700 

km 

7 

8 

9 

10 

II 

Vertical Exaggeration x 1.6 

Figure 3. Migrated depth section from the toe region of the central Aleutian accretionary prism, Alaska. A ramp 

anticline is visible near shotpoint 450 and a drag fold is visible at 7.2 km depth beneath shotpoint 525. Processed 

using finite-difference migration, stacking velocities determined from sonobuoy records and streamer moveout. 

From McCarthy and others (1984 ). 
358 THE FUTURE OF ENERGY GASES 

to describe the structure of the hydrocarbon generation-migration-accumulation system operating in the accretionary 

environment, and it seriously hampers any attempt to evaluate the amount of sediment (thus carbon) subject to conditions favorable for hydrocarbon generation. 

Seaward of the deformation front, more certainty exists with respect to the geothermal profile of the sedimentary section, and more meaningful estimates of the location 

of the hydrocarbon generation window can be made. In 

some situations, a significant part of the incoming sedimentary section may already be at temperatures higher 

than 50°C, the floor of the hydrocarbon window, and thus 

be contributing thermally cracked hydrocarbon species to 

the pore fluids. These conditions are most common where 

the sedimentary section is several kilometers thick, such as 

in seaward of the Makran deformation front (Minshull and 

White, 1989), or where the subducting plate is young, such 

as in the Shikoku Basin (Shipboard Scientific Party, 1991 ). 

Where these circumstances combine, for example off 

southern Vancouver Island, British Columbia, temperatures 

at the base of the incoming sedimentary section may approach 250°C (Hyndman and Wang, 1993). 

Convergence rate is a modulating force on basal prism 

temperature by controlling the amount of heat available for 

transfer. Rapid subduction of old cold plate results in greater thermal disequilibrium with respect to a steady-state 

heat flow, and it reduces heat flux to the prism base (Burch 

and Langseth, 1981 ). If the subducting lithosphere is 

r---------------------------------------------------------------~0 

A 

10 

IS 

20 

0 km 10 km 

r---------------------------------------------------------------------,-0 

B 

0 km 10 

Figure 4. A, Diagrammatic isotherm configuration for an 

accretionary system, which is subducting old cold lithosphere. Note a low overall geothermal gradient and 

modest temperature at the base of the prism. B, Diagrammatic isotherm configuration for an accretionary system, 

km 

which is underlain by young hot lithosphere. Note elevated isotherms in the prism, a high geothermal gradient, 

and high basal wedge temperatures. Modeled after Hyndman and Wang (1993), northern Cascadia accretionary 

prism. 
RESOURCE POTENTIAL FOR HYDROCARBONS IN ACCRETIONARY SUBDUCTION SYSTEMS 359 

young and warm, thermal disequilibrium can be minimal, 

resulting in high heat transfer to the prism base and high 

geothermal gradients (Hyndman and Wang, 1993). Age 

trends of the subducting plate can also have an effect on 

the thermal structure of the prism if convergence rates are 

high. As the subducted plate gets older, high convergence 

rates will result in the removal of heat from the base of the 

wedge. This condition will result in a lower overall geothermal gradient and a low temperature at the base of the 

prism. In situations where the subducting lithosphere is 

young, high convergence rates will raise basal temperatures by increasing heat flux to the base of the wedge. 

ORIGIN AND MIGRATION OF FLUIDS 

A good understanding of the hydrogeology of accretionary complexes is key to interpreting the migration, entrapment, and to a lesser degree, generation of hydrocarbons 

in the accretionary environment. Reasonable qualitative descriptions of the mechanisms of fluid expulsion from the 

prism and subducting sediment exist, but the relative importance of the various pathways is unclear, and quantitative 

data are lacking. 

The accretionary environment is a zone in which the 

rapid folding, stacking, and tectonic burial of poorly consolidated to unconsolidated sediment results in rapid loss 

of pore volume and the consequent expulsion of large 

quantities of pore fluids. In addition to pore water, lesser 

amounts of fluids are generated deep within the subduction 

zone by mineraloid and mineral dehydration reactions that 

reach the prism by traveling up and across the interplate 

contact of the decollement (Vrolijk and others, 1991). Evi0 

Zone of high fluid expulsion 

rates, maximum fluid flow, and 

rapid pore volume loss 

km 10 

~ Fluid vent sites 

dence exists for fluid flow at all levels and in all environments within a subduction zone (see summary in Moore 

and Vrolijk, 1992). Hydrocarbons generated within the accreted or subducting sediment can be expected to become 

entrained in this fluid flow, to migrate along with the fluids, and to either become trapped or vent to the ocean. 

Accreting sediment experiences rapidly increasing 

overburden loads, and this situation leads to rapid compaction and tectonically driven dewatering that is most active 

in the outer 20 km (high taper wedge) to 60 km (low taper 

wedge) of the prism (Bekins and Dreiss, 1992), where 

prism thickness is less than about 4 km (fig. 5). Landward 

of this zone, fluid expulsion continues, but the expelled 

volumes decline substantially. The primary control on the 

location of maximum fluid expulsion is the taper, or slope, 

of the wedge that determines the rate of burial (Bekins and 

Dreiss, 1992). The zone of maximum fluid expulsion is 

commonly characterized by numerous surface fluid escape 

structures, such as springs, carbonate pavements indicative 

of diffuse fluid flow, mud volcanoes, and diapirs, which all 

attest to a very active water drive (see Moore and Vrolijk, 

1992 and references therein). Studies of older accretionary 

rocks from the lower reaches of prisms exposed by erosion show that significant diffuse and channelized fluid 

flow occurs in virtually all parts of the wedge (Cloos, 

1984; Vrolijk, 1987), a circumstance that could aid in the 

migration of hydrocarbons formed anywhere within the 

complex (fig. 5). 

Sediment that lies under the decollement and is transported beneath the wedge has a markedly different fluid 

expulsion history than accreted sediment. Observations of 

fluid content, pore pressure, and consolidation state are 

limited to the outermost reaches of the prism and provide 

Potential gas reservoirs 

0 

10 

15 

20 

~ Fluid migration paths 

km 

Figure 5. Generalized model of fluid flow within an accretionary prism showing the many possible channelized and 

diffuse fluid flow routes, and zone of maximum fluid expulsion. Base from Moore and Vrolijk (1992). Fluid expulsion 

zone from Bekins and Dreiss (1992). 
360 THE FUTURE OF ENERGY GASES 

no direct evidence of conditions deeper beneath the wedge 

(Moore and Vrolijk, 1992). Where measured, pore pressures are substantially above hydrostatic and can approach 

lithostatic; these measurements attest to the slow rate of 

fluid escape (see Shipboard Scientific Party, 1991). Indirect evidence from seismic velocity studies (Shipley and 

others, 1990; Bangs and others 1990) and estimates of 

basal shear strength derived from taper angle measurements (Westbrook and others, 1982) indicate that overpressured conditions can persist deep under the prism. The 

addition of water to this section from mineral dehydration 

reactions can increase the fluid content of this section to 

an unknown, but potentially substantial amount (Moore 

and Vrolijk, 1992). 

Fluid flow paths in the subducting sedimentary section 

appear to be primarily lateral, because the decollement and 

undisturbed low-permeability layers act as significant barriers to vertical fluid flow (fig. 5). Water chemistry anomalies 

(primarily low chloride concentrations) observed beneath 

the decollement and in association with the frontal thrust 

have been interpreted as evidence of fluids (dehydration 

water) migrating laterally from deeper within the subduction zone (Moore and Vrolijk, 1992, pl. 2). 

The subdecollement sedimentary section represents a 

fluid reservoir that can be introduced by underplating into 

the basal portion of the accretionary prism at any location 

along the subduction contact. Migration of the decollement down section will transfer sediment and its accompanying fluids to the base of the wedge. In this location, 

vertical migration pathways can facilitate migration and 

entrapment of entrained hydrocarbons in the more stable 

structures landward of the zone of maximum fluid expulsion (fig. 5). If this transfer occurs during or after sediment has entered the oil and gas generation window, the 

fluids could contain a significant hydrocarbon fraction. 

FAVORABLE SETTINGS FOR 

MATURATION, MIGRATION, AND 

ENTRAPMENT OF HYDROCARBONS 

The lack of known commercial-size hydrocarbon accumulations in accretionary settings makes it difficult to 

describe favorable conditions for discovery on the basis of 

observed criteria. The known active oil and gas field that 

is reservoired in and sourced from an accretionary prism is 

in southern Barbados (Babaie and others, 1992). Commercial-size gas accumulations believed to be generated from 

accreted sediment, but reservoi"red in forearc basin strata, 

are present in northern California (Underwood, 1985), and 

in the Andaman forearc (J. Curray, oral commun., 1993). 

It is possible, however, to identify features of accretionary 

complexes that enhance the likelihood of generation, migration, and entrapment of hydrocarbons on the basis of 

theoretical considerations. 

Subduction zones that are being fed thick terrigenous 

sections should have greater hydrocarbon potential owing 

to the greater total volume of carbon available for reaction 

and the generally higher tenor of terrigenous sections, compared to less organic-rich pelagic sections. A high trenchfloor sedimentation rate, with a significant continental (as 

opposed to volcanic arc) detrital component, both increases 

available carbon and enhances reservoir potential in the 

upper wedge by placing sand bodies high in the section, as 

a consequence of frontal accretion (fig. 5). High organic 

content in the sedimentary section is of obvious benefit. 

From a structural standpoint, a large prism allows the 

upper landward region to become increasingly insulated 

from tectonic stress; such an isolation enhances the possibility of reservoir preservation, seal integrity, and hydrocarbon retention. The position of the decollement within the 

incoming section controls the amount of sediment that enters the generation window, because frontally accreted material rarely becomes deeply buried. A high decollement 

allows more of the section to pass beneath the outer wedge 

and be introduced into the higher temperature regime 

below. A greater amount of underplating of the prism is 

favorable for hydrocarbon generation, mobility, and entrapment, and it allows a greater transfer of sediment (and fluids) to the base of the wedge. Out-of-sequence thrusting is 

important in fostering and maintaining vertical fluid-migration pathways to the inner (landward) region of the wedge 

(fig. 5). The presence of slope-basin strata capable of hosting hydrocarbons is demonstrably favorable to hydrocarbon 

accumulation, as shown by the producing wells on Barbados (Babaie and others, 1992). Similarly a forearc basin can 

provide favorable settings for hydrocarbon accumulation. 

The thermal structure of accretionary complexes, as deduced from heat-flow calculations, is variable and exerts 

important controls on the amount of organic matter within 

the wedge subject to maturation. Subduction zones characterized by rapid subduction of old cold lithosphere with a 

thin pre-trench sediment cover reduces heat flux to the base 

of the prism, resulting in low geothermal gradients within 

the wedge ·(fig. 4A). This circumstance can restrict the hydrocarbon generation window to great depths within the 

complex and thereby substantially reduce the amount of 

sediment that generates hydrocarbons. At the other extreme, a young hot subducting plate with a thick overlying 

sedimentary cover and a low decollement increases heat 

flux into the prism base. Incoming sediment may already be 

essentially thermally mature at the bottom of the incoming 

section (for example, the northern Cascadia accretionary 

complex, Hyndman and Wang, 1993). In the northern Cascadia prism, all but the uppermost part ( <3 km) may have 

passed through or is lying within the thermal zone of hydrocarbon generation (fig. 4B). 

Fluid flow within the accretionary complex can have an 

important effect on both the thermal structure of the wedge 

by advection of heat and on the fate of hydrocarbons that 
RESOURCE POTENTIAL FOR HYDROCARBONS IN ACCRETIONARY SUBDUCTION SYSTEMS 361 

become entrained in the fluid. Buoyancy plays an important 

role in fluid flow in this regime (Moore and Vrolijk, 1992). 

Warm, less saline deep waters rise and transport heat into 

cooler, higher regions. This process increases hydrocarbon 

potential by elevating isotherms and exposing more sediment to temperatures suitable for organic maturation 

(fig. 5). Vertical fluid flow in the prism results in transportation and concentration of hydrocarbons in structural and 

stratigraphic traps. Too much vertical flow, however, can 

result in flushing of the wedge and venting hydrocarbons to 

the ocean. The vigorous water drive in the seaward, highvolume fluid-expulsion part of the prism is likely to prevent 

accumulation there. Fluids, added to the base of the wedge 

by deep underplating, rise through the landward part of the 

prism along channelized pathways (such as out-of-sequence 

thrusts, backthrusts, the accretionary wedge-crystalline 

basement contact). This migration sequence represents a 

favorable mechanism for introducing hydrocarbons into 

traps in the upper, more stable, landward region of the prism 

and into overlying forearc basin and slope cover strata. 

Large prisms, which require more underplating to maintain 

critical taper, enhance fluid transfer across the decollement. 

Fluid flow beneath the decollement is primarily lateral. Unless the permeability barrier at the subduction contact is 

broken, subdecollement fluid expulsion will take place at 

the frontal thrust; this process will result in venting or injection into the trench wedge, which will cause a loss of hydrocarbon potential in the prism. Consequently, decollement 

disruption and fluid escape into the overlying accretionary 

prism can actually favor hydrocarbon entrapment. 

GLOBAL HYDROCARBON RESOURCE 

POTENTIAL FROM ACCRETED 

SEDIMENT 

Regional estimates of hydrocarbon generation demonstrate the potential of some plate margins for gas production. In the eastern Aleutian subduction zone, Kvenvolden 

and von Huene (1985) estimate a production potential of 

5xl08 m3 of gas per kilometer of subduction zone length 

per million years. A worldwide estimate of thermogenic 

hydrocarbon generation potential from accretionary prisms 

by Larue (1991) indicates a maximum potential of 1012 

moles of live (hydrocarbon) carbon per year. If all the carbon were present as methane, it would occupy a volume 

of 2.2x 1010 m3 (0.8 Tcf) at standard conditions. Large uncertainties exist in this estimate, and the numbers should 

be treated only as order of magnitude estimates. Recent, 

more detailed, estimates of the volume of globally accreted sediment (von Huene and Scholl, 1991) allow some of 

the uncertainties to be reduced. 

Generation potential of thermally mature accreted sediment containing type Ill organic matter is 8.75x1011 mol 

of live carbon (carbon contained in hydrocarbon species) 

per km3 (from Larue, 1991, table 4). 

Solid volume of sediment accreted/subcreted annually 

in accretionary prisms is 0.44 km3

/yr (long-term average, 

glacial effects removed, D.W. Scholl, oral commun., 1993). 

Solid volume of sediment annually subducted landward of the accretionary prism and beneath the arc basement is 0.31 km3/yr (long-term average, glacial effects 

removed, D.W. Scholl, oral commun., 1993). 

Hydrocarbon generation potential for accretionary 

complexes, yearly, is 8.75xl011 mol of live carbon per 

km3x(0.44 km3/yr+0.31 km3/yr) = 6.6xl011 mol of live 

carbon (carbon contained in hydrocarbon species) per 

year. If all the live carbon appears as methane, it would 

occupy a volume of 1.5xl010 m3 (0.5 Tcf) 

The estimate just described makes several assumptions 

that may, in part, be inaccurate and lead to an overestimation. The estimate assumes that all sediment in the accretionary prism reaches thermal maturity for oil and gas 

generation. This assurt~ption is unlikely to be the case for all 

frontally accreted sediment, and it may not be true for all 

underplated material. Uncertainties in the thermal profile of 

the accretionary environment make it impossible to further 

constrain this parameter. The estimate also assumes that all 

hydrocarbons produced in the subducted but nonunderplated sediment escape into the accretionary prism or trench 

wedge and avoid reassimilation, which may also be a source 

of error. This error is probably small, however, as most 

subducted sediment passing beneath accretionary prisms 

probably passes through the oil and gas window prior to 

subduction beneath crystalline basement, and fluid escape 

from deeply subducted sediment is documented. The tenor 

of the sediment input is appropriate for modem accretionary 

settings, but it may not represent a viable long-term average 

rate. This source of error is also likely to be small because it 

is derived from measurements from many different environments and from sediment with a significant age distribution 

(Larue, 1991, table 1 ). There are two assumptions in the 

above estimate which may cause underestimation. The first 

is a sediment input rate 50 percent lower than modem rates 

is used to compensate for the input increase caused by late 

Neogene, Pleistocene, and Holocene glaciation, which has 

caused an increase in terrestrial sediment supply (von 

Huene and Scholl, 1991 ). The second is all organic matter is 

assumed to be type III, which yields much less live carbon 

per unit of organic carbon input compared to type II organic 

matter. Because of these uncertainties, the estimate is still 

poorly constrained, and it should be used with caution. 

CONCLUSIONS 

Accretionary complexes represent an environment in 

which marine sediment containing organic carbon of terrestrial and marine origin becomes rapidly buried and is 
362 THE FliTURE OF ENERGY GASES 

transported into a regime where the generation of hydrocarbons via thermal cracking can occur. Methane, of both microbial and thermal origin, is ubiquitous in this setting and 

has been found in all regions and depths within modern and 

fossil accretionary complexes. Modern accretionary prisms 

show wide variations in volume of sediment input, organic 

matter input, thermal structure, fluid flow, and structural 

style. These factors make generalizations regarding hydrocarbon potential difficult. However, factors that favor the 

generation and entrapment of hydrocarbons have been identified. The most important favorable factor is the presence 

of a large, thick accretionary prism. Other favorable factors 

include a thick incoming sedimentary section, substantial 

axial trench sedimentation dominated by continental detritus, formation of the decollement high in the incoming section, substantial underplating, a young subducting plate, 

and slow to moderate plate-convergence rates. 

Substantial quantities of methane and other hydrocarbons are likely generated in accretionary complexes. No 

commercial (producible at a profit) accumulations of gas 

and only one commercial oil and associated gas accumulation have been found in this setting. These two facts imply 

that most or all gas generated in this environment escapes 

to the oceans or the atmosphere. However, accretionary 

complexes have not been extensively explored for hydrocarbons, so this conclusion needs further testing, especially in complexes that have favorable factors. The 

magnitude of the potential is so large that even low percentages of entrapment and preservation could result in a 

substantial resource. 

REFERENCES CITED 

Babaie, H.A., Speed, R.C., Larue, O.K., and Claypool, G.E., 

1992, Source rock and maturation evaluation of the Barbados accretionary prism: Marine and Petroleum Geology, v. 9, 

no. 6, p. 623-632. 

Bally, A.W., editor, 1983, Seismic expression of structural styles: 

Tulsa, Okla., American Association of Petroleum Geologists 

Studies in Geology Series no. I 5, v. 3. 

Bangs, N.L.B., Westbrook, G.K., Ladd, J.W., and Buhl, P., 1990, 

Seismic velocities from the Barbados ridge complex-Indicators of high pore fluid pressures in an accretionary complex: Journal of Geophysical Research, v. 95, p. 8767-8782. 

Bebout, G.E., 1991, Field based evidence for devolitization in 

subduction zones-Implications for arc magmatism: Science, v. 251, p. 413-416. 

Bekins, B.A., and Dreiss, S.J., 1992, A simplified analysis of parameters controlling dewatering in accretionary prisms: 

Earth and Planetary Science Letters, v. 109, p. 275-287. 

Brown, K.M., 1990, The nature and hydrogeologic significance 

of mud diapirs and diatremes for accretionary systems: Journal of Geophysical Research, v. 95, p. 8969-8982. 

Burch, T.K., and Langseth, M.G., 1981, Heat flow determination 

in three DSDP boreholes near the Japan trench: Journal of 

Geophysical Research, v. 86, p. 9411-9419. 

Cloos, M., 1984, Landward dipping reflectors in accretionary 

wedges; active dewatering conduits?: Geology, v. 12, no. 9, 

p. 519-522. 

Davis, E.E., and Hyndman, R.D., 1989, Accretion and recent deformation of sediment along the northern Cascadia subduction zone: Geological Society of America Bulletin, .v. 101, 

p. 1465-1480. . 

Ferguson, I.J., Westbrook, G.K., Langseth, M.G., and Thomas, 

G.P., 1993, Heat flow and thermal models of the Barbados 

ridge accretionary complex: Journal of Geophysical Research, v. 98, p. 4121-4142. 

Howell, D.G., and Murray, R.W., 1986, Model for continental 

growth and denudation: Science, v. 233, p. 446-449. 

Hyndman, R.D., and Wang, K., 1993, Thermal constraints on the 

zone of major thrust earthquake failure-The Cascadia subduction zone: Journal of Geophysical Research, v. 98, 

no.B2, p. 2039-2060. 

Kvenvolden, K.A., and von Huene, R., I 985, Natural gas generation in sediments of the convergent margin of the eastern 

Aleutian Trench area, in Howell, D.G., ed., Tectonostratigraphic Terranes of the Circum-Pacific Region: Houston, 

Tex., Circum-Pacific Energy Council Earth Science Series 1, 

Houston, Texas, p. 31-49. 

Kulm, L.D., and Suess, E., 1990, The relation of carbonate deposits to fluid venting processes: Journal of Geophysical Research, v. 95, p. 8899-8915. 

Langseth, M.G., Westbrook, G.K., and Hobart, M., 1990, Contrasting geothermal regimes of the Barbados accretionary complex: Journal of Geophysical Research, v. 95, p. 8829-8844. 

Larue, O.K., 1991, Organic matter in the Franciscan and Cedros 

subduction complexes-The problems of "instantaneous 

maturation" and "missing petroleum" in accretionary prisms: 

Marine and Petroleum Geology, v. 8, no. 5, p. 468-482. 

Ludwig, W.J., and Houtz, R.E, 1979, Isopach map of sediments 

in the Pacific Ocean basin and marginal sea basins: Tulsa, 

American Association of Petroleum Geologists, 2 sheets. 

McCarthy, J., Stevenson, A.J., Scholl, D.W., and Vallier, T.L., 

1984, Speculations on the petroleum geology of the accretionary body-An example from the central Aleutians: Marine and Petroleum Geology, v. 1, p. 151-167. 

Milliman, J.D., and Meade, R.H., 1983, World wide delivery of 

river sediment to the oceans: Journal of Geology, v. 91, 

p. 1-21. 

Minshull, T., and White, R., 1989, Sediment compaction and 

fluid migration in the Makran accretionary prism: Journal of 

Geophysical Research, v. 94, p. 7387-7402. 

Moore, J .C., and Vrolijk, P., 1992, Fluids in accretionary settings, 

Reviews of Geophysics: v. 30, no. 2, p. 113-135. 

Ryan, H.R., and Scholl, D.W., 1989, The evolution of forearc 

structures along an oblique convergent margin, central Aleutian arc: Tectonics, v. 8, no. 3, p. 497-516. 

Scholl, D.W., 1974, Sedimentary sequences in the North Pacific 

trenches, in Burk, C.A., and Drake, C.L., eds., The Geology 

of Continental Margins: New York, Springer-Verlag, p. 493-

504. 

Scholl, D.W., 1982, Sedimentation and Deformation in the Amlia 

Fracture Zone Sector of the Aleutian Trench: Marine Geology, v. 48, p. 105-134. 

Shipboard Scientific Party, 1991, Site 808, in Taira, A., Firth, 

J. V., and others, Proceedings of the Ocean Drilling Program: 
RESOURCE POTENTIAL FOR HYDROCARBONS IN ACCRETIONARY SUBDUCTION SYSTEMS 363 

College Station, TX, Ocean Drilling Program, v. 131, p. 71-

269. 

Shipley, T.H., Staffa, P.L., and Dean, D.F., 1990, Underthrust 

sediments, fluid migration paths, and mud volcanoes associated with the accretionary wedge off Costa Rica-Middle 

America Trench: Journal of Geophysical Research, v. 95, 

p. 8743-8752. 

Snavely, P.D. Jr., von Huene, R., Mann, D.M., and Miller, J., 

1986, in von Huene, R., ed., Seismic images of modern convergent margin tectonic structure: Tulsa, Okla., American 

Association of Petroleum Geologists Studies in Geology 

no. 26, Tulsa, p. 26-27. 

Speed, R.C., Westbrook, G., Mascale, A., Biju-Duval, B., Ladd, 

J., Saunders, J., Stein, S., Schoonmaker, J., and Moore, J., 

1984, Lesser Antilles Arc and adjacent terranes-Woods 

Hole, Mass., Ocean Margin Drilling Program, Regional 

Atlas Series: Houston, TX, Marine Science International, 

Atlas 10, 27 sheets. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and occurrence: New York, Springer-Verlag, 538 p. 

Underwood, M.B., and Bachman, S.B., 1982, Sedimentary facies 

associations within subduction complexes, in Leggett, J., 

ed., Trench and Forearc Geology: London, Special Publications of the Geologic Society of London, no. 10, p. 537-

550. 

Underwood, M.B., 1985, Sedimentology and hydrocarbon potential of the Yager structural complex-Possible paleogene 

source rocks in the Eel River Basin, northern California: 

American Association of Petroleum Geologists Bulletin, 

v. 69, p. 1088-1100. 

von Huene, R., and Scholl, D. W., 1991, Observations at convergent margins concerning sediment subduction, subduction 

erosion, and the growth of continental crust: Reviews of Geophysics, v. 29, no. 3, p. 279-316. 

von Huene, R., ed., 1986, Seismic images of modern convergent 

margin tectonic structure: Tulsa, Okla., American Association 

of Petroleum Geologists Studies in Geology no. 26, p. 26-27. 

Vrolijk, P., 1987, Tectonically-driven fluid flow in the Kodiak accretionary complex, Alaska: Geology, v. 15, p. 466-469. 

Vrolijk, P., Fisher, A., and Gieskes, J., 1991, Geochemical and 

geothermal evidence for fluid migration in the Barbados accretionary prism (ODP leg 110): Geophysical Research Letters, v. 18, p. 947-950. 

Wang, C.Y., and Shi, Y-L, 1984, On the thermal structure of subduction complexes: a preliminary study: Journal of Geophysical Research, v. 89, p. 7709-7718. 

Westbrook, G.K., Smith, M.J., Peacock, J.H., and Poulter, M.J., 

1982, Extensive underthrusting of undeformed sediments beneath 'the accretionary complex of the Lesser Antilles subduction zone: Nature, v. 300, p. 625-628. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

An Energy Perspective on Landfill Gas 

By Peter J. Hutchinson 1 

CONTENTS 

Abstract . ...... ..... ... ... ... ... ..... .. .. .... .. .. .. ... .. ...... ... .. . . .. .. .. .. .. .. 365 

Introduction ................................................................... 365 

Municipal-Solid-Waste-Containment Facilities ........... 366 

Design .................................................................... 366 

Municipal-Solid-Waste Composition .................... 367 

Microbiology ................................................................ 369 

Controlled Reactor ........................................................ 371 

Landfill Biogas ............................................................. 372 

Migration ................................................................ 372 

Composition ........................................................... 372 

Biogas ·Yield ........................................................... 372 

Global Landfill Biogas Production Rates .................... 375 

Biogas Exploitation ...................................................... 377 

Conclusions ................................................................... 378 

References Cited ........................................................... 378 

ABSTRACT 

Globally, one billion metric tons of organic waste in 

the form of municipal solid waste are placed into solidwaste containment facilities every year. Complete biodegradation of this waste can generate approximately 

2.8x1011 m3 (9.9 trillion cubic feet (Tcf) or 1.98xl08 metric tons) of biogas. Biogas consists of approximately equal 

proportions of methane and carbon dioxide; thus a year's 

worth of waste can potentially generate l.4xi011 m3 (5 

Tcf or 9.9x107 metric tons) of methane. If we assume that 

1

The Hutchinson Group, Ltd., 5124 Scenic Rd., Murrysville, PA, 

15668. 

landfill-biogas generation began only 20 years ago and has 

proceeded at a steady rate, then we can estimate that it 

can contribute 5xl010 m3 (1.8 Tcf or 36xl06 metric tons) 

of methane to the global atmospheric budget every year. 

Landfill gas is difficult to recover and use. Exploitation 

of biogas includes use as a raw product for heat energy, 

dehydration to produce electric generator fuel, refinement 

for commercial transportation, and use as a chemical feedstock. Controlled-reactor landfills, called "biofills," are designed for optimum methane generation to ensure a steady 

and consistent rate of gas generation. Biofill mechanisms 

used to improve gas production include physical and chemical modifications to the modern landfill design. These 

methods can reduce the gas-generation time from 80 years 

to 5 years, can reduce the waste mass, and can reduce negative effects on the environment. 

Everything we use comes in boxes, cartons, bins. and so-called packaging we love so much. The mountains of things we throw away are much 

greater than the things we use. In this, if no other way, we can see the 

wild and reckless exuberance of our production, and waste seems to be 

the index. 

John Steinbeck 

INTRODUCTION 

The practice of putting waste in landfills dates back 

over 5,000 years (Senior, 1990). Archaeologists continually 

examine ancient waste-disposal sites to comprehend society's development and history (Rathje, 1991). Modem researchers are now examining municipal solid waste for its 

potential as an energy or gas resource (Hutchinson, 1990). 

Municipal solid waste has a caloric value upon incineration that can be converted to electric or steam energy 

(Seeker and others, 1989). The incineration of municipal 

solid waste, however, has had negative effects upon the 

365 
366 THE FUTURE OF ENERGY GASES 

environment and is currently in disfavor (Kiser and Sussman, 199 I). Recently, the focus has shifted to the biogas 

that municipal solid waste produces. Through anaerobic decomposition, municipal solid waste generates methane in 

quantities that can be exploited (Hutchinson, 1989). 

Municipal solid waste in landfills produces biogas, a 

mixture of nearly equal volumes of methane and carbon 

dioxide (Alpern, 1973; Anderson and Callinan, 1970). The 

generation of biogas has positive economic implications because biogas is an exploitable, moderately predictable, and 

reliable source of methane (Hutchinson, 1990, 1991 ). Bingemer and Crutzen (1987) estimated that global generation of 

methane from municipal solid waste is 30 to 70 million 

metric tons, or 1.5 to 3.5 trillion cubic feet (Tcf), per year. 

.Biodegradation of municipal solid waste under anoxic 

conditions in municipal-solid-waste-containment facilities 

reduces the waste volume, geochemically stabilizes the remaining waste (thereby limiting stress to the environment), 

and generates an energy source in the form of methane-rich 

biogas that can be an asset to the host community. This paper 

will address the global volume of landfill-generated biogas 

and the potential for the exploitation of this energy source. 

MUNICIPAL-SOLID-WASTECONTAINMENT FACILITIES 

Municipal-solid-waste-containment facilities are designed to inhibit the loss of three phases of waste material: 

solid waste, leachate, and biogas (fig. 1). Solid waste (for 

FINAL 

COVER 

SYSTEM 

LANDFILL 

GAS 

EXTRACTION 

WELL 

MUNICIPAL 

SOLID 

WASTE 

example, paper, household goods, construction materials, 

animal carcasses, refractory materials, and food products) 

is normally the only phase emplaced and buried at the municipal-solid-waste-containment facility. However, some 

liquids are introduced through disposal of municipal solid 

waste, water is added to the municipal-solid-waste-containment facility through infiltration of precipitation, and 

liquids are generated through decomposition of the waste 

(Senior and Shibani, 1990). The percolation of water 

through the landfill generates a liquid called leachate. Biogas is liberated from the waste mass during the decomposition of the organic material (Barlaz and others, 1987). 

Migration of this gas away from the municipal-solidwaste-containment facilities can be dangerous, especially 

if the gas collects with oxygen in confined spaces (Hartner, 1990). 

DESIGN 

In the past, landfills were merely dumping areas where 

waste materials were placed and either abandoned, covered, or burned. The modem landfill evolved through the 

need to limit vectors (for example, rodents, insects, birds), 

to better manage waste disposal, to insure prudent siting, 

to reduce the threat of contamination of soil and groundwater, and to minimize health-based risks of municipal 

solid waste. The modern municipal-solid-waste-containment facility consists of three phase-containment systems: 

two for containing and collecting leachate and gas, and 

one for containing solid waste. 

LEACHATE 

TREATMENT 

SYSTEM 

LANDFILL 

GAS 

RECOVERY 

PLANT 

UPGRADIENT 

GROUNDWATER 

MONITORING 

WELL 

LINER AND LEACHATE 

COLLECTION SYSTEM 

WATER TABLE 

Figure 1. Schematic drawing of municipal-solid-waste-containment system. 

DOWNGRADIENT 

GROUNDWATER 

MONITORING 

WELL 
AN ENERGY PERSPECTIVE ON LANDFILL GAS 367 

The hydrogeologic regime for the site often dictates 

the landfill design (Fetter, 1988). Landfills are often designed to protect groundwater in four site-specific hydrogeologic regimes (Walsh and O'Leary, 1991). 

The primary component of the landfill consists of the 

liner (Haxo, 1976). The landfill liner prevents the escape 

of leachate, and the landfill cap contains gases. An alternative landfill design, natural-attenuation landfill, relies upon 

the cation-exchange capacity of the soils under the waste 

mass to remediate the leachate (Lisk, 1991 ). This type of 

landfill is now rare owing to the heterogeneity of soils and 

an often poor understanding of the cation-exchange capacity of soils below the landfill. 

A municipal-solid-waste-containment system can employ- one of seven types of liners: (l) compacted native 

fine-grained soils, (2) bentonite and other clay sealants, (3) 

asphalt, (4) portland cement, (5) soil sealants (such as lime 

and penetrating polymeric emulsions), (6) sprayed liquid 

rubber, and (7) synthetic polymeric membranes (Haxo, 

1976). The most common type of liner is the synthetic 

polymeric membranes; these liners are thin, inexpensive, 

malleable, and allegedly dependable. Lee and Jones 

(1991 ), however, maintain that the life span of flexible 

membrane liners is short and that the failure of landfill 

caps and liners constructed ·of this material remain an imminent threat to groundwater. 

Leachate that collects at the base of the landfill material can be pumped from the municipal-solid-waste-container and treated before disposal. The gas generated 

during decomposition of the waste mass is collected passively or actively. Passive systems consist of wells drilled 

or built into the waste mass and left open to the atmosphere to permit ventilation (Wegener and Lekstutis, 1989). 

Active vacuum gas-abstraction systems require rigorous 

design and engineering (Leach, 1990). Strategies for the 

removal of gas from the municipal-solid-waste-containment facility consist of vertical and horizontal collection 

systems; most of these are expensive and require continual 

maintenance (Marshall, 1988). Regulatory compliance provides most of the driving force for the installation of landfill gas-abstraction systems (Hartner, 1990; Pennsylvania 

Department of Environmental Resources, 1989). 

MUNICIPAL-SOLID-WASTE COMPOSITION 

Municipal solid waste consists of organic and inorganic materials (table 1). The inorganic materials consist of 

refractory waste (plastic, glass, metal), construction debris, 

and recalcitrant organic debris (such as lignin) and do not 

readily undergo bacterially mediated catabolism or decomposition. Organic materials include paper, cardboard, food, 

and coarse organic waste (wood/yard/textile). Barlaz and 

others (1989b) found that municipal solid waste from 

Madison, Wisconsin, consisted of three groups of compounds sorted by their biodegradability: labile, recalcitrant, and inert. Labile compounds consist of cellulose 

( 40-50 percent), hemicellulose (12 percent), and protein ( 4 

percent); whereas recalcitrant compounds include the 

nonbiodegradable biomolecule lignin (10-15 percent) and 

various inert materials (30 percent). Westlake ( 1990) 

found that European municipal solid waste consists of 60 

percent carbohydrates, 2.5 percent protein, 6 percent lipids, and 31.5 percent inert material. 

Table 1 is a distillation of the work of many researchers arid may overstate or understate the waste concentrations for each category. For example, one researcher may 

consider animal carcasses as food, which is in the Food 

Waste category, whereas another may consider animal 

carcasses as leather, which is in the WoodNard/Textile 

category. Nevertheless, these data display a normal distribution with low standard deviations, suggesting that these 

data are reasonable. 

Globally, an estimated 1,165xl06 metric tons of biodegradable organic municipal solid waste are generated 

per year (table 2). This amount is considerably larger than 

the 85xl06 metric tons per year calculated by Bingemer 

and Crutzen (1987). However, Bingemer and Crutzen 

(1987) used a global population 34 percent smaller than 

that in the 1990 global census figures (Hoffman and others, 1991 ). The 12 studies in table 2 indicate that, on average, the municipal solid waste generated in the world is 75 

percent organic (table 1). Bingemer and Crutzen considered the organic constituent of municipal solid waste to be 

15 to 22 percent of the disposed waste. Considering these 

differences in the extrapolation from available data, current world population figures, and organic compositions 

cited for various parts of the world, the estimate of Bingemer and Crutzen (1987) can be recalculated to approximate! y I ,OOOx 106 metric tons of organic waste per year. 

Difficulties with this global yearly generation rate of 

biodegradable organic compounds are numerous, and 

many of these problems were reviewed by Bingemer and 

Crutzen (1987). Most underdeveloped countries currently 

or will soon exploit the landfill technologies of the developed countries. Modern landfill technologies encourage 

anoxic decomposition, or anaerobiosis (Emcon Associates, 

1981 a). Recent landfill installations in Hong Kong meet 

the specifications for U.S. Environmental Protection Agency Resource Conservation and Recovery Act of 1977, subtitle D, regulations for landfill construction. The West 

Indies, Mexico, Indonesia, and portions of Africa are currently installing modern landfills that will promote anaerobic conditions. 

The major concern with estimates of the global yearly 

generation of biodegradable municipal solid waste is that 

municipal solid waste must be buried to initiate anaerobiosis. On a national level, improper waste placement techniques, scavenging, recycling, and composting can reduce 

the global yearly generation rate of organic municipal 
368 THE FUTURE OF ENERGY GASES 

Table 1. Composition of municipal solid waste in selected locations around the world. 

[Values in percent wet weight. Year (second column from right) indicates year for which data were compiled. n.a., not applicable] 

Waste category Source of data 

Paper/ Food waste Wood/yard/ Plastic Glass Metal Construction Year Reference 1 

Location cardboard textile debris 

Australia ------------------ 24.9 46.1 1.5 3.0 14.7 8.2 1.6 1988 k 

Denmark------------------ 33.0 37.0 10.0 5.0 6.0 4.0 5.0 1990 

England ------------------- 34.0 23.0 3.0 8.0 9.0 9.0 14.0 1988 

Federal Republic of 27.0 35.0 0.0 4.0 10.0 5.0 19.0 1977 

Germany (former). 

Holland ------------------- 22.5 55.0 3.9 6.8 8.1 2.5 1.2 1983 e 

Hong Kong--------------- 5.0 2.6 73.2 8.7 0.3 2.9 7.3 1983 g 

Indonesia ----------------- 14.0 74.0 0.0 2.0 1.0 1.0 8.0 1984 

Israel ---------------------- 30.3 54.7 3.1 4.4 3.0 3.1 1.4 1979 h 

Italy ----------------------- 17.0 53.0 4.0 7.0 8.0 3.0 8.0 1977 a 

Japan ---------------------- 31.4 26.0 11.5 11.7 9.3 7.8 2.3 1980 c 

Norway ------------------- 33.5 38.5 8.4 6.2 5.1 4.0 4.3 1981 d 

United States------------- 34.2 8.5 29.5 9.1 7.1 8.4 3.2 1988 b 

Waste composition, 25.57 37.78 12.34 6.33 6.80 4.91 6.28 n.a. n.a. 

average. 

I References: 

a. Albonetti and Massari ( 1979) g. Parker (1983) 

b. Environmental Protection Agency (1990) h. Senior (1990) 

c. Hanashima and others (1983) i. Soerjani (1984) 

d. Heie and Minaas (1981) j. Thome-Kozmiensky (1977) 

e. Hoeks (1983) k. Ward (1988) 

f. Mosey and Mistry ( 1990) I. Willumsen (1990) 

Table 2. Disposal of municipal solid waste by region. 

[CIS, Commonwealth of Independent States (former Soviet Union)] 

Region_ .. :. ______ .. ______ , _______________________ Nonh America Europe CIS Asia Oceania Latin America Africa 

Population 

(millions) ---------------------------------- 277 499 291 2,994 26 450 795 

Waste generation rate 

(kilograms per capita per day) --------- 1.6 1.5 1.2 0.4 0.8 0.6 0.5 

Fraction of municipal solid waste 

placed in landfills 

(percent) ----------------------------------- 87 85 85 71 85 80 70 

Organic fraction 

(percent; from table I) ------------------ 71.7 72.9 75 88 72.5 80 85 

Biodegradable organic fraction 

(percent) ----------------------------------- 60 60 60 60 60 60 60 

Organic municipal solid waste available for anaerobiosis 

(million metric tons per year)---------- 61 109 64 654 6 98 174 
AN ENERGY PERSPECTIVE ON LANDFILL GAS 369 

solid waste. Current trends towards dehydration of the 

waste in modern municipal-solid-waste-containment facilities inhibits biodegradation (Lee and Jones, 1991 ). These 

factors may reduce the global total of available biodegradable organic municipal solid waste by about 30 percent of 

the calculated 1, 165x 106 metric tons of municipal solid 

waste generated per year. For the remainder of this article, 

1 ,OOOx 106 metric tons per year will be inferred for the 

global generation rate of biodegradable organic material. 

MICROBIOLOGY 

Farquhar and Rovers (1973) divided landfill-gas generation into four phases based upon the catabolic activity 

of landfill microorganisms. Subsequently, Rees ( 1980a) 

added an additional phase that reflected the terminal stages 

of anaerobiosis (fig. 2). Ward (1988) also summarized the 

five stages of landfill decomposition: I, initial adjustment; 

II, transition in landfill biota; III, acid formation; IV, methane fermentation; and V, final maturation. 

Zehnder ( 1978) found that three bacterial groups dominate progressive stages in the generation of biogas in an 

anaerobic digester. The first group consists of anaerobic 

and facultative anaerobic fermenting bacteria that catabolize complex organic material. At this stage, carbohydrates, proteins, and lipids are hydrolyzed and fermented 

to fatty acids, alcohols, carbon dioxide, ammonia, and hydrogen (fig. 3). Organic products of the first stage are converted to acetic acid, hydrogen, and carbon dioxide by 

obligate proton reducing acetogens, the second group. The 

third group consists of two microbial forms: anaerobic 

chemolithotrophs that use hydrogen to generate methane 

and eliminate acid buildup, and methanotrophs that form 

methane from the decarboxylation of acetate (fig. 3). 

Similarly, Zeikus (1981) identified four physiologically different types of bacteria in anaerobic digesters. Initially, hydrolytic bacteria ferment complex hydrocarbons to 

fatty acids, methanol, carbon dioxide, ammonia, and hydrogen; whereas obligate and facultative hydrogen-producing acetogenic bacteria ferment complex organic acids and 

neutral compounds to hydrogen, carbon dioxide, and acetic acid (McCarty, 1981 ). Homoacetogenic bacteria continue to ferment carbon compounds to acetic acid, and 

methanogenic bacteria ferment H2/C03, monocarbon compounds, and acetate to methane. 

The landfill environment is similar to the anaerobic digester in that it is a site where organic compounds are 

mineralized (disintegrated to carbon dioxide, methane, and 

water); however, the decomposition of organic material in 

the landfill proceeds by slightly different physical, chemical, and biological processes (Ham and Barlaz, 1987). For 

example, comminution of the municipal solid waste prior 

to placement has positive effects upon the biogas generation rate (Naveau, 1984). 

Initially, the waste decomposes through aerobic processes in which atmospheric oxygen and nitrogen are consumed within days (phase I, fig. 2) (Barlaz and others, 

1989c ). Subsequent to placement, there is little change in 

populations of cellulolytic, acetogenic, and methanogenic 

LANDFILL GAS PRODUCTION PHASE 

I n 

OXYGEN 

ill IV 

/ --...... , 

\ 

\ 

X 

0 \ 

I \ 0 \ 

v 

Figure 2. Typical landfill-gas-production pattern (from Farquhar and Rovers, 1973, and Rees, 1980b). The 

five phases of landfill-gas production (from Ward, 1988) are I, initial adjustment; II, transition in landfill 

biota; III, acid formation; IV, methane fermentation; and V, final maturation. See text for discussion. 
370 THE FUTURE OF ENERGY GASES 

COMPLEX ORGANIC 

MATERIAL 

HYDR6LYSIS 

& 

FERMEtTATION 

6)t 0 .. (50 \--il 

·ACIDS\ ALCOHOLS t 

70% t 30% 1 

ACETO GENESIS H 2 METHANOGENESIS 

[ ACL ACID t : 

CH4 I . t 

METHANOGENESIS ~ I 

t t I 

~ ~----------J 

Figure 3. Biodegradation of complex organic material. Anaerobic and facultative anaerobic fermenting bacteria accomplish hydrolysis and fermentation; obligate proton reducing acetogenic 

bacteria perform acetogenesis; anaerobic chemolithotrophs and 

methanotrophs affect methanogenesis. Pie charts show inferred 

percentages of mass transfer. Dashed line indicates a potential 

pathway. 

bacteria, and soluble sugars serve as the carbon source 

(Barlaz and others, 1992). During the aerobic phase (phase 

I), complete mineralization of an organic compound can 

be achieved by one microbial species, invertebrates can effect physical and chemical decomposition, and fungi can 

contribute to catabolism (Senior and Balba, 1990). Nitrogen is a rate-limiting factor for aerobic bacteria, and this 

phase generates a considerable amount of water (Senior 

and Balba, 1990). 

The remaining four phases are anaerobic and are characterized by mineralization of organic compounds to carbon dioxide and methane (figs. 2, 3). Cellulose can be 

completely mineralized to equal volumes of carbon dioxide and methane: 

(I) 

Senior (1990) divided anaerobic catabolism of organic 

compounds into four pathways;. hydrolysis and fermentation, propionogenesis (propionate generation), acetogenesis 

(acetate generation), and methanogenesis (methane generation). These processes occur together through the anaerobic 

phases of catabolism; however, some reactions are more 

active during certain phases. 

Phase II is characterized by the presence of a large 

population of facultative anaerobic organisms that use a 

variety of inorganic electron acceptors; this phase can 

last up to 6 months (Ham and Barlaz, 1987). Carboxylic 

acids accumulate and the pH drops during the initial 

stages of phase II; however, catabolism of cellulose and 

hemicellulose begins and continues through the remaining phases (fig. 2) (Barlaz and others, 1989b). During 

phase II, hydrolysis and fermentation generate hydrogen, 

carbon dioxide, ethanol, lactate, and succinate. The generation of hydrogen and the manufacture of fatty acids 

depress the pH. The lower pH adversely affects methanogenic bacteria (Augenstein and others, 1976; Westlake, 

1990; White and Plaskett, 1981; Zehnder and others, 

1981 ). Nitrogen is depleted from the system while carbon 

dioxide becomes the volumetrically most abundant gas 

(fig. 2) . 

Phase III, the acid formation phase, is noted for dramatic transformations in gas concentrations and is distinguished by the loss of nitrogen and hydrogen, and the 

initiation of methane generation. Propionogenesis may 

commence during this phase and consume some of the 

free hydrogen and consequently raise the pH (Senior and 

Balba, 1990). Phase III lasts from 3 months to 3 years, 

during which methane levels of biogas rise to 50 to 60 

percent, carboxylic acid concentrations decline, and the 

populations of acetogenic, cellulolytic, and methanogenic 

bacteria increase (Barlaz and others, 1992; Barlaz and 

others, 1989b, c.) At this phase, the waste mass is reaching a steady-state condition for gas geneiation in which 

the bacterial populations work symbiotically to maintain 

adequate conditions for survival of all species (fig. 3). 

Methane-generation levels stabilize during the longest 

of the landfill-gas-generation phases, phase IV. Methanegeneration levels can be maintained at a 45 to 60 percent 

concentration in the biogas for as long as· 80 years (Augenstein and Pacey, 1991; Emcon Associates, 1980). During this phase, population levels of methanogenic bacteria 

remain stable and the pH remains buffered (Ward, 1988). 

Phase IV is characterized by high concentrations of 

two types of bacteria: acetogenic and methanogenic. Two 

types of acetogenic bacteria occur in the waste mass: hydrogen-producing acetogens that gain energy for growth 

by catabolizing alcohols and organic acids into acetic acid 

and hydrogen, and hydrogen-consuming acetogens that 

metabolize carbohydrates, hydrogen, and carbon dioxide 

to acetic acid (Senior and Balba, 1990). Seventy percent 

of the methane in the anoxic environment is derived from 

acetate mediated by methanogenic bacteria (Jeris and McCarty, 1965; Mah and others, 1977; Wolfe, 1982). 
AN ENERGY PERSPECTIVE ON LANDFILL GAS 371 

Methanogens also perform a bioregulatory role in the 

maintenance of fermentation through the conversion of 

acetic acid, hydrogen, and carbon dioxide to methane; otherwise the pH would drop and stress the acetogenic bacteria. Senior and Balba (1990) found methanogenic bacteria 

to be involved in three bioregulatory roles including proton, electron, and nutrient regulation. Proton removal by 

the methanogenic bacteria maintains the system neutrality 

and electron regulation produces a thermodynamically stable and reduced carbon compound, methane. Senior and 

Balba (1990) speculated that methanogenic bacteria supply 

nutrients to the other species in the system. 

The loss of cellulose, carbon dioxide, and methane 

characterize the final phase of municipal-solid-waste decomposition, phase V (Ward, 1988). During this phase, 

bacterial populations decrease dramatically and biogas generation declines (Rees, 1980a). Continued abstraction of 

gas during this phase can ventilate the landfill to atmospheric concentrations. This phase can last between 1 and 

40 years. Complete landfill biodegradation can be achieved 

10 to 80 years after emplacement. 

CONTROLLED REACTOR 

Municipal-solid-waste-containment facilities represent 

complex bioreactors where bacterial ecosystems are symbiotically maintained when other factors are preserved. Factors that can sustain and stimulate biogas generation are as 

follows (Barlaz and others, 1990; Farquhar and others, 

1979; Ward, 1988): (1) Moisture levels kept at field capacity conditions, (2) leachate recycling, (3) neutral pH, (4) a 

strongly negative redox potential (<-200 millivolts (mV)), 

(5) mesophilic temperatures, (6) adequate nutrient levels, 

(7) municipal-solid-waste composition, (8) waste placement and compaction, (9) waste mixing, and (I 0) size reduction. Zehnder and others (1981) found that many of 

these factors are rate-limiting for the generation of gas. 

Moisture levels at field capacity can significantly improve biogas generation rates (Barlaz and others, 1987; 

Emcon Associates, 198la; Ward, 1988; Westlake, 1990). 

White and Plaskett (1981) found that optimum conditions 

for methanogenesis occur at saturation levels of greater 

than 40 percent. DeWalle and others (1978) found the 

greatest gas production occurred in containers with 99 percent saturation. High moisture levels have two main advantages: (1) water can solubilize and distribute substances and 

nutrients to the bacteria (Barlaz and others, 1987), and (2) 

recycling leachate (with neutralization) can substantially 

improve biogas generation by mixing waste and liquids and 

by increasing saturation (Barlaz and others, 1989b; Harper 

and Pohland, 1988; Hartz and Ham, 1983; Klink and Ham, 

1982; Leckie and others, 1979; Rees, 1980b ). 

Methanogenic bacteria are very sensitive to acidic 

conditions and are stressed below a pH of 6 (Zehnder and 

others, 1981 ). Augenstein and others (1976, 1977) found 

that "souring" (reduction of pH and death of bacteria) occurred when organic acids were generated during catabolism and that methane formation was suppressed by low 

pH. Buffering the waste with calcium carbonate significantly improves production of biogas. White and Plaskett 

( 1981) contended that the ideal pH for the generation of 

biogas is between 6.8 and 7.2. Fortunately, a delicate 

chemical symbiosis between methanogenic and acetogenic 

bacteria maintains a ~uffered pH (Zeikus, 1983). 

Anaerobic reactions occur only when the redox potential is less than -200 m V (Farquhar and others, 1979). Zehnder (1978) found that bacteria cannot initiate growth at 

a redox potential higher than -330 mV. Farquhar and others (1979) suggested that a reducing agent, such as cysteine, must be present to initiate low redox conditions. 

Methanogenic bacteria may have a naturally low redox 

potential (Hartner, 1990). 

·Mesophilic or thermophilic conditions are more difficult for bacteria to maintain in anaerobic conditions than 

in aerobic conditions (White and Plaskett, 1981). However, after exothermic aerobic reactions cease, anaerobiosis 

is able to maintain mesophilic conditions (Farquhar and 

others, 1979). Zehnder and others (1981) observed that 

methanogenic bacteria generate gas under mesophilic conditions of 35 to 45°C. Pfeffer (1974b) considers the optimum temperature range for biogas generation to be 37 to 

42°C. Hartz and others (1982) concluded from studies on 

landfill cores that the ideal temperature for biogas generation and for methanogenesis is 41 °C. 

Several workers maintain that certain nutrientsnitrates and phosphates-have a rate-limiting effect upon 

biogas generation (Barlaz and others, 1989b; Farquhar 

and others, 1979; Ham and Barlaz, 1987; Pohland and 

others, 1983). Nutrient levels for optimal gas generation 

expressed as the ratio of chemical-oxygen-demand:nitrogen: phosphorous are 100:0.44:0.08 (Farquhar and others, 

1979). Bogner and others (1990) and Bogner (1991) demonstrated that biogas generation can be slightly stimulated 

by the addition of a comprehensive aqueous nutrient 

media. Ham and Barlaz (1987) suggested that the heterogeneity of municipal solid waste conceals the nutrient 

rate-limiting effects, put the apparent zero-order kinetic 

reaction rates for landfill-gas generation at many landfills 

suggest that rate limitation is occurring. 

Toxic xenobiotic compounds added to the waste mass 

can have a poisonous effect upon the bacteria that evolve 

biogas. Chlorinated hydrocarbons, heavy metals, and detergents are poisonous to the methanogenic bacteria (Senior and Kasali, 1990). Prudent disposal mechanisms can 

help to eliminate these toxic compounds. Wood and others 

(1986) found that certain toxic compounds are released 

during anaerobiosis. Vinyl chloride, a bacterial toxin, is 

generated enzymatically by microbial dehalogenation of 

halogenated hydrocarbons. 
372 THE FUTURE OF ENERGY GASES 

Municipal-solid-waste compos1t10n, placement, and 

size reduction have beneficial effects upon the generation 

of biogas. Shredding and comminution of waste exposes 

more surface area to biodegradation (Augenstein and others, 1977; Rees, 1980b). Westlake (1990) contended that 

reducing refuse size and increasing density have positive 

effects on the generation of biogas through better mixing. 

Sorting, selecting, and mixing of waste improve gas evolution rates (Ham, 1976; Ham, 1992). Cellulose and hemicellulose, ubiquitous compounds in municipal solid waste, 

readily biodegrade under anaerobic conditions and are 

ideal waste products; however, cellulose is associated with 

lignin, a recalcitrant biomolecule (Barlaz and others, 

1989a, b, 1992; Young and Frazer, 1987). Maximum gasgeneration rates are achieved through selection, comminution, and compaction; however, excess compaction reduces 

permeability of the waste mass and thus reduces infiltration and gas-generation rates (Bookter and Ham, 1982; 

Emcon Associates, 1981a). 

LANDFILL BIOGAS 

MIGRATION 

Migration of gas away from landfills has caused numerous problems, including explosions, plant necrosis, and 

redolent fetor (for example, multiple deaths were associated 

with the Winston-Salem, N.C., National Guard Armory explosion in 1968). These problems have driven many studies 

of landfill-gas-generation rates and landfill-gas migration. 

Gas migration is attributed to molecular diffusion to regions of low gas concentration (Baker and others, 1984; 

Doyle, 1985; Parker and Roberts, 1985; Young and Parker, 

1983). Hartner ( 1990) found that migration of gas is related 

to barometric pressure changes and temperature contrasts. 

Undesired migration of gas prompted the installation of gas 

recovery systems such as gravel-filled cut-off trenches and 

gas-abstraction systems (Bogardus, 1984). These recovery 

efforts, induced by gas-migration problems, have preceded 

many projects that now exploit the captured biogas. 

COMPOSITION 

Cellulose generates biogas in equal concentrations of 

methane and carbon dioxide (equation 1). Barlaz and 

others (1989a) found that 91 percent of landfill biogas 

methane is from biodegradation of cellulose and hemicellulose. The average methane concentration from six landfills in California is 30.4 percent; however, because many 

of these landfills produce oxygen, the intrusion of air is 

suspected (Freemon, 1989). Most landfills that follow appropriate abstraction protocols produce a methane concentration of 45 to 55 percent (Emcon Associates, 1980; 

Farquhar and others, 1979; Pfeffer, 1974a). Carbon dioxide occurs in slightly lower concentrations, 35-45 percent, possibly due to its high solubility in leachate 

(Senior and Shibani, 1990). 

Additional compounds have been identified in landfill 

biogas and are attributed to three sources: vaporization, 

chemical reaction, and biological decomposition (Emerson, 1990). These vapor-phased compounds can be toxic 

to the microbial populations in the landfill, corrosive to 

abstraction and processing equipment, and harmful to 

human health. More than 100 trace vapor-phased chemical 

compounds identified in landfill biogas are listed in table 

3. The condensate associated with abstraction of landfill 

biogas is composed of two phases, a light organic phase 

consisting of trace hydrocarbons, and a heavier aqueous 

phase containing trace elements of dissolved trace compounds (Environmental Protection Agency, 1987). 

BIOGAS YIELD 

Zehnder (1978) considered oxygen to be a rate-limiting factor in the growth of strict anaerobes and used the 

Peter-Nernst oxidation-reduction-potential equation for determining rates of anaerobiosis. Emcon Associates ( 1981 a) 

applied a modified version of the Monod (1950) kinetic 

expression to describe the rate of biogas production. Soluble-substrate and bacterial concentrations are the rate-limiting factors that can be set to a first-order kinetic equation 

for biogas production: 

ds 

dt 

KCS 

(Ks + S) 

(2) 

where K is the maximum rate of substrate utilization per 

unit mass of bacteria (time-1 ); C is the concentration of 

bacteria (mass/volume); S is the waste concentration 

surrounding the bacteria (mass/volume); and Ks is the 

substrate concentration, where the rate is one-half the 

maximum rate of substrate utilization (mass/volume). 

Equation 2 has been successfully employed to explain the 

observed generation rates for biogas (Emcon Associates, 

1981a). 

Augenstein and Pacey ( 1991) listed four models for 

the increase and decline of biogas production through 

time. The first model is a zero-order model with constant 

gas-generation rates through time. The second model follows an exponential gas-generation-rate decline from the 

onset of solid-waste placement. The remaining models include an exponential or constant rise followed by an exponential decline in generation rate. The Emcon model, the 

methane generation model, includes a lag period prior to a 

constant rise, followed by an exponential decline in the 

rate of gas generation. However, Ham and Barlaz (1987) 
AN ENERGY PERSPECTIVE ON LANDFILL GAS 373 

Table 3. Trace constituents of landfill gas. 

[---, constituent not detected or not detennined] 

Reference 1 ------------------------------- A B c D E F G H K L 

Comment2 ------------------------------- 2 3 2 2 5 4 6 2 7 2 

Trace aliphatic organic compounds (micrograms per liter) 

n-BUTANE 30,000 9,950 9,270 23 

BUTENE-I 3,000 21 

DECANE 157 

n-DECANE 70,000 137 78 

DECENE 57 

DODECANE 4 

ETHANE 802.500 

ETHYLENE 31 

HEPTANE 10.000 8 6 

HEXANE 75,000 7,350 II 14 

n-HEXANE 160,000 8,245 18 7,800 13 

HEX ENE 6 3 

2-METHYLHEPT ANE 3 

3-METHYLHEPTANE 3 

2-METHYLHEXANE 16 

3-METHYLHEXANE 13 

2-METHYLPENT ANE 2 

3-METHYLPENT ANE 2 

NONANE 63 

NONENE 12 

n-NONANE 50,000 400 46 

OCTANE II 

n-OCTANE 110,000 75 11 

OCTENE 4 

iso-PENT ANE 250 4 

n-PENTANE 46,000 2,968 8,480 12 

PROPANE 29.000 19,410 10 

PROPENE 83 

TERPENE 84 

TRIDECANE 

UNDECANE 82 

n-UNDECANE 72,000 48 31 

UNDECENE 44 

Trace acids, esters, ketones, ethers, and alcohols (micrograms per liter) 

I-BUTANOL 19 

iso-1-BUTANOL 5 

2-BUTANOL 116 

ETHANOL 650 

METHANOL 210 

I-PROPANOL 73 

2-PROPANOL 2,500 32 

ACETONE 240,000 8,940 4,800 

2-HEXANONE 1,000 

METHYL ETHYL KETONE 130,000 1,030 23 

METHYL ISOBUTYL KETONE 1,200,000 1,950 

2-PENTANONE 17 

ETHYL ACETATE 4,500 36 

ETHYL BUTANOATE 10 

ETHYL PENTANOA TE 27 

METHYL ACETATE 5,000 

METHYL PENTANOATE 22 

VINYL ACETATE 240,000 

DIETHYL ETHER 2,200 20 

METHYL ISOPROPYL ETHER 2,500 

TETRAHYDROFURAN 50,000 

See footnotes at end of table. 
374 THE FUTURE OF ENERGY GASES 

Table 3. Trace constituents of landfill gas-Continued. 

Reference I ------------------------------- A B c D E F G H K L 

Comment2 ------------------------------- 2 3 2 2 5 4 6 2 7 2 

Trace aromatic and cyclic compounds (micrograms per liter) 

BENZENE 11,000 2,500 6,540 39,000 2,700 3,640 7 2,000 32,000 4 

BICYCL0(3,2,0)HEXAN0-2,2- 153 

METHYL-4-METHYLETHYLENE 

BICYCL0(3,2, I )OCT ANO- 350 

2,3-METHYL-4-METHYLENE 

BUTYL BENZENE 78 

CAMPHORJFENCHONE 2,000 8 

ETHYL BENZENE 98,000 87,500 12,425 21,940 99 236 6,200 20 

ETHYLCYCLOPENTANE 5,000 

LIMONENE 119 

MESITYLENE 25 

METHYL STYRENE 15 

METHYLCYCLOHEXANE 45,000 7,200 

METHYLCYCLOPENTANE 7,500 

PENTYL BENZENE 17 

PROPYL BENZENE 94 

PROPYL CYCLOHEXANE 4 

STYRENE 2,000 150,000 

TOLUENE 143,000 280,000 67,750 57,750 135 615 27,000 150,000 58 

XYLENE 220,000 94,000 35,500 18,000 208 376 16,000 56 

Trace halogenated hydrocarbons (micrograms per liter) 

CARBON TETRACHLORIDE 42,000 II 2,100 60 6,220 

CHLOROBENZENE 330 1,350 473 2,020 

CHLORODIFUOROMETHANE 1,760 2,810 

CHLOROETHANE 30,000 473 1,970 264 

CHLOROFLUOROMETHANE 10,000 

CHLOROFORM 70,000 360 3,260 12,000 2,500 350 2 610 42 

CHLOROMETHANE 23,000 5,740 3,720 

CHLOROTRIFLUOROMETHANE 10 

DICHLOROBENZENE 130 750 16 

1,1-DICHLOROETHANE 22,000 2,615 4,240 

1,2-DICHLOROETHANE 1,600 600 6,000 2,100 89 2,320 652 294 4,200 19,000 

1,1-DICHLOROETHENE 4,000 310 370 800 

c-1,2-DICHLOROETHENE 20,000 

t-1,2-DICHLOROETHENE 37,000 850 475 6,900 9,100 59,000 22 

DICHLORODIFLUOROMETHANE 49,000 130 16,440 119 23 

DICHLOROFLUOROMETHANE 7,500 6,913 1,400 

D1CHLOROMETHANE 42,000 630 33 

1,2-DICHLOROPROPANE 280 123 350 61 

DICHLOROTETRAFLUOROETHANE 900 

DICHLOROTRIFLUOROETHANE 50,000 

ETHYLENE DIBROMIDE 4 6 

METHYLENE CHLORIDE 4,800 59,000 16,125 19,310 6 32,000 

PERCHLOROETHYLENE 62,000 1,100 52,000 180,000 19,875 8,290 142 11,000 19,000 170 3 

1,1 ,2,2-TETRACHLOROETHANE 500 16.000 110 1,100 

I, 1,1-TRICHLOROETHANE 15,000 650 12,000 14,500 353 1,110 4 1,800 3,600 7 18 

1,1 ,2-TRICHLOROETHANE 9,300 8,500 

TRICHLOROETHENE 4,600 840 11,000 32,000 5,475 3,880 182 3,100 13,000 92 11 

TRICHLOROFLUOROMETHANE 428 960 84 2,500 

VINYL CHLORIDE 2,200 41,000 32,000 3,750 7,720 6,900 44,000 

Trace sulfur compounds (micrograms per liter) 

BUTYLPROPYLDISULPHIDE 3 

CARBON DISULFIDE 3,400 

DIETHYL DISULPHIDE 3 

DIMETHYL DISULPHIDE 30 40 

See footnotes at end of table 
AN ENERGY PERSPECTIVE ON LANDFILL GAS 375 

Table 3. Trace constituents of landfill gas-Continued. 

Reference 1 ------------------------------- A B c D E F G H K L 

Comment 2 ------------------------------- 2 3 2 2 5 4 6 2 7 2 

Trace sulfur compounds (micrograms per liter)-Continued 

DIMETHYLSULFIDE 

DIMETHYL TRlSULPHIDE 

DIPROPYLTRISULPHIDE 

1-ETHANETHIOL 

ETHYLISOBUTYLDISULPHIDE 

ETHYLISOPROPYLDISULPHIDE 

ETHYLMETHYLDISULPHlDE 

ETHYLMETHYL TRISULPHIDE 

ETHYLPROPYLDlSULPHIDE 

ETHYLPROPYL TRISULPHIDE 

HYDROGEN SULFIDE 

METHANETHIOL 

METHYLPROPYLDlSULPHIDE 

METHYLPROPYL TRlSULPHIDE 

2-PROPANETHlOL 

2-PROPENE-1-THIOL 

5,000 

75 

5 

I 

I 

8 

25 

2 

I 

4 

45 

16 

I 

2 

22 

44 

87 

Major gases in landfill gas (volume percent) 

METHANE 

CARBON DIOXIDE 

NITROGEN 

OXYGEN 

1 References: 

19.00 73.00 

2

Comments: 

47.75 

39.75 

11.53 

1.27 

58.70 51.25 

43.50 44.25 

A. Assmuth (1992) I. Average of 3 landfills 

B. Baker and others (1990) 2. Maximum recorded concentration 

C. Brennan ( 1989) 3. Average of 340 landfills 

D. California Waste Management Board (1989) 4. Average of 48 landfills 

E. Crouch and others (1990) 5. Average of 4 landfills 

F. Dimmick and Chow ( 1990) 6. Average of 3 VOC source samples 

G. Holsen and others ( 1990) 7. Average of 35 landfills 

H. Rettenberger (1987) 

I. Vogt and Conrad (1988) 

J. Wood and others (1986) 

K. Young and Blakey (1990) 

L. Young and Parker ( 1983) 

concluded that rate-limiting factors may lower biogas generation to fit a zero-order kinetic expression. 

Landfill-gas-generation rates and volumes are predicted from experimental, theoretical, and field data (table 4). 

A review of these data indicates that the many disparate 

variables and methodologies have produced a wide range 

of predicted rates and volumes for methane and biogas 

production. Maxwell (1990) referred to an industry production rate for 36 biogas-to-electricity projects in the 

United States of 0.006 m3kg- 1yr- 1

. Ham (1979) reviewed 

the literature and found the range for gross production to 

be 0.047 to 0.45 m3kg-l, or approximately 0.28 m3kg- 1

, 

and the generation rate to range from 0.0026 to 

0.0307 m3kg-1 yr-1

. Ham concluded that a yearly rate of 

0.005 m3kg- 1yr- 1 is a good working estimate for landfill 

biogas generation in the United States (R.K. Ham, oral 

commun., 1989). I will use this figure to calculate global 

annual landfill biogas emissions. 

GLOBAL LANDFILL BIOGAS 

PRODUCTION RATES 

Predictions of municipal-solid-waste biogas generation 

volume and rates are difficult to produce because waste is 

continuously placed into landfills over time, gas flux occurs during and after placement, and gas generation is 

based upon many physical parameters that vary spatially 

and temporally. Consequently, the exponential rise and fall 

of landfill-gas generation (first-order kinetic reaction) is 

normally amortized over I 0 to 80 years. 

Globally, approximately 1,000x106 metric tons of 

organic waste are placed in landfills every year. If completely biodegraded at a rate of 0.28 m3 of biogas per 

kilogram, municipal solid waste has the potential to produce approximately 2.8x101I m3 of biogas (9.9 Tcf or 

1.98x 108 metric tons). Assuming a 50-percent methane 

concentration in the biogas mixture, 1.4xi011 m3 (5 Tcf or 
376 THE FUTURE OF ENERGY GASES 

Table 4. Methane and biogas production from landfill biodegradation. 

[m3/m.t., cubic meters of methane or biogas generated per metric ton of degradable waste; m3/kgyr, cubic meters of methane or biogas generated per kilogram of waste per 

year; MSW, municipal solid waste; UK, United Kingdom;---, not determined] 

Methane Biogas 

Gross Rate Gross Rate Reference Comment 

(m3/m.t.) (m3/kgyr) (m3fm.t.) (m3/kgyr) 

Experimental data 

130 Augenstein and others (1976) Conventional continuously stirred tank of dry sludge/waste 

solids with calcium hydroxide. 

128 Augenstein and others ( 1976) Conventional continuously stirred tank of dry sludge/waste 

solids with calcium carbonate. 

95 Augenstein and others ( 1976) Conventional continuously stirred tank of sludge/waste 

solids with calcium carbonate. 

104 Augenstein and others (1977) Shredded MSW and sludge in buffered packed-bed digester. 

9.5 Augenstein and others ( 1977) Shredded MSW in buffered packed-bed digester. 

80-150 0.0007-0.128 Barlaz and others (1987) Dry grindable solids with anaerobic sewage sludge. 

142.5-208 Barlaz and Ham ( 1990) Gas recovery from labtop experiments. 

310-390 Brown and others (1976) Organic fraction of MSW in laboratory digesters. 

0-816.8 Buivid (1980) Flailed, shredded, and ball-milled MSW in controlled 

lysimeter. 

0.066 DeWalle and others (1978) MSW in laboratory lysimeters. 

80-320 Nave au (1984) Reported laboratory tests. 

94.2 188.4 Pfeffer (197 4) Calculated from a digester with shredded refuse. 

Field data 

0.005-0.009 Campbell and Croft (1990) Test cells with 15,000 metric tons of MSW. 

0.04 Jenkins and Pettus (1985) Incubation of landfill cores. 

0.01-0.025 Lawson and others (1991) Test cell at Brogborough, UK. 

282.6 0.006 Maxwell ( 1990) Waste Management Inc. working field number. 

37.7-94.2 Pacey and others (1987) Landfill cell at Mountain View, Calif., landfill. 

0.038 0.098 Rees (1980) Rates from Aveley (UK) landfill. 

0.0025-0.0088 Wilke and others (1982) Calculated from actual landfill production. 

217-418 Willumsen (1990) Tested cells of 240 metric tons (Denmark). 

Theoretical data 

213.5 427 Alpern (1973) Stoichiometric calculation. 

244.9 414.5 Anderson and Callinan (1970) Stoichiometric calculation. 

62-110 Augenstein (in press) Generation model from Emcon Association. 

62-125 Augenstein and Pacey (1991) Modelled from actual landfills. 

77-107 Barlaz and Ham (1990) Calculated methane generation. 

77.9 155.7 Dair and Schwegler (1974) Biodegradability calculations. 

62.8-188.4 Emcon Association (1981) First-order equations of submasses in the waste mass. 

62.8-113 Emcon Association (1986) First-order equations/reference trade use of 188.2 m 3fm.t.. 

175.8 207.6 Golueke (1970) Calculations of biodegradability. 

232.4 358.1 Leckie (1974) Stoichiometric calculations for food/paper waste. 

270 425.2 Leckie (1974) Stoichiometric calculations for composited MSW. 

0.008 Pennsylvania Dept. of Environ- Estimation by Commonwealth of Pennsylvania. 

mental Resources ( 1989) 

125.6 251.2 Pfeffer (1974) Theoretical calculation. 

415 830 Ward (1988) Stoichiometric calculation from cellulose. 
AN ENERGY PERSPECTIVE ON LANDFILL GAS 377 

9.9xl07 metric tons) of methane will evolve over time. On 

the basis of Ham's generation rate of 0.005 m3 of biogas 

per kilogram of organic waste per year, every year, 5xl09 

m3 (176 billion cubic feet (Bcf) or 3.5x I 06 metric tons) of 

biogas will evolve from municipal-solid-waste-containment 

systems and be added to the annual atmospheric budget. 

Large modem municipal-solid-waste-containment systems with strong biogas-generation potential are a modern 

phenomenon. As a starting point, assume that biogas generation started only 20 years ago and that steady-state conditions (zero-order kinetic reaction rate) have prevailed for 

landfill-gas generation for the last 20 years. Consequently, 

we can estimate the cumulative yearly rate of methane 

generation by multiplying the annual global rate by 20. 

This calculation yields an estimate of 10xi010 m3 (3.6 Tcf 

or 72xl06 metric tons) of biogas or 5xi010 m3 (1.8 Tcf or 

36xi06 metric tons) of methane that could evolve globally 

from landfills this year. 

Augenstein (1990) calculated through first-order kinetics that landfills in the United States generate 3 to 8 million metric tons (0.15-0.40 Tcf) of methane per year. 

Hutchinson ( 1990, 1991 ), through a zero-order kinetic 

model, calculated that 12 million metric tons (0.6 Tcf) of 

methane per year are available from landfills in the United 

States. Colt and others (1990) estimated that the yearly 

methane emissions for the municipal solid waste in the 

United States are 8 to II million metric tons (0.4-0.55 

Tcf). Bingemer and Crutzen (1987) imprudently assumed 

that all municipal solid waste generated yearly completely 

biodegrades yearly and, consequently, that 50 million tons 

(2.5 Tcf) of methane are emitted yearly to the atmosphere 

from all landfills. In reality, municipal solid waste generates biogas through time, and thus each year's volume of 

waste contributes only a portion of its generative capacity 

to the atmosphere. 

Municipal-solid-waste-disposal rates, biodegradation 

rates, organic concentration, and numerous other factors 

dictate that these generation rates and gross generation 

values are nothing more than best guesses for global methane production. Recoverable energy from landfills could 

range between 1 and 2 percent of the total United States' 

energy use (Environmental Protection Agency, I991; Dair 

and Schwegler, I974). In effect, methane from landfills 

could supply 11 percent of the United States' current demand for natural gas (Pfeffer, I974a). 

BIOGAS EXPLOITATION 

Landfill-gas recovery and exploitation is expensive 

and is driven by the energy economics or politics of the 

time (fig. 4). A steep, upward trend in the number of landfill-gas-recovery projects began in 1984. The increase in 

projects followed large increases in oil prices between 

1980 and 1981. The 4-year time lag reflects the design, 

construction, and start-up time from the initial impetus 

(rise in cost of energy). The sagging energy prices of the 

late 1980's also prompted a decline in the growth in number of recovery projects. Currently, there are 157 landfillmethane-recovery projects (128 operational) in the United 

States (Berenyi and Gould, 1991). Richards and Aitchison 

(1990) indicated that 242 landfill-gas-recovery projects 

exist in 20 countries around the world, and that 78 percent 

of these are in the United States. 

Four strategies for the exploitation of biogas are as 

follows: (1) raw gas sale to an end-user, (2) medium-Btu 

(British thermal unit) gas sales, (3) high-Btu-gas sales, and 

(4) chemical feedstock supply. Raw landfill gas, with its 

high, heat-robbing moisture content, is rarely used because 

of the low energy value ( <400 Btu per cubic foot) and 

high corrosivity and erosivity of the trace compounds 

(Zimmerman and others, 1985). Dehydration of the gas 

raises the energy value, and many projects are based on 

this strategy, including most electric-generation projects 

(Berenyi and Gould, I991). 

High-energy-gas recovery strategies include dehydration and stripping carbon dioxide and trace gases from the 

biogas. Hutchinson (1989) listed seven gas-separation 

techniques: (I) chemical absorption, (2) physical absorption, (3) chemical adsorption, (4) physical adsorption, (5) 

partial pressure separation, (6) distillation/dehydration, and 

(7) cryogenic fractionation. Physical absorption is considered the most economical technology for turning raw landfill gas into relatively pure methane (C-E Lummus and 

SCS Engineers, 1983; Keller, 1988; Zimmerman and others, 1985). Additional strategies can be employed after the 

gas is refined, such as compression for vehicular fuel (Augenstein and Pacey, 1992). 

Biogas as a chemical feedstock is becoming a reality 

with the discovery of different catalysts. Lithium-promoted 

NO. PROJECTS PRICE/STB (US$) 

160 --------------------------~===440 

120 30 

80 20 

PRICE OF OIL 

40 10 

0 

YEAR 

Figure 4. Cumulative U.S. landfill-gas-recovery projects and average yearly published price of oil in stock-tank barrels (STB) 

(yearly average crude price: written commun., American Association of Petroleum Geologists, 1993). See text for discussion. 
378 THE FUTURE OF ENERGY GASES 

magnesium oxide can catalyze the partial oxidation of 

methane in a conventional flow reactor to make ethane and 

ethylene (Ito and others, 1985). Periana and others ( 1993) 

describe a successful method using methyl bisulfate to catalyze the oxidation of methane to methanol. High-energy 

fuel from biogas may be available through the generation 

of synfuel (Hickman and Schmidt, 1993) and diesel fuel 

(Thomeloe, 1990; Wald, 1991 ). 

Biogas can be used as a low-energy gas to heat a greenhouse, with the advantage that the elevated carbon dioxide 

levels encourage plant growth (Graff, 1989; Miller and 

Quinn, 1990). Controlled oxidation of biogas can also produce carbon dioxide in economic quantities (Hutchinson, 

1989). 

Perhaps the best strategy for biogas exploitation is to 

generate the gas through selective disposal into controlledreactor landfills (Ham, 1992). Richards and Aitchison 

( 1990) introduced the term "biofills" for landfills designed 

to optimize methane generation by recycling leachate and 

having internal permeable corridors. Biofill methane-generative capacity can also be ameliorated through the use of 

horizontal gas collectors and dispersers (Glockner, 1989). 

The horizontal dispersers are designed to reinject carbon 

dioxide, water, buffers, and nutrients into the landfill material. All of these strategies can reduce the gas-generation 

time from between 20 to 80 years to 5 years or less (Augenstein and Pacey, 1992). 

Anaerobic biological digestion of organic materials has 

been economically demonstrated in reactor gasifiers (Levy 

and Rigo, 1976). Two-step anaerobic sludge blankets employ acid fermentation followed by methane fermentation 

and can yield 75 percent of the ultimate biogas yield in an 

operating time of 20 to 30 days (Lagerkvist, 1991; Rijkens. 

and Voetberg, 1981 ). High-solids digestion systems are the 

most promising of the anaerobic digestion options because 

they are compact and have the best prospects for producing 

useful refined digestate products (Mosey and Mistry, 1990). 

Lynd and others ( 1991) found that conversion of municipalsolid-waste cellulose to ethanol can be cost effective. 

CONCLUSIONS 

Landfill gas is a resource that has reached a level of 

understanding and exploitation only within the last decade. 

Landfills are always associated with urbanized areas, thus 

the gas is spatially near potential applications. Highly urbanized areas generate large volumes of waste that can be 

biodegraded to biogas. Anaerobic digestion of the organic 

phase of Municipal solid waste can reduce the volume of 

waste, produce a more inert and environmentally favorable 

product, and help reduce the load on the world energy 

budget. Capturing the gas for exploitation reduces the 

greenhouse gas emission by ( 1) replacing another carbon 

dioxide-generating energy source and thereby reducing the 

carbon dioxide load to the atmosphere and (2) reducing 

the methane load to the atmosphere (methane's contribution as a greenhouse gas is 25 times greater than that of 

carbon dioxide on a mole percent basis). 

The global volume of gas available for exploitation, 

approximately 5x1010 m3 (1.8 Tcf or 36xt06 metric tons), 

warrants further refinement of the mechanisms for improving biogas generation rates, and capturing and processing 

the gas. Biogas is a unique feedstock that can be chemically 

manipulated to produce other more marketable products. 

Manipulation of the anaerobic reaction can induce rapid 

biodegradation of the waste, improve generation volume 

and rate, and minimize the impact to the environment. Biogas represents a technical challenge to the scientific community for the solution of waste placement, pollution, and 

energy production. 

REFERENCES CITED 

Albonetti, S.G., and Massari, G., 1979, Microbial aspects of municipal waste composting system: European Journal of Applied Microbiology and Biotechnology, v. 7, p. 91-104. 

Alpern, R., 1973, Decomposition rates of garbage in existing Los 

Angeles landfills: Long Beach, California State University, 

M.S. thesis. 

Anderson, D.R., and Callinan, J.P., 1970, Gas generation and 

movement in landfills, in Proceedings of the National 

Industrial Solid Waste Management Conference: Silver 

Spring, Md., Government Refuse Collection and Disposal 

Association. 

Assmuth, T., 1992, Distribution and attenuation of hazardous 

substances in uncontrolled solid waste landfills: Waste Management and Research, v. I 0, p. 235-255. 

Augenstein, D.C., 1990, Greenhouse effect contributions of United States landfill methane, in Maxwell, G., Walsh, J., and 

Hirshfeld, S., eds., Proceedings from the GRCDA 13th Annual International Landfill Gas Symposium: Government 

Refuse Collection and Disposal Association, Silver Spring, 

Md., p. 95-126. 

---in press, The greenhouse effect and U.S. landfill methane: 

Journal of Global Environmental Change. 

Augenstein, D., and Pacey, J., 1991, Landfill methane models, in 

Hickman, H.L., Jr., ed., Proceedings from the technical sessions of SWANA's 29th Annual International Solid Waste 

Exposition: Silver Spring, Md., Solid Waste Association of 

North America, p. 1-25. 

Augenstein, D., and Pacey, J., 1992, Landfill gas energy 

utilization-Technology options and case studies: Washington, D.C., U.S. Environmental Protection Agency, Report 

EPA-600/R-92-116, 81 p. 

Augenstein, D.C., Wise, D.L., and Cooney, C.L., 1977, Packed 

bed digestion of solid wastes: Resource Recovery and Conservation, v. 2, p. 257-262. 

Augenstein, D.C., Wise, D.L., Wentworth, R.L., and Cooney, 

C.L., 1976, Fuel gas recovery from controlled laqdfilling of 

municipal wastes: Resource Recovery and Conservation, 

v. 2, p. 103-117. 
AN ENERGY PERSPECTIVE ON LANDFILL GAS 379 

Baker, J.M., Peters, C.J., Perry, R., and Knight, C.P.V., 1984, 

Odour problems associated with solid-waste disposal: Public 

Health Engineering, v. 12, p. 115. 

Baker, L., Capouya, R., Cenci, C., Crooks, R., and Hwang, R., 

1990, The landfill testing program-Data analysis and evaluation guidelines: Sacramento, Calif., California Air Resources Board, 27 p. 

Barlaz, M.A., and Ham, R.K., 1990, The use of mass balances 

for calculation of the methane potential of fresh and anaerobically decomposed refuse, in Maxwell, G., Walsh, J., and 

Hirshfeld, S., eds., Proceedings from the GRCDA 13th Annual International Landfill Gas Symposium: Government 

Refuse Collection and Disposal Association, Silver Spring, 

Md., p. 231-241. 

Barlaz, M.A., Ham, R.K., and Schaefer, D.M., 1990, Methane 

production from municipal refuse-A review of enhancement techniques and microbial dynamics: Critical Reviews 

in Environmental Control, v. 19, no. 6, p. 557-584. 

Barlaz, M.A., Ham, R.K., and Schaefer, D.M., l989a, 

Mass-balance analysis of anaerobically decomposed refuse: 

Journal of Environmental Engineering, American Society of 

Civil Engineers, v. 115, no. 6, p. 1088-1102. 

Barlaz, M.A., Ham, R.K., and Schaefer, D.M., 1992, Microbial, 

chemical and methane production characteristics of anaerobically decomposed refuse with and without leachate recycling: Waste Management and Research, v. 10, p. 257-267. 

Barlaz, M.A., Milke, M.W., and Ham, R.K., 1987, Gas production parameters in sanitary landfill simulators: Waste Management & Research, v. 5, p. 27-39. 

Barlaz, M.A., Schaefer, D.M., and Ham, R.K., 1989b, Bacterial 

population development and chemical characteristics of 

refuse decomposition in a simulated sanitary landfill: Applied and Environmental Microbiology, v. 55, no. l, 

p. 55-65. 

Barlaz, M.A., Schaefer, D.M., and Ham, R.K., 1989c, Inhibition 

of methane formation from municipal refuse in laboratory 

scale lysimeters: Applied Biochemistry and Biotechnology, 

v. 20/21, p. 181-205. 

Berenyi, E., and Gould, R., 1991, 1990-1991 Methane recovery 

from landfill yearbook: New York, Government Advisory 

Association, Inc., 386 p. 

Bingemer, H.G., and Crutzen, P.J., 1987, The production of 

methane from solid waste: Journal of Geophysical Research, 

v. 92, no. D2, p. 2181-2187. 

Bogardus, E.R., 1984, Should you recover landfill gas?: BioCycle, v. 25, p. 48. 

Bogner, J .E., 1991, Energy Potential of modem landfills, in Bogner, J.E., ed., Illinois Energy Conference: U.S. Department 

of Energy, 11 p. 

Bogner, J.E., Vogt, M., and Miller, R.M., 1990, Studies of soil, 

gas generation, and shallow microbial activity at Mallard 

North Landfill, DuPage County, Illinois, in Maxwell, G., 

Walsh, J., and Hirshfeld, S., eds., Proceedings from the 

GRCDA 13th Annual International Landfill Gas Symposium: Government Refuse Collection ~nd Disposal Association, Silver Spring, Md., p. 195-212. 

Bookter, T.J., and Ham, R.K., 1982, Stabilization of solid waste 

in landfills: Journal of Environmental Engineering, American Society of Civil Engineers, v. 108, no. EE6, 

p. 1089-1100. 

Brennan, T., 1989, Calderon air "SWATS"-What are they telling us?, in Myers, J.D., Van Heuit, R.E., and Haley, L.W., 

eds., Proceedings from the GRCDA 12th Annual International Landfill Gas Symposium: Silver Spring, Md., Government Refuse Collection and Disposal Association, p. 13-29. 

Brown, J.W., Pfeffer, J.T., and Liebman, J.C., 1976, Biological 

conversion of organic refuse to methane: Urbana, Illinois, 

U.S. Energy Research and Development Administration Report C00/2917-3. 

Buivid, M.G., 1980, Laboratory simulation of fuel gas production 

enhancement from municipal-solid-waste landfills: Dynatech 

Research and Development Co., Final Report to Pacific Gas 

and Electric Co. and Southern California Gas Co. 

California Waste Management Board, 1989, Landfill gas characterization, in Myers, J.D., Van Heuit, R.E., and Haley, L.W., 

eds., Proceedings from the GRCDA 12th Annual International Landfill Gas Symposium: Silver Spring, Md., Government Refuse Collection and Disposal Association, p. 61-80. 

Campbell, D.J.V., and Croft, B., 1990, Landfill gas enhancement-Brogborough test cell programme, in Richards, G.E., 

and Alston, Y.R., eds., Landfill gas-Energy and environment '90: Bournemouth, England, Harwell Laboratories, 

p. 281-303. 

C-E Lummus, and SCS Engineers, 1983, City of San Antonio--

Landfill gas recovery project study: Houston, Report to the 

City of San Antonio, Tex., 98 p. 

Colt, J., Harvey, R., Lockhead, M., Mayer, S., Bocutti, L., and 

Hogan, K., 1990, Methane emissions from solid-waste landfills in the United States, in ICF, Inc., ed., International 

Workshop on Methane Emissions from Natural Gas Systems, Coal Mining and Waste Management Systems: U.S. 

Environmental Protection Agency. ' 

Crouch, E.A.C., Green, L.C., and Zemba, S.G., 1990, Estimation 

of health risk from landfill gas emissions, in Maxwell, G., 

Walsh, J., and Hirshfeld, S., eds., Proceedings from the 

GRCDA 13th Annual International Landfill Gas Symposium: Government Refuse Collection and Disposal Association, Silver Spring, Md., p. 87-94. 

Dair, R.R., and Schwegler, R.E., 1974, Energy recovery from 

landfills: Waste Age, March/April 1974, p. 6-10. 

DeWalle, F.B., Chian, E.S.K., and Hammerberg, E., 1978, Gas 

production from solid waste in landfills: Journal of the Environmental Engineering Division, American Society of Civil 

Engineers, v. 104, no. EE3, p. 415-432. 

Dimmick, F., Chow, A., Kuo, I., Howle, R., and Crenshaw, J., 

1990, USEPA Clean Air Act regulations for landfill gas 

emission, in Maxwell, G., Walsh, J., and Hirshfeld, S., eds., 

Proceedings from the GRCDA 13th Annual International 

Landfill Gas Symposium: Government Refuse Collection 

and Disposal Association, Silver Spring, Md., p. 243-255. 

Doyle, A.A., 1985, New landfill breaks new ground: Public 

Works, v. 116, no. 11, p. 59. 

Emcon Associates, 1980, Methane generation and recovery from 

landfills: Ann Arbor, Mich., Ann Arbor Science Publishers, 

139 p. 

---1981a, State of the Art of Landfill Gas Recovery: San 

Jose, Calif., Argonne National Laboratory Report 

ANUCNSV-TM-85, 97 p. 
380 THE FUTURE OF ENERGY GASES 

---1981 b, State of the art of methane gas enhancement in 

landfills: Chicago, Ill., Argonne National Laboratory Report 

ANUCNSV-23. 

---1986, Estimating landfill gas yields, in, Proceedings of 

the Ninth International GRCDA Landfill Gas Symposium: 

Silver Spring, Md., Government Refuse Collection and Disposal Association. 

Emerson, J., 1990, Suggested control measure for landfill gas 

emissions: Sacramento, Calif., California Air Resources 

Board, 54 p. 

Environmental Protection Agency, 1987, Municipal landfill gas 

condensate: Washington, D.C., Environmental Protection 

Agency, Office of Solid Waste, Report EPA/600-2-87090, 

45 p. 

---1990, Characterization of municipal solid waste in the 

United States-1990 Update: Washington, D.C., U.S. Environmental Protection Agency, Office of Solid Waste, Executive Summary, EPA/520-SW-90-042A, 15 p. 

---1991, Air Emissions from municipal solid waste landfills-Background information for proposed standards and 

guidelines: Washington, D.C., U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, 

Report EPA-450/3-90-0 11 a, 35 p. 

Farquhar, G.J., and Rovers, F.A., 1973, Gas production during 

refuse decomposition: Water Air and Soil Pollution, v. 2, 

p. 483-495. 

Farquhar, G.L., Soyupak, S., Constable, T.W., and Sykes, J.F., 

1979, Fundamentals of gas generation in landfills: Berlin, 

Technische Universitat Berlin, Abfallwirtschaftsseminar, 

Einladung zum 10, p. 1-33. 

Fetter, C.W., 1988, Applied hydrogeology: Columbus, Ohio, 

Merrill Publishing Company, 592 p. 

Freemon, J.P., 1989, Landfill gas recovery projects of the county 

sanitation districts of Los Angeles County, in Myers, J.D., 

Van Heuit, R.E., and Haley, L.W., eds., Proceedings from 

the GRCDA 12th Annual International Landfill Gas Symposium: Silver Spring, Md., Government Refuse Collection 

and Disposal Association, p. 218-234. 

Glockner, W.D., 1989, New opportunities in the landfill gas industry created by regulatory changes, in Myers, J.D., Van 

Heuit, R.E., and Haley, L.W., eds., Proceedings from the 

GRCDA 12th Annual International Landfill Gas Symposium: Silver Spring, Md., Government Refuse Collection 

and Disposal Association, p. 2-11. 

Golueke, C.G., 1970, Comprehensive studies of solid wastes 

management, third annual report: Berkeley, University of 

California, SERL Report No. 70-2. 

Graff, G.P., 1989, Green(hous)ing of the landfill: Waste Age, 

March 1989, p. 82-86. 

Ham, R.K., 1976, Solid waste degradation due to shredding and 

sludge addition, in Genetelli, E.J., and Cirello, J., eds., Gas 

and leachate from landfills-Formation, collection, and 

treatment, U.S. Environmental Protection Agency, Report 

EPA-600/9-76-004, p. 168-189. 

---1979, Predicting gas generation from landfills: Waste 

Age, November 1979, p. 50-56. 

---1992, Sanitary landfill-Proactive or reactive?: Waste 

Age, February 1992, p. 73-78. 

Ham, R.K., and Barlaz, M.A., 1987, Measurement and prediction 

of landfill gas quality and quantity, in Proceedings of International Symposium on Process, Technology, and Environmental Impact of Sanitary Landfill: CISA, Environmental 

Sanitary Engineering Centre, p. l-24. 

Hanashima, J., Yamamaski, K., Matsufuji, Y., Tanaka, M., and 

Ikeguchi, T., 1983, Technological progress of inland reclamation in Japan, in Reclamation '83 Papers: Tunbridge 

Wells, England, Industrial Seminars, p. 327-336. 

Harper, S.R., and Pohland, F.G., 1988, Landfills-Lessening environmental impacts: Civil Engineering, November 1988, 

p. 66-69. 

Hartner, D.K., 1990, Evaluation of landfill methane monitoring: 

Pittsburgh, Pa., University of Pittsburgh, M.S. thesis, 152 

p. 

Hartz, K.E., and Ham, R.K., 1983, Moisture level and movement effects on methane production rates in landfill samples: Waste Management and Research, v. 1, p. 139-145. 

Hartz, K.E., Klink, R.E., and Ham, R.K., 1982, Temperature effects-Methane generation from landfill samples: Journal 

of Environmental Engineering, American Society of Civil 

Engineers, v. 108, no. EE4, p. 629-638. 

Haxo, H.E., Jr., 1976, Assessing synthetic and admixed materials for lining landfills, in Genetelli, E.J ., and Cirello, J ., 

eds., Gas and leachate from landfills-Formation, collection, and treatment, U.S. Environmental Protection Agency, 

Report EPA-600/9-76-004, p. 130-158. 

Heie, A., and Minaas, J ., 1981, Garbologists, in Bridgewater, 

A., and Lidgren, K., eds., Household waste management in 

Europe--economics and techniques: New York, Van Nostrand Reinhold, p.45-62. 

Hickman, D.A., and Schmidt, L.D., 1993, Production of syngas 

by direct catalytic oxidation of methane: Science, v. 259, 

p. 343-346. 

Hoeks, J., 1983, Significance of biogas production in waste 

tips: Waste Management and Research, v. 1, p. 323-335. 

Hoffman, M.S., Foley, J., McGuire, T., Young, D., Georgiadis, 

A., and Northrop, M., 1991, The world almanac and book 

of facts: New York, Pharos Books, 960 p. 

Holsen, TM., Scheff, P.A., Chaberski, C.M., Hall, C.G., and 

Khalili, N ., 1990, Determination of the composition of landfill gas, in Maxwell, G., Walsh, J., and Hirshfeld, S., eds., 

Proceedings from the GRCDA 13th Annual International 

Landfill Gas Symposium: Government Refuse Collection 

and Disposal Association, Silver Spring, Md., p. 35-44. 

Hutchinson, P.J., 1989, Landfill gas-Results of investigation: 

Pittsburgh, Pa., Chambers Development Co., unpublished report, 21 p. 

---1990, Landfill gas-A significant resource [abs.]: American Association of Petroleum Geologists Bulletin, v. 39, 

no. 5, p. 680. 

---1991, Resource potential of municipal waste biogenic gas 

[abs.]: American Association of Petroleum Geologists Bulletin, v. 75, no. 3, p. 1385. 

Ito, T., Wang., J.-X., and Lunsford, J.H., 1985, Oxidative dimerization of methane over a lithium-promoted magnesium 

oxide catalyst: Journal of the American Chemical Society, 

v. 107, p. 5062-5068. 

Jenkins, R.L., and Pettus, J.A., 1985, The use of in:vitro anaerobic landfill samples for estimating landfill gas generation 

rates, in Antonopoulos, A., ed., Proceedings of the First 

Symposium on Biotechnological Advances in Processing 
AN ENERGY PERSPECTIVE ON LANDFILL GAS 381 

Municipal Wastes for Fuels and Chemicals: Chicago, Illinois, Argonne National Laboratory. 

Jeris, J.S., and McCarty, P.L., 1965, The biochemistry of methane fermentation using cl4 tracers: Journal of Water Pollution Control Federation, v. 37, p. 178. 

Keller, A.P., 1988, Trace constituents in landfill gas: Chicago, 

Ill., Gas Research Institute Report GRI-87/0018.2, 128 p. 

Kiser, J.V.L., and Sussman, D.B., 1991, Municipal waste combustion and mercury-The real story: Waste Age, November 

1991, p. 41-44. 

Klink, R.E., and Ham, R.K., 1982, Effects of moisture movement 

on methane production in solid-waste samples: Resource 

Recovery and Conservation, v. 8, p. 29-35. 

Lagerkvist, A., 1991, Two step degradation-An alternative management technique, in Margherita di Pula, S., ed., Proceedings Sardinia '91, Third International Landfill Symposium: 

CISA, Environmental Sanitary Engineering Centre, p. 1-8. 

Lawson, P.S., Campbell, D.J.V., Lagerkvist, A., and Meijer, J.E., 

1991, Landfill gas enhancement test cell data exchange: 

Didcot, England, Harwell Laboratory, 250 p. 

Leach, A., 1990, Landfill gas abstraction, in Richards, G.E., and 

Alston, Y.R., eds., Landfill gas-Energy and environment 

'90: Bournemouth, England, Harwell Laboratories, 

p. 204-222. 

Leckie, J.O., 1974, Estimation of potential methane production 

from solid-waste landfills: San Jose, Calif., Emcon Associates, unpublished report. 

Leckie, O.J., Pacey, J.G., and Halvadakis, C., 1979, Landfill 

management with moisture control: Journal of the Environmental Engineering Division, American Society of Civil Engineers, v. 105, no. EE2, p. 337-355. 

Lee, G.F., and Jones, R.A., 1991, Landfills and groundwater 

quality: Ground Water, v. 29, no. 4, p. 482-486. 

Levy, S.J., and Rigo, H.G., 1976, Resource recovery plant implementation-Guide for municipal officials: Washington, D.C., 

U.S. Environmental Protection Agency, Report SW-157.2, 

81 p. 

Lisk, D.J., 1991, Environmental effects of landfills: The Science 

of the Total Environment, v. 100, p. 215-468. 

Lynd, L.R., Cushman, J.H., Nichols, R.J., and Wyman, C.E., 

1991, Fuel ethanol from cellulosic biomass: Science, v. 251, 

p. 1318-1323. 

Mah, R.A., Ward, D.M., Baresi, L., and Glass, T.L., 1977, Biogenesis of methane: Annual Reviews in Microbiology, v. 31, 

p. 309. 

Marshall, B.N., 1988, Landfill gas collection systems-Cost, effectiveness, and maintenance, in Carolan, M.J., Martin, 

H.L., Flanagan, K.A., and Haley, L.W., eds., Proceedings 

from the GRCDA 11th International Landfill Gas Symposium: Silver Spring, Md., Government Refuse Collection 

and Disposal Association, p. 147-160. 

Maxwell, G., 1990, Will gas-to-energy work at your landfill?: 

Solid Waste & Power, June 1990, p. 44-50. 

McCarty, P.L., 1981, One hundred years of anaerobic treatment, 

in Hughes, D.E., Stafford, D.A., Wheatley, B.I., Baader, W., 

Lettinga, G., Nyns, E.J., Verstraete, W., and Wentworth, 

R.L., eds., Anaerobic digestion 1981: New York, Elsevier 

Biomedical Press, p. 3-22. 

Miller, M.J ., and Quinn, J., 1990, Reclaiming landfill sites for 

urban agriculture, in Maxwell, G., Walsh, J., and Hirshfeld, 

S., eds., Proceedings from the GRCDA 13th Annual International Landfill Gas Symposium: Government Refuse Collection and Disposal Association, Silver Spring, Md., 

p. 175-179. 

Monod, J., 1950, La technique de culture continue-Theorie et 

applications: Annals Institute Pasteur, v. 79, p. 390-410. 

Mosey, F.E., and Mistry, P.B., 1990, Biological is best-How 

feasible is municipal solid waste digestion for the UK?, in 

Richards, G.E., and Alston, Y.R., eds., Landfill gas-Energy 

and environment '90: Bournemouth, England, Harwell Laboratories, p. 387-402. 

Naveau, H., 1984, Anaerobic digestion in the European Economic Community, in Ferrero, G.L., Ferranti, M.P., and Naveau, 

H., eds., Anaerobic Digestion and Carbohydrate Hydrolysis 

of Waste: London, Elsevier Applied Science Publisher, 

p. 182-187. 

Pacey, J.G., Glaub, J.C., and Van Heuit, R.E., 1987, Results of 

the Mountain View controlled landfill project, in Hickman, 

L.H., Jr., ed., Proceedings of the GRCDA 1Oth International 

Landfill Gas Symposium: Silver Spring, Md., Government 

Refuse Collection and Disposal Association. 

Parker, A., 1983, Behaviour of wastes in landfill-methane generation, in Holmes, J.R., ed., Practical waste management: New 

York, John Wiley & Sons, chapter 8. 

Parker, C., and Roberts, T., 1985, Energy from waste-An evaluation of conversion technologies: London, Elsevier Applied 

Science Publishers, 250 p. 

Pennsylvania Department of Environmental Resources, 1989, 

Guidance Manual for Landfill Gas Management: Harrisburg, 

Pa., Commonwealth of Pennsylvania, Bureau of Waste Management, 21 8 p. 

Periana, R.A., Taube, D.J., Evitt, E.R., Loffler, D.G., Wentrcek, 

P.R., Voss, G., and Masuda, T., 1993, A mercury-catalyzed, 

high-yield system for the oxidation of methane to methanol: 

Science, v. 259, p. 340-343. 

Pfeffer, J.T., 1974a, Reclamation of energy from organic waste: 

Washington, D.C., U.S. Environmental Protection Agency, 

Report EPA-670/2-74-016, 35 p. 

---1974b, Temperature effects on anaerobic fermentation of 

domestic refuse: Biotechnology and Bioengineering, v. 16, 

p. 771-781. 

Pohland, F.G., Dertien, J.T., and Gosh, S.B., 1983, Leachate and 

gas quality during landfill stabilization of municipal refuse, 

in Proceedings of the 3rd International Symposium on Anaerobic Digestion, Evans and Faulkner, Cambridge, Mass., 

p. 185-201. 

Rathje, W.L., 1991, The history of garbage: Garbage, September 

1991, p. 32-36. 

Rees, J.F., 1980a, The fate of carbon compounds in the landfill 

disposal of organic matter: Journal of Chemical Technology 

and Biotechnology, v. 30, p. 161-175. 

---1980b, Optimization of methane production and refuse 

decomposition in landfill by temperature control: Journal of 

Chemical Technology and Biotechnology, v. 30, p. 458-465. 

Rettenberger, G., 1987, Trace composition of landfill gas, in Proceedings of International Symposium on Process, Technology, and Environmental Impact of Sanitary Landfill: CISA, 

Environmental Sanitary Engineering Centre, p. 1-12. 

Richards, K.M., and Aitchison, E.M., 1990, Landfill gas-Energy 

and environmental themes, in Richards, G.E., and Alston, 
382 THE FUTURE OF ENERGY GASES 

Y.R., eds., Landfill gas-Energy and environment '90: 

Boumemouth, England, Harwell Laboratories, p. 21-44. 

Rijkens, B.A., and Voetberg, J.W., 1981, Two-step process for 

anaerobic digestion of solid wastes, in Hughes, D.E., 

Stafford, D.A., Wheatley, B.I., Baader, W., Lettinga, G., 

Nyns, E.J., Verstraete, W., and Wentworth, R.L., eds., 

Anaerobic Digestion 1981: New York, Elsevier Biomedical 

Press, p. 382. 

Seeker, W.R., Heap, M.P., Landrum, V., Lanier W.S., and Linz, 

D.G., 1989, Applications study and research needs assessment for natural gas use for waste management: Chicago, 

Ill., Gas Research Institute, Topical Report GRI-89/0012, 

100 p. 

Senior, E., 1990, Introduction, in Senior, E., ed., Microbiology of 

Landfill Sites: Boca Raton, Fla., CRC Press, p. 1-15. 

Senior, E., and Ba1ba, M.T.M., 1990, Refuse decomposition, in 

Senior, E., ed., Microbiology of Landfill Sites: Boca Raton, 

Fla., CRC Press, p. 17-57. 

Senior, E., and Kasali, G.B., 1990, Landfill gas, in Senior, E., 

ed., Microbiology of Landfill Sites: Boca Raton, Fla., CRC 

Press, p. 113-158. 

Senior, E., and Shibani, S.B., 1990, Landfill leachate, in Senior, 

E., ed., Microbiology of Landfill Sites: Boca Raton, Fla., 

CRC Press, p. 81-111. 

Soerjani, M., 1984, Present waste management in cities in Indonesia: Conservation & Recycling, v. 7, p. 181-185. 

Thome-Kozmiensky, K.J., 1977, Ubersicht uber die Moglichkeiten und Alternativen des Material Recycling: Berlin, 

Technische Universitiit Berlin, Abfallwirtschafts seminar, 

v. I, p. 5-35. 

Thorneloe, S., 1990, United States research on enhancing landfill 

gas production, in Lawson, P.S., Campbell, D.J.V., Lagerkvist, A., and Meijer, J.E., eds., Landfill Gas Enhancement Test Cell Data Exchange: Bournemouth, England, 

Harwell Laboratories, p. 1-68. 

Vogt, W.G., and Conrad, E.T., 1988, Landfill gas trace constituents-VOCs versus ROGs, in Carolan, M.J., Martin, H.L., 

Flanagan, K.A., and Haley, L.W., eds., Proceedings from the 

GRCDA ll th International Landfill Gas Symposium: Silver 

Spring, Md., Government Refuse Collection and Disposal 

Association, p. 187-199. 

Wald, M.L., 1991, From a pollutant, a cleaner fuel: New York 

Times, August 21, 1991, p. C5. 

Walsh, P., and O'Leary, P., 1991, Sanitary landfill design procedures-Lesson 6: Waste Age, September 1991, p. 97-105. 

Ward, R.F., 1988, Landfill gas production, in Carolan, M.J., Martin, H.L., Flanagan, K.A., and Haley, L.W., eds., Proceedings from the GRCDA 11th International Landfill Gas 

Symposium: Silver Spring, Md., Government Refuse Collection and Disposal Association, p. 161-186. 

Wegener, R.W., and Lekstutis, J.P., 1989, LFG design for the 

long term: Waste Age, April 1989, p. 188-196. 

Westlake, K., 1990, Landfill microbiology, in Richards, G.E., 

and Alston, Y.R., eds., Landfill gas-Energy and environment '90: Oxfordshire, England, Harwell Laboratories, 

p. 271-280. 

White, L.P., and Plaskett, L.G., 1981, Biomass as Fuel: London, 

Academic Press, 355 p. 

Wilke, M.L., Zimmerman, R.E., and Isaacson, H.R., 1982, 

Methane from landfills-Preliminary assessment workbook: 

Chicago, Ill., Argonne National Laboratory, Report 

No. ANUCNSV-31, 24 p. 

Willumsen, H.C., 1990, Registration and optimizing of gas production from closed waste test cells in landfills: Denmark, 

Ministry of Energy, Report J. No. 1383/86-9, 45 p. 

Wolfe, R.S., 1982, Biochemistry of methanogenesis: Experimentia, v. 38, p. 198-203. 

Wood, J.A., Porter, M.L., and Wadley, M.W., 1986, Toxics in 

Class II landfill gas: American Chemical Society Division of 

Environmental Chemistry, v. 26, no. 2, p. 347-350. 

Young, C.P., and Blakely, N.C., 1990, Gases in, gases out: Monitored emissions from power generation projects, in Richards, 

G.E., and Alston, Y.R., eds., Landfill gas-Energy and environment '90: Oxfordshire, England, Harwell Laboratories, 

p. 317-329. 

Young, L.Y., and Frazer, A.C., 1987, The fate of lignin and 

lignin-derived compounds in anaerobic environments: 

Geomicrobiology Journal, v. 5, no. (3/4), p. 261-293. 

Young, P.J., and Parker, A., 1983, The identification and possible 

environmental impact of trace gases and vapours in landfill 

gas: Waste Management and Research, v. 1, p. 213-226. 

Zehnder, A.J.B., 1978, Ecology of methane formation, in Mitchell, R., ed., Water pollution microbioiogy: New York, 

Wiley-Interscience, p. 349-376. 

Zehnder, A.J.B., Ingvorsen, K., and Marti, T., 1981, Microbiology of methane bacteria, in Hughes, D.E., Stafford, D.A., 

Wheatley, B.l., Baader, W., Lettinga, G., Nyns, E.J., Verstraete, W., and Wentworth, R.L., eds., Anaerobic Digestion 

1981: New York, Elsevier Biomedical Press, p. 45-68. 

Zeikus, J. G., 1981, Microbial intermediary metabolism in anaerobic digestion, in Hughes, D.E., Stafford, D.A., Wheatley, 

B.I., Baader, W., Lettinga, G., Nyns, E.J., Verstraete, W., and 

Wentworth, R.L., eds., Anaerobic Digestion 1981: New 

York, Elsevier Biomedical Press, p. 23-35. 

---1983, Metabolism of one-carbon compounds by chemotropic anaerobes: Advances in Microbial Physiology, v. 24, 

p. 215. 

Zimmerman, R.E., Walsh, J.J., and Wilkey, M.L., 1985, Landfill 

gas-Resource Evaluation and development: Chicago, Ill., 

Gas Research Institute, Report No. GRI-85/0259, 137 p. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

A Survey of Natural Gas Dissolved in Brine 

By Sullivan Marsden1 

CONTENTS 

Abstract ......................................................................... 383 

Introduction ................................................................... 383 

Background of the Dissolved-Gas Resource ............... 384 

Worldwide Distribution of Hydropressured 

Natural Gas ................................................................... 384 

Japan ...................................................................... 384 

Italy ........................................................................ 385 

The Commonwealth of Independent States .......... 385 

The United States ................................................... 385 

Philippines .............................................................. 386 

China ...................................................................... 386 

Summary and Conclusions ........................................... 386 

Acknowledgments ........................................................ 386 

Selected References ...................................................... 387 

ABSTRACT 

Natural gas, composed primarily of methane, is found 

dissolved in aquifers in many parts of the world. This natural gas can provide an important energy source in those 

areas where conventional natural gas reserves are absent 

but where economical methods for drilling, development, 

and production of hydropressured natural gas are available. There are some distinct geological and geochemical 

signs which indicate the presence of natural gas dissolved 

in aquifers, such as the presence of iodine. Extraction of 

such iodine is a source of additional revenue to gas producers, thus improving the overall economics of exploita1

Stanford University, Department of Petroleum Engineering, Stanford, CA 94305-2220. 

tion of dissolved natural-gas resources. The experience of 

those who have already found methods to exploit these resources, principally the Japanese, can be very valuable in 

the future development of this resource. 

INTRODUCTION 

Natural gas, along with petroleum, coal, and nuclear 

energy, is one of the major energy resources of the United 

States and many other countries around the world. Each of 

these resources has its own requirements for exploitation, 

such as geographical location, accessibility, estimates of 

available reserves, possible environmental problems, and 

costs of production and -transportation. Because of the 

world's ever-growing energy demands, all of these resources, along with various so-called renewable energy 

sources, have been and will continue to be tapped. 

The major sources of gas for domestic, industrial, and 

commercial use in the United States come from what are 

termed "conventional resources," usually involving gas associated with crude oil accumulations, although significant 

amounts of dry (no oil found in association) gas accumulations are also being exploited. There are, however, numerous unconventional settings for natural-gas accumulations 

that have received varying amount of attention. In recent 

years, the U.S. Department of Energy has supported research in production of natural gas from geopressured reservoirs, coal beds, and Devonian shales. These sources 

show promise, and some natural gas is being produced 

from them, but many experts have serious doubts about 

their economic viability. Besides the sources of natural gas 

mentioned above, there is another major source, which is 

mainly ignored in such energy-rich countries as the United 

States, but is utilized in energy-poor countries such as 

Japan. This resource is gas dissolved in underground brines 

under normal hydrostatic pressure, not at the abnormally 

383 
384 THE FUTURE OF ENERGY GASES 

high pressures of geopressured reservoirs. Gas dissolved in 

underground brines is called hydrostatic natural-gas (or 

brine gas) accumulations-the Japanese call them "suiyoseitennengasu" reservoirs. Hydrostatic brine and geopressured gas reservoirs are quite different and distinct in both 

their physical properties and problems involved in their exploration, drilling, completion, production, economics, and 

marketing. 

I have studied hydrostatic brine reservoirs in Japan and 

elsewhere for the past quarter of a century and written a 

number of reports (Marsden and Kawai, 1965; Marsden, 

1979a, 1979b) with several Japanese collaborators to supplement the rather extensive literature written in Japanese, 

which is inaccessible to most people. These studies have 

been supplemented by notes from field trips in Japan from 

1963 to the present and discussions with scientists and engineers from other countries, in particular Italy, the People's 

Republic of China, the Philippines, and the Commonwealth 

of Independent States (the former Soviet Union), where 

brine gas is known and utilized whenever possible. 

In the United States, hydropressured brine gas is produced on a limited scale, but this production is often not 

accurately reported owing to complex accounting procedures. Compared to dry or associated natural-gas fields, dissolved natural gas in brines occurs in relatively small and 

widely scattered reservoirs, which do not interest the large 

energy companies. 

The purpose of this report is to present a brief summary 

of important aspects of the occurrence of hydropressured 

brine gas resources as it is described in the technical literature, and by various researchers in the field. Interested readers are encouraged to look to the literature for more data 

and more in-depth discussions. This was a subject of great 

interest a couple of years ago; but at the present time, especially in North America, it has been given less attention. 

My personal hope is that this paper will engender more 

interest in brine gas, as our full understanding as well as the 

resource potential of this energy source is incomplete. Although some reports describe both hydropressured and 

geopressured reservoirs, we shall omit discussion of the 

latter. References are made to the few reports in English on 

the subject of natural gas dissolved in brines, and the reader 

is referred to them for details and statistics on reserves, 

production, extent, and so forth. There is extensive literature written in Japanese, but except for abstracts written in 

English, this literature is generally inaccessible. 

BACKGROUND OF THE 

DISSOLVED-GAS RESOURCE 

To understand the nature of natural gas dissolved in 

brines, we must reconsider certain basic, well-known physical concepts. The solubility of a gas (for example, natural 

gas) in a liquid (for example, water) increases with increasing pressure and decreases with increasing temperature. It 

is also known that the hydrostatic pressure of underground 

fluids increases with depth and that the subsurface temperature increases with depth. Of these factors, which have opposing effects on the solubility of gases in underground 

waters, solubility is influenced much more by pressure than 

by temperature. Hence, the amount of natural gas dissolved 

in underground liquids increases greatly with depth. 

Because of the chemical similarity of organic gases, 

such as methane, and organic liquids, such as crude oil, the 

solubility of methane in oil is far greater than in polar liquids, such as water or brine. The solubility of methane in 

water and brine is often considered by many people to be 

insignificant, but the Japanese natural-gas industry has produced methane from brine for many years. Since we (and 

the Japanese) know that gas is dissolved in brine in many 

locations, the primary concern is to find locations where the 

gas can be produced economically and without environmental damage. For reasons discussed below, the environmental damage caused by production of this resource in 

Japan has, in recent years, curtailed some production, even 

though the Japanese have now developed environmentally 

safe production methods. Environmental concerns involve 

subsidence and brine disposal. As the international price of 

crude oil and LNG (liquefied natural gas) are relatively low, 

the Japanese, with their high national energy demands, 

have favored these energy sources, while keeping "suiyoseitennengasu" as a reserve. 

Although hydropressured natural-gas fields are only 

minimally developed in the United States, wells can be 

drilled relatively fast and inexpensively because the gas 

fields are found at depths ranging from a few hundred to a 

few thousand of feet and because they usually occur in 

relatively soft sedimentary rocks. Brines can introduce corrosion problems for steel, which is the normally used casing material in wells, so PVC (polyvinylchloride) casing is 

normally used, which also reduces completion and production costs. Other more modem plastic pipe might be even 

less costly and easier to use. 

WORLDWIDE DISTRIBUTION OF 

HYDROPRESSURED NATURAL GAS 

JAPAN 

In terms of both production and reserves of natural 

gas dissolved in brines, the country of greatest importance 

is Japan. This has been discussed extensively in three reports written with Japanese colleagues (Marsden and 

Kawai, 1965; Marsden, 1979a, 1979b) and summarized 

briefly in a report by Bonham (1979). The reader is referred to these reports for details. 

The production of natural gas dissolved in brines is a 

stable, profitable, and somewhat expanding industry in 
A SURVEY OF NATURAL GAS DISSOLVED IN BRINE 385 

Japan, because the companies there have developed lowcost drilling, development, and production methods to provide for an indigenous energy source. Production from the 

older fields is reasonably stable, and the estimated reserves 

are very extensive. In addition, the recovery of iodine from 

the produced brines has improved the overall profits significantly. Land subsidence, which results from fluid withdrawal, has been arrested by brine reinjection after the 

methane and iodine have been removed. 

Countries wishing to develop this resource would do 

well to consult with the natural-gas companies operating in 

Japan. For three decades, the Japanese have been very helpful in arranging many field trips and supplying information 

on their natural-gas production operations, as have some of 

the faculty in the Department of Mineral Development Engineering (formerly Petroleum Engineering) at the University of Tokyo. 

In recent years technical interest in natural gas dissolved in brines has extended to two other universities in 

Japan. Starting in 1985, Professor Satoshi Akibayashi of 

Akita University has published a series of seven reports 

(Akibayashi and Zhou, 1985, 1986, 1988; Akibayashi and 

others, 1988, 1988; Zhou and others, 1989; Akibayashi and 

Yamaguchi, 1992) on the numerical simulation of the behavior of Mobara-type gas reservoirs. While most of these 

reports are in Japanese, all have at least an abstract in English and each presents a development beyond its predecessor. More recently, Prof. Toyohiko Yamazaki of Waseda 

University has presented a report with Yoshiyuki Tazoki of 

Kanto Natural Gas Development Company (Tazaki and 

Yamazaki, 1993) on another simulation study of Mobaratype dissolved natural-gas reservoirs. 

ITALY 

Hydropressured natural gas is produced with brine in 

the eastern Po River plain of northern Italy from wells that 

are usually less than 500 m deep. Early production data 

and information on reserves have been summarized briefly 

by Bonham (1979); a much older report by Reeves (1953) 

gives more information on the geology of the area. The 

production of natural gas from brines in Italy is mostly of 

historical interest-it started a half century ago-because 

it was discontinued by order of the Italian government in 

1962. Brackish water produced was not reinjected and 

there was serious land subsidence. 

THE COMMONWEALTH OF 

INDEPENDENT STATES 

As far as I have been able to ascertain, hydropressured 

natural gas is not developed as a separate resource in the 

Commonwealth of Independent States. The massive reserves and production of both dry and oil-associated natural' gas, as well as limited domestic financial resources, 

have encouraged the development, use, and export of 

geopressured natural gas to the rest of Europe. Bonham 

(1979) has quoted estimates of natural gas dissolved in 

formation water for both oil and ordinary natural-gas 

fields, stating they are "gigantic." However, I have found 

no indication that this resource is now utilized, even locally, in otherwise energy-deficient areas of the Commonwealth of Independent States. 

THE UNITED STATES 

It is best to divide hydropressured gas production in 

the United States into the three major States where it has 

been reported (Bonham, 1979), California, Oklahoma, and 

Texas (including parts of Louisiana). In terms of both production and documented reserves, hydropressured gas is 

not now a major resource in the U.S., but it could become 

one in the future. 

It is common in some parts of California (and probably elsewhere) to find natural gas dissipating from fresh 

water in relatively shallow water wells. An example is natural gas dissolved in water discovered during excavation 

of a building site in Fresno (K.W. Eampbell, oral commun., 1993). In a few areas this has led to further drilling 

to recover the gas for use as a domestic and industrial 

fuel. Sometimes brine gas has been blended with natural 

gas derived from other sources, because that produced 

from water wells has been insufficient to meet the supply 

requirements. In soine rural areas, wells drilled to produce 

water for cattle have also produced natural gas which is 

run into stationary internal combustion engines, for electrical power generation. The power is used only for very 

local purposes. Some hydropressured gas has been found 

in connection with geopressured gas in Texas and parts of 

Louisiana, but the geopressured gas has been the major 

focus in these regions, and little is known about the hydropressured gas. 

The association of natural gas dissolved in brine and 

iodine has been noticed elsewhere besides Japan, and this 

has led to the development of an iodine resource in the 

United States. Routine analyses of brines produced from 

oil- and gas-field exploration and development activities in 

the North Boiling Springs gas field of northwestern Oklahoma near the town of Woodward have demonstrated the 

existence of unusually high iodine concentrations (about 

325 parts per million (ppm)) (W. Gerber, Woodard Iodine 

Company, oral commun., 1993). This iodine resource was 

developed originally by Amoco Production Company and 

Houston Chemicals, a subsidiary of Pittsburgh Plate Glass. 

The present operating company is the Woodward Iodine 

Corporation, which is now fully owned by Ise Chemicals 

Corporation, a subsidiary of Asahi Glass Company of 
386 THE FUTURE OF ENERGY GASES 

Japan. The total gas production for the past one and onehalf decades has been about 8.9 billion cubic feet (Bcf); 

the overall gas/water ratio has been about 29 cubic feet 

per barrel. ( cf/bbl) and the present gas/water ratio is about 

26 cf/bbl from 22 production wells serving 10 reinjection 

wells (W. Gerber, Woodard Iodine Company, oral commun., 1993). While the major component of this gas is 

methane (more than 90 percent) small amounts of ethane, 

nitrogen, carbon dioxide, and trace amounts of other aromatic hydrocarbons are also produced. 

The interest that developed in the United States several years ago in geopressured natural gas has led to an occasional reference to hydropressured natural gas, but 

because the two kinds are "in competition," there has been 

very little new research on geopressured, and virtually 

none on hydropressured, natural gas. The report by Bonham ( 1979) cited earlier is an important early reference on 

hydropressured gas in the United States as is the extensive 

work of Buckley and others (1958), and later work by 

Doherty ( 1981) provides another general review. 

PHILIPPINES 

In the early 1980's a joint study of hydropressured gas 

by the Japan International Cooperation Agency and the 

Geological Survey of Japan with the Department of Energy of the Republic of the Philippines covered the Iloilo 

Basin of Parray Island. The results of this very extensive 

study are given in an unpublished, 152-page report (H. 

Natori, Geological Survey of Japan, written commun., 

1993). 

Although he reported the potential for natural gas 

from this basin, the project was terminated because of lack 

of funds for exploratory drilling to establish the magnitude 

of the resource. It is noteworthy that the brine containing 

the dissolved gas also contained significant amounts of the 

iodide ion. 

CHINA 

Although deep, geopressured natural gas has been 

known in China for centuries, the documentation for shallow natural gas dissolved in brine is much more recent, 

perhaps because of the political disturbances over the past 

several decades. Since at least 1958, however, individuals 

and small industries have drilled for and produced brine 

gas for domestic use and in small factories. These reservoirs, which are mainly in Zhejiang and Jiangsu Provinces, but also in Shanghai City, are usually found at depths 

of only 6 to 50 m and have thicknesses of only 0.5 to 3 m. 

Daily production ranges from 100 to 10,000 m3 at gas 

pressures of I to 6 atm. 

This shallow gas is believed to be a promising energy 

source. Within the past decade, the .China National Petroleum Corporation has entrusted the Hangzhou Institute of 

Petroleum Geology, under the direction of Prof. Qian 

Yizhong, to conduct research on the exploration and development of shallow gas. This work is being carried out 

along the Yangtse River and coastal areas of southeastern 

China (Qian Yizhong, oral commun., 1993). 

Although gas dissolved in brine has also been reported 

in Taiwan, up-to-date information on it could n·ot be obtained for this report (Qian Yizhong, oral commun., 1993). 

Taiwan has had both significant amounts of dry and wet 

natural gas, which have been well developed in the past, 

but the major industrial needs are now supplied by imported LNG. 

SUMMARY AND CONCLUSIONS 

Natural gas dissolved in relatively shallow aquifers is 

an important resource in energy-deficient countries and 

areas such as Japan and the southern coast of China. Economical methods of drilling for and producing the dissolved gas are essential for its utilization. The recovery of 

iodine from the brines improves the economics considerably, as has been the case in Japan and may be so in the 

Philippines in the future. Sometimes iodine is the major 

product and natural gas a supplementary product, as in 

Woodward County, Oklahoma. There are indications that 

natural gas dissolved in brine is produced for local consumption in countries which also produce large quantities 

of ordinary natural gas such as the Commonwealth of Independed States (CIS), Indonesia, Malaysia, Thailand, and 

Taiwan, but reliable information is hard to find; the same 

is probably true in parts of the United States and in parts 

of Australia and in New Zealand. 

Technical, environmental, and economic problems 

must be solved for the development and continued production of natural gas dissolved in brines. The Japanese industry has been very successful in these respects and can 

be looked to for guidance. Safe and effective disposal of 

the produced water or brines is essential, otherwise the industry may be shut down, as was the case in Italy. Deep 

exploratory drilling and production tests are necessary for 

definition of a very promising dissolved natural-gas prospect such as that in the Philippines. Investment funds, 

such as from an international investment organization like 

the World Bank, are also needed. 

ACKNOWLEDGMENTS 

The valuable contributions of many people to the 

preparation of this report must be recognized. Mrs. Char-
A SURVEY OF NATURAL GAS DISSOLVED IN BRINE 387 

lotte Darksen of the Branner Earth Sciences Library conducted an excellent literature search using several data 

bases. Mr. Yutaka Higuchi, Managing Director of the 

Kanto Natural Gas Company and his many colleagues 

have been very helpful in discussions, providing reports 

and arranging field trips in the Chiba Prefecture. 

Professor Satoshi Akibayashi of Akita University and 

Professor Toyohiko Yamazaki of Waseda University have 

been generous in supplying me with their many reports on 

this subject which have unfortunately not found their ways 

into the data bases consulted. Mr. Rufino B. Bomasung of 

the Philippine Department of Energy has generously provided ·me with a full copy of the report written by Dr. 

Haroo Natori of the Geological Survey of Japan on the 

Japanese study of a major Philippine prospect. Finally, Mr. 

William R. Gerber of the Woodward Iodine Company has 

ably provided me with reports on the major field development in the United States. 

SELECTED REFERENCES 

Akibayashi, S., and Zhou, P., 1985, Simulation of production behavior in the water-dissolved gas field: Japan Underground 

Water Association Report, v. 27, no. 4. 

---1986, A numerical model for simulating production performance in the Mohara-type water-dissolved natural-gas 

field: Journal of Japanese Association for Petroleum Technology, v. 51, no. 6, p. 10-15. 

---1988, The production performance of the water-dissolved 

natural gas reservoir: 17th Offshore Southeast Asia Conference, Singapore, p. 582-590 (February). 

Akibayashi, S., Zhou, P., and Takirawa, K., 1988, Simulation of 

gas water ratio behavior in the Mohara-type water-dissolved 

natural-gas field-Radial model: Journal of Japanese Association for Petroleum Technology, v. 50, no. 3, p. 24-28. 

Akibayashi, S., Zhou, P., and Yuhara, K., 1988, A numerical 

model for simulating production behavior of multi-wells in 

the Mobara-type water-dissolved natural gas reservoir: Journal of the Japanese Association for Petroleum Technology, 

v. 53, no. 3, p. 38-44, (May). 

Akibayashi, S., and Yamaguchi, S., 1992, Simulation of high 

GWR behavior in the water-dissolved natu'ral gas reservoir: 

Journal of the Japanese Association for Petroleum Technology, v. 57, no. 5, p. 427-433. 

Bonham, L.C., 1979, Gas in subsurface waters: UNITAR Conference on long-term energy resources, Montreal, Canada (November, December). 

Buckley, S.F., Hocott, C.R., and Taggart, M.S., Jr., 1958, Distribution of dissolved hydrocarbons in subsurface waters: Habitat of Oil. UL in American Association of Petroleum 

Geologists, p. 850-882. 

Cotten, H.M., 1973, Iodine in Northwestern Oklahoma: Oklahoma Geological Survey Circular 79, p. 89-94. 

Doherty, M.G., 1981, Natural gas production from hydro-pressured aquifers: International Conference on Small Energy 

Resources, Los Angeles, CA, p. 133-137. 

Lyday, P.A., 1991, Iodine: U.S. Department of Interior, Bureau of 

Mines (October). 

Marsden, S.S., 1979a, Natural gas dissolved in· brine-A major 

energy resource of Japan: Society of Petroleum Engineers 

Annual Fall Meeting, Las Vegas, Nevada, Preprint 8355. 

---1979b, Hydropressured natural-gas reservoirs: UNITAR 

Conference on long-term energy resources, Montreal, Canada (November, December). 

Marsden, S.S., and Kawai, K., 1965, Suiyoseitennengasu-A 

special type of Japanese natural gas deposit: American Association of Petroleum Geologists, v. 49, no. 3, p. 286-295. 

Reeves, F., 1953, Italian oil and gas resources: American Association of Petroleum Geologists Bulletin, v. 37, no. 4, p. 603-

625. 

Tazaki, Y., and Yamazaki, T., 1993, Simulator for predicting the 

Mobara-type production performance: 1993 SPE Asia Pacific Oil and Gas Conference and Exhibition, Singapore, February 8-10, paper SPE 25337. 

Zhou, P., Akibayashi, S., and Yuhara, K., 1989, Numerical model 

of the production behavior for the ordinary type water-dissolved natural gas reservoir during water reinjection: Journal 

of Japanese Association for Petroleum Technology, v. 54, 

no.5,p.l-7. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Coalbed Gas-An Undeveloped Resource 

By Dudley D. Rice 1

, Ben E. Law1, and Jerry L. Clayton1 

CONTENTS 

Abstract ......................................................................... 389 

Introduction ................................................................... 389 

Generation of Coalbed Gas .......................................... 390 

Characteristics of Coalbed Gas .................................... 392 

Gas Storage ................................................................... 394 

Determination of Gas Content ..................................... 395 

Gas Production ............................................................. 396 

Environmental Concerns .............................................. 398 

Methane Emissions from Coal Mining ................. 398 

Water Disposal ..... ...... .. ... .. . ... . .. ... .. .... .. . .. .. .. .. .. .. .. .... 400 

Resource Potential . .. .. . . .. ... ... .. ....... ... .. .... .. ..... ... ... .. ... . .. .. 400 

Conclusions .......................................... _. ........................ 402 

References Cited ........................................................... 402 

ABSTRACT 

Coalbeds are both source and reservoir rocks for 

major quantities of natural gas. Large amounts of natural 

gas are generated in coalbeds throughout their burial history by both biogenic and thermogenic processes. Coalbed 

gases are variable in their molecular and isotopic composition. In addition to methane, they can contain significant 

amounts of heavier hydrocarbons and C02. The primary 

controls of hydrocarbon gas composition are coal rank and 

composition, and depth/temperature. Coalbed gas is stored 

(sorbed) upon and within the molecular structure of the 

coal. As a result, coal has the ability to hold much more 

gas than the same rock volume of a conventional reservoir 

in which gas occurs as a free or dissolved phase. The 

amount of gas stored is a function of rank, pressure, and 

1

U.S. Geological Survey, Box 25046, Federal Center MS 971, Denver, CO 80225. 

temperature. Matrix permeability is essentially nonexistent 

in coal and flow pathways for gas are provided by the 

fracture (cleat) system. Regardless of rank, nearly all coals 

contain at least some water (inherent moisture, meteoric, 

and .(or) from adjacent aquifers). Economic quantities of 

natural gas can be produced from coalbed reservoirs; desorption results from dewatering and subsequent depressurization of the coalbeds. The main environmental 

concerns about coal bed gas extraction are related to (1) 

methane emissions from coal mining and (2) disposal of 

produced water. However, significant amounts of methane 

can be captured prior to and during mining, and the water 

produced can be disposed of in an environmentally acceptable manner, such as in injection wells. Estimated resources of coalbed gas are enormous and widely distributed 

around the world. However, this resource is essentially undeveloped, except in the United States where some production and technological advances have taken place. 

INTRODUCTION 

Coal is the most abundant energy source in the world; 

reserves are estimated to be more than one trillion metric 

tons. With the expansion of global economies, particularly 

in underdeveloped countries, world coal production has 

been increasing rapidly on a yearly basis. Total production 

totaled more than 5 billion metric tons in 1990; China 

alone produced more than 1 billion metric tons. 

Coal is also a major source of gaseous hydrocarbons. 

The gas is a product of the coalification process whereby 

plant material is progressively converted to coal, generating 

large quantities of gas, which are stored within the coal 

matrix. The rank sequence from peat to meta-anthracite and 

other commonly used indices of rank and thermal maturity 

are shown in figure I. The presence of methane-rich gas 

in coal has been recognized for a long time because of 

389 
390 

Refl. 

Rank Ro 

f- 0.2 

Peat 

~ 

f- 0.3 

Lignite 

c 0.4 Sub- -- Bit. B 

~ f- 0.5 

f- 0.6 

1-- Cll 

::I 0.7 B 0 

c: 

1-- .E 

2 1- 0.8 

i:i'i 

0 IA > 

.c 

Ol 

:I I- 1.0 

Medium 1- 1.2 

Volatile IBituminous - 1.4 

Low 

1.6 

Volatile 

Bituminous - 1.8 

c-

- 2.0 

SemicAnthracite 1-

1-

Anthracite 1- 3.0 

f- 4.0 

Meta-A. 

Vol. M. Carbon 

d.a.f. d.a.f. 

% Vi trite 

1-

1--68 

1-

1---64 

I- ca. 60 

-60 

I-56 

1-

I-52 

1- 1- ca. 71 

I- 48 

f- 44 

I- ca. 77 

II- 40 

1-

1- 36 

1-

1- 32 

II- 28 1- ca. 87 

1- .. 

I- 24 

II- 20 

fI- 16 

1-

I- 12 

II- 8 I- ca. 91 

1-

- 4 

THE FUTURE OF ENERGY GASES 

Bed 

Moisture 

f- ca. 75 

r-ca. 35 

f- ca. 25 

r-ca. 8-10 

Cal. Value 

Kcai/Kg 

f- 4000 

f- 5500 

f- 7000 

1- 8650 

f- 8650 

explosions and gaseous outbursts associated with underground mining. Only recently has coal been recognized as a 

reservoir rock as well as a source rock and thus represents an 

enormous undeveloped "unconventional" energy resource. 

Some of the first attempts to produce gas from coal 

were undertaken in Europe in the late 19th century to reduce mining hazards (Bromilow and James, 1955). The 

date the first wells were drilled specifically for coalbed gas 

is uncertain; however, by the late 1970's some commercial 

production of coalbed gas had been established in the Black 

Warrior and San Juan basins in the United States (fig. 2). 

Significant exploration for and production of coalbed gas in 

the United States began in the mid-1980's because of a 

Federal tax credit given for the production of coalbed gas. 

Gas is commercially produced from coalbeds that range in 

thickness from 1 to 30 meters and occur at depths of 45 to 

2,730 meters. By the end of 1991, about 5,000 wells, located mainly in the Black Warrior (2,800) and San Juan basins 

(1,800), were producing about 28x106 m3 of coalbed gas 

per day. The tax credit not only increased drilling activity, 

but was also responsible for the development of new drilling and completion technology. The knowledge and technology gained from exploration and production in the 

United States is currently being transferred to other countries where there has been no significant coalbed gas production because of economic, logistical, political, and 

geological reasons. However, considerable exploration activity is currently taking place in Australia, Canada, China, 

the Czech Republic, the former Soviet Union, Poland, 

South Africa, Spain, and the United Kingdom. 

GENERATION OF COALBED GAS 

Generation of natural gas in coalbeds takes place by 

two distinct processes described as biogenic and thermogenic. Biogenic gas is composed primarily of methane and 

results from the decomposition of organic matter by microorganisms. The major requirements for the generation 

of significant amounts of biogenic gas by methanogenic 

microorganisms (assigned to the Archaea domain (Woese 

and others, 1990)) are (1) an anoxic environment, (2) low 

sulfate concentrations, (3) low temperatures, (4) abundant 

organic matter, (5) high pH values, and (6) adequate space 

~ Figure 1. Coal ranks, from lowest (peat) to highest (metaanthracite), and common properties of measurement. Modified 

from Stach and others (1982). D.a.f., dry and ash free; vol. m., 

volatile matter; ref!. R0 , vitrinite in percent; cal. value, caloric 

value; meta-A., meta-anthracite; sub-bit., subbituminous; vol., 

volatile. 
COALBED GAS-AN UNDEVELOPED RESOURCE 391 

500 Km 

POWDER RIVER 

850x1o9m3 

COAL FIELDS 

(Not quantified) 

RICHM:>ND& 

DEEP RIVER 

85x1o9m3 

CAHABA & COOSA 

COAL FIELDS 

85x109m3 

Figure 2. Map showing principal coal-bearing basins of the United States and estimates of inplace coalbed-gas resources. 

Coals .in basins of central and eastern United States are of Paleozoic age and those in western U.S. basins are of Cretaceous 

and Tertiary age. Modified from ICF Resources ( 1990). 

(Rice and Claypool, 1981; Rice, this volume). If these 

conditions are met, economically significant amounts of 

biogenic gas can be generated over a period of tens of 

thousands of years after burial. 

Biogenic gas can be generated during two different 

stages in coalbeds (Rice, in press). Biogenic gas can form 

early in the burial history of low rank coals (peat to subbituminous rank-vitrinite reflectance (R0 ) values less than 

0.5 percent). This biogenic gas is referred to as early 

stage, and its generation and accumulation are favored by 

rapid sedimentation. Biogenic gas can also be generated in 

coalbeds in recent time (tens of thousands to a few million 

years B.P.) where ground water flow has created a favorable environment for microbial activity. This type of biogenic gas is referred to as late stage, and its generation can 

take place in coalbeds of any rank provided that the requirements outlined previously have been met. 

As the degree of coalification increases owing to higher temperatures and pressures, coals become enriched in 

carbon as large amounts of volatile matter rich in hydrogen and oxygen are released primarily as methane and carbon dioxide (fig. 3), and water (Stach and others, 1982). 

Coal Rank 

20 Peat 

Lignite 

Sutr 

bituminous 70 

High· 

Volatile 

() Bituminous 0 

w 120 Medium· a: Volatile ::::> 

1- Bituminous <( 

a: Low- w Volatile a.. 170 Bituminous :::2: 

w Semi- 1- anthracite 

220 

I Anthracite 

\ 

\ 270 

0 50 100 150 200 

YIELD, liter/kg 

Figure 3. Calculated amounts of gases generated from coal during coalification. Modified from Hunt (1979). 
392 THE FUTURE OF ENERGY GASES 

This methane is thermogenic and its generation begins at a 

rank of high-volatile bituminous (R0 values greater than 

0.6 percent). The relative quantities of these main volatile 

products can be estimated using the major elemental composition of the coal (C-H-0) which will vary for the different types of kerogen (Juntgen and Karweil, 1966). Four 

types of kerogen (I-IV) are recognized using major elemental analysis plotted on a van Krevelen diagram (fig. 4). 

These four types of kerogen generally correlate with the 

major organic constituents (macerals) identified by petrography-liptinite (I-ll), vitrinite (III), and inertinite (IV). 

Liptinite-rich coals generally correspond to types I and II 

kerogen, vitrinite-rich coals to type III kerogen, and inertinite-rich coals to type IV kerogen. 

Major amounts of methane are generated from coals 

during the coalification process. The estimates vary from 

about 100 to 300 cm3 of gas per gram of coal depending 

on the elemental values used, starting rank, and assumptions made about the gas product composition (Juntgen 

and Karweil, 1966; Hunt, 1979; Levine, 1987). Under natural conditions, the actual yield is probably in the range of 

150 to 200 cm3/g. 

1.5 

0 

~ (.) 

~ 1.0 Jli ~ < 

~ I 

0.5 I 

I 

\ 

\ I \__.-/ 

I \ \ ,--/I 

\ I __.,---"'\/ \ 

\ ...\--.......... \ 

\ //\ I \ / I I 

OL-----L-----L---~L-----L-----L-----~ 

0 0.05 0.10 0.15 0.20 0.25 0.30 

0/C ATOMIC RATIO 

Figure 4. van Krevelen diagram showing types of kerogen and 

pathways for generation of methane and elimination of carbon 

dioxide and water during coalification. Liptinite corresponds to 

types I and II kerogen, vitrinite to type III, and inertinite to type 

IV. H/C, hydrogen/carbon; 0/C, oxygen carbon. Modified from 

Levine (1987). 

In addition to methane, some coals are capable of generating gas containing heavier hydrocarbons (wet gas) and 

oil. Generation of these heavier hydrocarbons takes place 

in coals having significant amounts of hydrogen-rich components, such as liptinite or certain components of the vitrinite maceral (such as humic gel) (Bertrand and others, 

1986; Saxby and Shibaoka, 1986; Khorasani, 1987; Stanton and others, 1992). 

CHARACTERISTICS OF COALBED GAS 

,Coalbed gases from which compositional data are determined are obtained from desorption tests of coal samples, underground mines and exploration boreholes, or 

production from coalbed reservoirs. Compositional data 

presented in this chapter are for gas samples collected from 

coalbeds and are not for gas samples from adjacent reservoirs that have been interpreted to be coal derived. Analyses of coalbed gas samples are available from Australia, 

Canada, China, Germany, Poland, and the United States. 

The associated coals range in age from Pennsylvanian (late 

Carboniferous) to Tertiary and in rank from lignite to anthracite (R0 values of 0.3 to 4.9 percent) (Rice, in press). 

The molecular and isotopic compositions of coalbed 

gases are highly variable (Rice, in press). Methane is usually the major component with other hydrocarbon gases and 

carbon dioxide occurring in lesser amounts. The hydrocarbon composition of the gases, which is expressed as gas 

wetness (C2+, where C2+=C2-C5/C1-C5), ranges from 0 to 

70.5 percent. The wettest gases are from coal samples that 

were desorbed and crushed. Carbon dioxide is the other 

major component of the coalbed gases and varies from less 

than 1 percent to 99 percent. Because of their variable molecular composition, gases from coalbeds should be referred to as coalbed gas and not as coalbed methane. 

Coalbed gases also vary in their isotopic composition; 

methane 613c values (613c (parts per thousand (permil)) = 

( 13CJ12c sample!13CI12C standard-1)xl000 relative to PDB 

standard) range from -80 to -16.8 permil and carbon dioxide 613C values range from -26.6 to+18.6 permil. 

The relation between coalbed gas composition (C2+ 

and methane 613C values) and the rank of associated coal 

(expressed as R0 ) is illustrated by coalbed gas samples 

from Canada and the United States (figs. 5 and 6) (Rice, in 

press). There is a tendency for all of the gases to be methane rich (about 95 percent or more CH4) at low and high 

ranks (fig. 6), and for some to be wet at intermediate rank 

(R0 values of about 0.6 to 0.8 percent, fig. 5); however, 

many samples are methane rich at intermediate ranks 

(fig. 6). Methane 613C values generally are isotopically 

lighter (as light as -60 permil) at lower ranks and isotopically heavier (-40 permil or heavier) at higher rank (fig. 6). 

However, gases from coal of a given rank display a wide 

range of methane 613C values and the values commonly 
COALBED GAS-AN UNDEVELOPED RESOURCE 393 

fall above (isotopically lighter) the regression lines shown 

on figure 6, which were determined for gases interpreted to 

have been generated from coal and dispersed organic matter. Similar patterns are exhibited by coalbed gases from 

other countries (Rice, in press). 

Although wetness and methane o13C values of coalbed 

gases are scattered when plotted against the rank of the 

associated coal, they illustrate a more systematic trend when 

plotted against present-day depth of burial (Rice, in press). 

Shallow coalbed gases are composed of isotopically light 

methane, as compared with deeper coalbed gases, regardless of rank. The methane-rich nature of shallow coalbed 

gases has been known for years from compositional data 

from underground mines. This knowledge resulted in the 

expression "coalbed methane." The depth-related change in 

the molecular and isotopic composition of coalbed gas can 

take place over a transition zone or can be abrupt. This 

change takes place at varying depths, but usually occurs 

within a kilometer of the surface. 

The reported coalbed gases are interpreted to be both 

biogenic and thermogenic on the basis of molecular and 

isotopic composition (Rice, in press). The primary controls 

on the composition of the gas are considered to be rank, 

0 

Muhiple samples 

0.5 

+ 

+ 

+ 

X XX XX 

+ + + ++.j:. 

~ !!._. 1.0 0 

a: 

+ 

+ 0 

1.5 

X 

2.0 -+"~---.-----r-------.-----, 

0 5 15 

EXPLANATION 

o Powder River basin. USA 

o Arkoma basin. USA 

Black Warrior basin, USA 

X Piceance basin,USA 

+ San Juan basin,USA 

• Deep basin, Alberta, Canada 

20 

Figure 5. Gas wetness (C2+) versus vitrinite reflectance (R0 ) for 

coalbed gases and coals, respectively, in Canada and the United 

States. (C2+=C2-C5/C1-C5.) From Rice (in press). 

composition, and the depth/temperature of the associated 

coal. Secondary controls are also reflected in the coalbed 

gas composition and they will be discussed later. 

Biogenic gas consists mainly of methane; the presence 

of significant amounts of heavier hydrocarbon gases with 

biogenic gas indicates mixing of late-stage biogenic methane in mature coals that have already generated heavier 

thermogenic hydrocarbons. Biogenic gas generation is restricted to shallow depths and to temperatures less than 

50°C, and can occur in coals of all ranks. Biogenic gas can 

generally be distinguished by its isotopic composition; 

methane o13C values are generally in the range of -55 to -90 

permil. 

-60 ~ 

X 0 

0 X 

0 

0 X 

X 

-50 

-o 

c 

() 

cry :j: 

'00 

lJ.J 

z 

<( 

I 

IlJ.J 

~ + + 

-40 X 

+ 

-30 

0.3 0.5 

D 

D 

EXPLANATION 

0 Powder River basin, USA 

D Arkoma basin, USA 

. Black Warrior basin,USA 

X Piceance basin,USA 

+ San Juan basin,USA 

• Deep basin, Alberta, Canada 

D 

~ D 

t ~ ++$:1- X 

• 

• 

1.0 1.5 

1. 

3. 

2. 

Ro(%) 

Fjgure 6. Methane o13C versus vitnmte reflectance (R0 ) for 

coalbed gases and coals, respectively, in Canada and the United 

States. Regression line 1 is for gases generated from types II/III 

kerogen, line 2 is for gas collected from coalbeds and coal 

pyrolysis gases in China, line 3 is for coal-derived gases in 

adjacent reservoirs in China, and stippled area is for coal-derived gas in adjacent reservoirs and coal-pyrolysis gases (from 

several authors). (<'i 13C (parts per thousand(permil))=( 13CI12c 

sample/13C/ 12C standard-l)xl,OOO relative to PDB standard.) 

From Rice (in press). 
394 THE FUTURE OF ENERGY GASES 

In comparison, thermogenic coalbed gases are characterized by (1) common presence of heavier hydrocarbons at 

intermediate ranks of high-volatile and medium-volatile 

bituminous coal (R0 >0.6 percent) and (2) enrichment of 

heavy isotope 13c in methane with increasing rank (methane b13C values are commonly more positive than -55 

permil). At intermediate ranks (high-volatile and mediumvolatile bituminous), sapropelic coals (liptinite and hydrogen-rich vitrinite) contain both wet gas and liquids, whereas 

humic coals (mostly vitrinite) contain a drier gas. The liquids generated in the sapropelic coals contain high pristane/ 

phytane ratios, a feature that is typical for coal-derived oil, 

and a slight predominance of odd-carbon numbered n-alkanes in the C25+ fraction (Clayton, in press). However, the 

saturated fraction of the liquids consists predominantly of 

low-molecular-weight components (C4-C10), a composition 

which results in the liquids having high API gravities (approximately 50° API). In addition, the coal-derived liquids 

are commonly characterized by flow only at high temperatures (high pour points) because they contain abundant 

long-chain n-alkanes derived from terrestrial plant waxes. 

At high ranks, coalbed gases are mostly methane generated 

from residual kerogen and cracking of previously formed 

heavier hydrocarbons. 

Thermogenic methane is isotopically more positive 

than biogenic methane because of the smaller kinetic isotope effects associated with thermal cracking (Chung and 

others, 1988; Clayton, 199l).In general, methane b13C values for thermogenic methane become isotopically heavier 

with increasing rank because residual gas-producing carbon 

becomes enriched in 13C owing to 12c- 12C bonds being 

broken more frequently by thermal processes than 12c- 13c 

bonds. Also, coal composition, in addition to rank, influences the isotopic composition of the coalbed gas, whereby 

gases generated from coals with oxygen-rich kerogen 

(mostly vitrinite) (1) have more positive methane b13C values than those generated from hydrogen-rich kerogen (liptinite and hydrogen-rich vitrinite) at similar levels of thermal 

maturity and (2) exhibit less spread in methane and ethane 

b13c values (James, 1990; Clayton, 1991). These differences result from isotopically lighter methane being produced 

by thermal cracking of aliphatic-type structures, which are 

prevalent in hydrogen-rich kerogen, whereas isotopically 

heavier methane results from cracking of aromatic structures, which are predominant in oxygen-rich kerogen. This 

effect of kerogen composition on isotopic composition is 

illustrated by regression lines shown on figure 6. 

Secondary processes also affect the composition of 

coalbed gases, particularly at shallow depths, such that 

isotopically light methane is dominant in shallow coalbed 

gases, regardless of rank (Rice, in press). The depth interval where these secondary processes are active and affect 

the composition of the gases is referred to as the zone of 

alteration. Unaltered gas generally occurs in the deeper 

parts of basins and is referred to as original gas. 

At shallow depths, coalbeds are commonly aquifers in 

which microorganisms can thrive. Microbial activity can 

affect the observed composition of coalbed gases in two 

ways. First, significant amounts of late-stage, isotopically 

light biogenic methane generated by anaerobic microorganisms can be mixed with previously generated thermogenic 

gas or fill degassed coalbeds (Rice, in press). Second, aerobic bacteria can preferentially destroy most of the wet-gas 

components, resulting in a methane-rich gas (James and 

Bums, 1984). 

The zone of alteration, in which mixing and oxidation 

affect the coalbed gas composition, can extend from 

depths of a hundred meters to a kilometer. The zone is 

usually restricted to the margins of basins; however, it can 

extend into and throughout a basin under certain conditions. The primary controls on the depth and lateral extent 

of the zone of alteration are the physical nature of the 

coalbeds, burial history, and hydrology. Thick, laterally 

continuous, permeable coalbeds are conducive to the development of ,an aquifer system. Uplift and erosion result 

in the depressurization of the coalbeds and subsequent degassing of the original gas. In addition, uplift and erosion 

result in reduced stress and increased permeability, thereby 

aiding both aquifer development and degassing. Finally, 

microorganisms become widely distributed in active aquifer systems, leading to widespread microbial activity, including aerobic oxidation and anaerobic methanogenesis. 

In addition to hydrocarbon gases, carbon dioxide is the 

other significant component of coalbed gases. As previously stated, major quantities of carbon dioxide are generated 

by thermal decarboxylation or devolatilization of coal, particularly prior to the main stage of thermogenic methane 

production (fig. 3). Carbon dioxide, however, is highly sol_. 

uble in water and very reactive and can have different origins (Hunt, 1979). As a consequence, the carbon dioxide 

presently in a coalbed gas may have an origin other than 

devolatilization. Furthermore, the concentration and isotopic composition (b13C) of carbon dioxide in coalbed gases 

is commonly different from those in gases of adjacent reservoirs, suggesting different origins. The wide range in 

concentrations and isotopic composition (b13C) of carbon 

dioxide suggest that significant amounts of carbon dioxide 

in coalbed gas are not commonly a product of the coalification process, but rather of other processes active in localized areas. Documented sources of large amounts . of 

carbon dioxide in coal bed gas are (I) thermal destruction 

of carbonates, (2) bacterial degradation of organic matter, 

(3) bacterial hydrocarbon oxidation, and (4) migration 

from magma chambers or deep crust (Rice, in press). 

GAS STORAGE 

One of the most important characteristics of coalbed 

gas reservoirs that set them apart from more conventional 
COALBED GAS-AN UNDEVELOPED RESOURCE 395 

gas reservoirs is the amount of gas and manner in which it 

is stored. In conventional reservoirs, such as sandstones or 

carbonates, gas occurs as either a free or dissolved phase. 

Although some free and dissolved gas may occur, as much 

as 98 percent of the gas present in coalbed reservoirs is 

sorbed (Gray, 1987). The free and dissolved gas in the 

coal occurs within the fractures (cleats) and pores, whereas the sorbed gas occurs as a monomolecular layer on the 

internal surfaces of coal (Selden, 1934; Kim, 1977). Because coal is a microporous solid with large internal surface areas (IO's to IOO's of m2

/g of coal), it has the ability 

to sorb very large amounts of gas and can hold much more 

gas than the same rock volume of a conventional reservoir. 

In addition, the microstructure of coal has been described 

as a molecular sieve or cage (van Krevelen, 1981) within 

which the methane molecule can be stored. 

In general, gas content increases with increasing rank, 

although there is a wide range of gas contents within each 

coal rank (fig. 7). Low-rank coals contain as much as 

2.5 cm3/g, whereas higher rank coals contain as much as 

31 cm3/g. The large increase in gas content between the 

ranks of subbituminous A and high-volatile C bituminous is 

mainly due to the larger amounts of methane generated by 

thermal processes associated with the coalification of highrank coals relative to the smaller volumes of methane only 

generated by microbial processes at lower ranks. At higher 

ranks (medium-volatile bituminous and higher), coals may 

have generated more methane than they can store, resulting 

in the possible expulsion of methane into adjacent reservoirs (Juntgen and Karweil, 1966; Meissner, 1984). 

Pressure and temperature also play an important role 

in the gas content of coal. For a given rank, sorbed gas 

content increases with increasing pressure and decreases 

with increasing temperature (Juntgen and Karweil, 1966). 

Because high pressures and temperatures are more commonly associated with high-rank coals than low-rank 

M,------------------------

s-An 

lv 

Mv 

~ Hv-A -t-------------------

0: Hv·B +---------------------------/ -' 

8 Hv-c ~--~===========- S.BA 7 s.c 

I 

10 15 20 25 30 35 

DESOABED GAS (cclgm) 

Figure 7. Cross plot showing range of gas content versus coal 

rank. Data from measurements of desorbed coalbed gas in the 

United States. An, anthracite; s-An, semianthracite; Lv, low-volatile bituminous; Mv, medium-volatile bituminous; Hv-A, Hv-B, 

and Hv-C, high-volatile bituminous A, B, and C; S-A, S-B, and 

S-C, subbituminous A, B, and C, L, lignite. 

coals, relatively high gas contents are generally expected 

in high-rank coals. In some cases, however, natural desorption of gas resulting from uplift and erosion in the 

subsurface environment may result in unexpected low gas 

contents, thereby accounting for some of the wide variations in gas content within a given coal rank (fig. 7). 

Regardless of rank, nearly all coals contain at least 

some water. For practical purposes, moisture content of 

coal is defined as the water present as H20 that is released 

at temperatures of 104° to ll0°C (American Society for 

Testing Materials, 1973). Water in coal occurs as free 

water, water of decomposition, and water of hydration. 

Free water occurs in fractures and macropores; water of 

decomposition is bound to oxygen-containing functional 

groups (-OH, -COOH, -C=O) by hydrogen bonding (Iyengar and Lahiri, 1957); and water of hydration is found 

in accessory minerals, such as gypsum and clay (Allardice 

and Evans, 1978). Some of this water competes with 

methane for sites of sorption. The amount of water sorbed 

in a coal is referred to as the critical moisture content and 

is dependent on the oxygen content of the coal (Joubert 

and others, 1973). Moisture contents above the critical 

moisture content do not affect the sorption of methane. 

Low-rank coals have _larger amounts of oxygen than highrank coals and therefore can sorb more water than highrank coals. 

The amount of inorganic material and the maceral 

composition of coal are additional factors affecting its gas 

sorption capacity. There is no affinity for gas to sorb onto 

the surfaces of inorganic matter. Inorganic matter occupies 

space that otherwise would be filled with organic matter, 

thereby reducing the surface area available for gas sorption (Gunther, 1965). As a consequence, coals with relatively high ash content will not contain as much gas as 

low-ash coals of equal rank. The gas storage capacity of 

hydrogen-rich, high-volatile bituminous coals is reduced 

because of the generation of high-molecular-weight hydrocarbons (Levine, 1991). These hydrocarbons have the effect of plugging the microporosity, thus reducing the 

storage capacity. The sorption capacity is increased again 

at higher ranks (low- volatile bituminous and higher), 

when these heavier hydrocarbons are thermally cracked. 

DETERMINATION OF GAS CONTENT 

The most common method of determining the volume 

of gas contained in coal is by direct measurement of core 

or drill-cutting samples retrieved from a well during drilling. The direct method measures three components--desorbed gas, residual gas, and lost gas. The desorbed gas 

component is measured by placing core or drill-cuttings 

samples in a sealed canister immediately after the samples 

arrive at the surface. Periodic measurements of the desorbed gas are recorded over a span of several weeks to 
396 THE FUTURE OF ENERGY GASES 

months until there is virtually no more gas desorbing from 

the coal. The coal is then removed from the canister, 

crushed to a very small size, and the amount of evolved or 

residual gas is measured. The lost gas component represents the amount of gas lost from the sample from the 

time the sample was penetrated by the drill bit to the time 

the sample was placed in a canister. It is calculated graphically by the linear extrapolation of the square root of time 

versus the cumulative volume of desorbed gas. The sum of 

the three components then constitutes the calculated 

amount of gas contained in the coal sample. In general, 

the measured values tend to be less than the actual gas 

contents as revealed by pressure cores (Yee and others, in 

press). Although there are several sources of potential 

error in measuring the gas content, particularly in calculating the lost gas amount, the results are usually representative of the relative volume of gas contained in a coal. 

Detailed procedures for measuring gas content are provided by Kissell and others (1973), Smith and Williams 

(1981), and Ulery and Hyman (1991). 

The amount of gas stored in a particular coal relative 

to reservoir pressure at a constant temperature is commonly determined from a sorption isotherm (fig. 8) (Mavor 

and others, 1990). The sorption isotherm is a measure of 

the maximum amount of gas that a coal can sorb. In many 

cases, however, coals are undersaturated with respect to 

gas, and the sorption isotherm, in conjunction with direct 

measurement of gas content, can be used to determine if a 

coal is fully saturated with gas. Common reasons for the 

undersaturation of gas are miscalculation of gas content, 

degassing of coalbeds resulting from uplift and erosion, 

and differential generation of coalbed hydrocarbons resulting from varying coal composition. 

25 .-----------------------------------------, 

20 Gas Content of Coal A ( 18.2 cdgm) 

/ 

1-

~15 z 

w 

1-

z 

0 

0 10 (f) 

<( 

(!J 

Gas Content of Coal 8 (1 5.0 cc/gm) 

~------------------ I 

I 

I 

I 

I 

I 

I 

I 

I 

I 

I Desorption Pressure 1 

of Coal 8 (7.0 MPa) : 

'-..I 

Coal A (Saturated) 

----------------~ 

Coal 8 ( Undersaturated) 

Initial Reservoir Pressure 

of Coals A & 8 (13.8 MPa) 

'-.. 

tO 

PRESSURE (MPa) 

15 

Figure 8. Idealized coalbed gas sorption isotherm showing relation between reservoir pressure and gas content for a saturated 

(A) and undersaturated (B) coal. Heavy solid line indicates the 

maximum amount of gas that can be stored at given reservoir 

pressure. Modified from McElhiney and others (in press). 

GAS PRODUCTION 

Economic quantities of gas can be produced from 

coalbed reservoirs. The diagrammatic sketch in figure 9 

shows the path that methane molecules and other gases 

must take in order to be produced. From the sites of gas 

sorption within the matrix, the gas must desorb and migrate 

by diffusion out of the matrix into the cleats where the gas 

then flows to the wellbore. The coalbed gas is held in the 

microstructure of the coal by pore pressure, and gas migration takes place when the pressure is reduced. Because 

most coals are characterized by high water saturations, depressurization results from dewatering of the coalbeds. The 

sorption isotherm, in conjunction with direct measurement 

of gas content, can provide information on the production 

potential of a coalbed reservoir. For example, coal A (fig. 8) 

contains 18.2 cm3 of gas per gram at a reservoir pressure of 

13.8 mega pascal (MPa). Because coal A is saturated with 

methane, gas will immediately begin desorbing from the 

matrix when the coal is penetrated by a drill bit and the 

pore pressure begins to drop. In contrast, coal B is undersaturated with methane (15.0 cm3

/g) and the methane will 

not desorb at the present reservoir pressure of 13.8 MPa. 

Significant gas desorption will only begin from coal B after 

reducing the reservoir pressure from 13.8 MPa to 7.0 MPa. 

The development of permeability is a critical aspect of 

gas production from coalbed reservoirs. The absolute permeability of coalbeds ranges from less than 0.1 millidarcy 

(md) to more than 100.0 md. Commonly, permeability in 

coal bed reservoirs is in the range of 1.0 to 10.0 md. For 

Figure 9. Diagram showing (A) desorption of methane from micropore in coal matrix, (B) diffusion path of methane through 

coal matrix, and (C) flow of methane in fractures (cleats). From 

Diamond (in press). 
COALBED GAS-AN UNDEVELOPED RESOURCE 397 

practical purposes, there is essentially no permeability within the coal matrix. Virtually all of the permeability in coal 

occurs within the fracture system, commonly referred to as 

the cleat system. Without a well-developed cleat system, 

commercial gas production from coalbeds is not possible. 

Cleats constitute a roughly orthogonal set of fractures referred to as face and butt cleats (fig. 10). Face cleats are the 

dominant, more extensive set and butt cleats are the subordinate set. Owing to the better development of face cleats, 

permeability in coalbeds commonly exhibits varying degrees of anisotropy, with the better permeability developed 

parallel to the face cleat direction (McCulloch and others, 

1974). The factors that affect the permeability of cleats include cleat frequency, connectivity, and aperture width. 

These factors are, in tum, affected by bed thickness, coal 

quality, rank, tectonic deformation, and stress (Macrae and 

Lawson, 1954; Ammosov and Eremin, 1963; Decker and 

others, 1991). The preservation of cleats is largely dependent 

on severity of structural deformation. Current coalbed gas 

production is from relatively structurally undeformed areas, 

where the cleat system is preserved. In areas of severe structural deformation, the cleat system is commonly obliterated 

(Law, in press). Thus, the economic production of gas in 

structurally complex regions may be severely hindered, even 

though the coals may contain large amounts of gas. 

One of the largest obstacles to the economic recovery 

of coalbed gas is water. The presence of water in coal inhibits desorption of gas from the coal matrix and flow to 

the wellbore, particularly in coals undersaturated with gas 

FACE CLEATS 

Figure 10. Diagram showing relation between face (dominant, 

more extensive) and butt (subordinate) cleats in coal and carbonaceous shale. Note that the frequency of cleats in carbonaceous 

shale is less than in coal. Modified from Jones and others (1984). 

(figs. 8, 9). Coalbeds are commonly dewatered by drilling 

several wells that then produce water by pumping to a 

point at which gas begins to desorb from the matrix. The 

period of time necessary to accomplish sufficient dewatering is highly variable (days to months) and in some cases 

is never reached. The success of dewatering efforts is dependent on the source of the water and the number of 

wells involved in the dewatering process. 

Sources of water in coal may include original water 

(inherent moisture), water of meteoric origin, and water 

from adjacent aquifers. First, nearly all coals contain some 

inherent moisture from the time that the original peat was 

deposited, moisture which decreases with increasing degree of coalification. Lignite commonly contains as much 

as 70 percent water, which decreases to less than 5 percent 

in medium-volatile bituminous and higher rank coals (van 

Krevelen, 1981). Second, in areas where coalbeds are relatively permeable and continuous and precipitation is abundant, atmospheric water may enter the coalbeds at the 

surface and travel great distances into the subsurface. Differences in elevation between the surface and· subsurface 

may cause abnormally high formation pressures (overpressured). This artesian overpressuring is developed in the 

northern part of the San Juan basin, which is characterized 

by high rates of both water and gas production from the 

coalbed reservoirs (Kaiser and others, 1991). Finally, communication may exist between a coalbed and adjacent aquifers because of natural or man-related causes. 

In areas where water is the pressuring phase, dewatering simultaneously reduces the reservoir pressure and the 

water content, thereby allowing gas to desorb from the 

coal. In areas where the coalbed reservoir is discontinuous 

and (or) has low permeability and the supply of water is 

limited, the probability of conducting successful dewatering programs is favorable. 

As a consequence of the gas storage characteristics of 

coal and the relation between water and gas production, 

coalbed gas wells exhibit a distinctive production history 

(fig. 11). In the early dewatering stage of production, large 

Stable 

',, , __ Water rates 

--------------------

TIME 

Figure 11. Generalized production history showing volumes of 

methane and water over time for a typical coalbed gas well. 

From Kruuskraa and Brandenberg (1989). 
398 THE FUTURE OF ENERGY GASES 

amounts of water are produced along with small amounts 

of gas until sufficient water is produced to allow for larger 

amounts of gas to desorb from the matrix and flow 

through the cleats to the wellbore. During the stable production stage, the quantities of gas increase as the quantities of water decrease. This coalbed gas production duririg 

the stable production stage is referred to as "negative decline" and distinguishes it from production from other 

types of reservoirs. Finally, in the declining stage of production, the amount of gas gradually declines and water 

production remains low. 

In nearly all cases, however, coalbed gas wells require 

special drilling or completion techniques to effectively 

connect the reservoir to the wellbore. Both vertical and 

horizontal wells have been utilized, although vertically 

drilled wells are far more common than horizontally 

drilled wells, except in some of the coal mining areas. The 

completion techniques range from hydraulic fracturing of 

wells with casing to open holes, some with enlarged cavities (Palmer and others, in press). Although open-hole cavity completions in the main production fairway of the San 

Juan basin have yielded the best results (as much as 

179x 103m3 of gas per day), the completion technique in 

each area must be tailored to the localized coalbed reservoir characteristics, such as rank, pressure, permeability, 

and gas content. 

ENVIRONMENTAL CONCERNS 

METHANE EMISSIONS FROM COAL MINING 

Methane is a strong infrared absorber and important 

greenhouse gas (Cole, this volume). According to recent 

estimates, atmospheric methane accounts for approximateHuman 

Activities Account 

for- 60% 

of 

Emissions 

l 

ly 15 percent of the "radiative forcing" added to the atmosphere during the past decade (Intergovernmental Panel 

on Climate Control, 1990). On an atomic basis, methane 

contributes 25 times more radiative forcing than carbon 

dioxide, and it contributes 70 times more radiative forcing 

than carbon dioxide on a weight basis (Intergovernmental 

Panel on Climate Control, 1990). On the other hand, methane has a short residence time in the atmosphere of 8 to 

12 years compared to more than 200 years for carbon dioxide. The short residence time of methane indicates that 

reductions in methane emissions will have noticeable 

short-term impacts on atmospheric concentrations of methane and that small reductions will be needed in the long 

term to stabilize atmospheric concentrations. 

Currently, the concentration of methane in the atmosphere is about I, 700 parts per billion (ppb) (Blake and 

Rowland, 1988). Evidence from analysis of gases trapped 

in ice cores indicates that atmospheric methane has more 

than doubled over the past 200-300 years from a preindustrial range of 600-700 ppb and has increased at a rate 

of about I percent per year over the past 15 years, or 

about 28 to 45 teragrams per year (I teragram (Tg)=52.6 

billion cubic feet at sea level) (Intergovernmental Panel on 

Climate Control, 1990). 

This increase in atmospheric methane is correlative 

with human population growth and human activities. The 

principal anthropogenic sources of methane are rice paddies, domestic livestock, landfills, biomass burning, venting of natural gas, losses of natural gas during transmission 

of gas and petroleum, and coal mining (fig. 12) (Intergovernmental Panel on Climate Control, 1990). These human 

activities account for about 60 percent of the total global 

emissions of methane, which are estimated to be in the 

range of 440 to 640 Tg per year. The methane reductions 

required to stabilize atmospheric concentrations of methI I I I I I 

0 25 50 75 100 

EMISSION ESTIMATE (Tg) 

Figure 12. Major sources of methane emissions in teragrams (Tg) per year. Oil and natural gas is 

from oil and natural gas venting and production; rice is from rice paddies, and natural systems is 

mostly from wetlands. (One teragram=52.6 billion cubic feet at sea level.) Bars indicate range of 

emission estimates for each source. From Kruger (1991). 
COALBED GAS-AN UNDEVELOPED RESOURCE 399 

ane by the year 2000 are on the order of 25 to 50 Tg per 

year (Intergovernmental Panel on Climate Control, 1990). 

These reductions are much lower than those required to 

stabilize other greenhouse gases, such as carbon dioxide 

and nitrous oxide. Coal mining probably accounts for 

about 1 0 percent of the total human-related emissions, and 

at least 10 percent of the coal-mining related emissions of 

methane can be economically recovered and utilized 

(Kruger, 1991 ). 

Pressure reduction during coal mining results from the 

removal of overburden and dewatering. This pressure reduction leads to the desorption of methane, dominant in 

coalbed gas at shallow depths, and to the possible release 

of methane to the atmosphere. In general, more methane is 

released from underground mines than surface mines because of the relation between methane storage, depth, and 

pressure. In underground mines, emission rates are variable depending on factors, such as the mining method 

(room and pillar versus Iongwall) and age of the mine 

(Deul and Kim, 1988). Methane emissions also continue 

during the transport, processing, and storage of coal. In 

1987, underground mining accounted for about 40 percent 

of the coal production in the United States and for about 

45 percent of world-wide coal production (Boyer and others, 1990). The methane released during underground mining is not only an environmental concern but also a 

serious safety hazard because methane is highly explosive 

at relatively low concentrations (5 to 15 percent in air). In 

the United States and some other countries, methane levels 

in the mines are kept at very low levels by installation of 

high-grade ventilation systems. 

Annual emissions of methane from coal mining have 

been estimated to be about 30 to 50 Tg (fig. 12) (Intergovernmental Panel on Climate Control, 1990). Currently, 

however, available data are insufficient to satisfactorily assess methane emissions from coal. Even though methane 

emissions from mining ventilation systems are measured 

in the United States, estimates of the total methane flux 

from coal mines include broad assumptions and contain a 

high degree of uncertainty. Estimates of methane emissions from coal mines in countries other than the United 

States contain greater uncertainty because even less data 

are available. In some cases, global estimates of methane 

flux from coal mines are solely based on data from U.S. 

mines that were extrapolated to a global scale (Boyer and 

others, 1990). 

On the basis of 1987 coal production data and using 

U.S. mines as an analog, Boyer and others (1990) estimated annual methane emissions from coal mines worldwide 

to be in the range of 33 to 64 Tg. More than 90 percent of 

the total emissions are from the I 0 primary coal producing 

countries shown in table I. About 79 percent of the total 

estimated methane emissions from coal mining are from 

four countries-China, the former Soviet Union, the United States, and Poland; China, by itself, accounts for about 

Table 1. Estimated methane emissions in teragrams (Tg) from 

major coal-producing countries. 

[One teragram=52.6 billion cubic feet at sea level. From Boyer and others, 1990] 

Primary coal producing countries Estimated annual methane emissions 

(Tg) 

China----------------------------------------· 16.1 

Fonner U.S.S.R.--------------------------- 8.3 

United States-------------------------------· 7.0 

Po land---------------------------------------· 3.4 

Germany------------------------------------ 2.1 

South Africa--------------------------------· 2.1 

India-----------------------------------------· I. 7 

United Kingdom---------------------------· 1.6 

Australia------------------------------------· 1.1 

Czech Republic---------------------------- 0.6 

Total-------------------------------------------4'4".0,.-----

36 percent of the world's annual emissions (table 1) (Boyer 

and others, 1990). Because of increasing energy demand, 

particularly in the developing countries and as the world's 

population increases, coal production is forecast to increase 

substantially over the next decade, and coal mining could 

become an even greater source of atmospheric methane. 

Coalbed gas can be recovered before, during, or after 

mining and the quality and quantity of the recovered methane will depend on the method used. Ventilation is the primary method of controlling methane levels in most mines, 

and fresh air is typically circulated across the actively 

mined coal face (Boyer and others, 1990). Sometimes, 

methane emissions can be controlled using ventilation 

alone, but this method commonly has to be supplemented. 

Other recovery methods include vertical wells, gob wells 

(removes gas released from rocks above and below the 

coalbed during and after mining), and horizontal and crossmeasure boreholes (Boyer and others, 1990). Because large 

amounts of air are mixed with methane during ventilation, 

the recovered-gas mixture is useful only for combustion air 

in a gas turbine or coal-fired boiler. Typical uses for gases 

recovered by wells and boreholes, gases which generally 

have higher percentages of methane, are pipeline injection 

and power generation. 

An excellent example of the economic recovery of 

methane from coal mining operations, resulting in reduced 

methane emissions, comes from the Black Warrior basin 

of southeastern Alabama (fig. 2) (Mills and Stevenson, 

1991). A coal mining company that has captured miningrelated methane operates gaseous mines at depths of 396 

to 640 m; the methane content of the coalbeds ranges from 

15.6 to 18.7 cm3

/g and presents a hazard to miners. Initially, the methane was vented to the surface. Later, methane 

was successfully recovered and sold, improving both mine 

safety and productivity. Recovery of methane averages 

about 1 x 106 m3 per day, a volume which represents about 
400 THE FUTURE OF ENERGY GASES 

35 percent of the methane released during the mining 

process. In this mine, about 83 percent of the recovered 

gas is from gob wells; the remaining 17 percent is from 

hydraulically stimulated vertical weJls and horizontal 

drainage wells, which recover methane before mining. 

Methane release related to coal mining can also cause 

safety hazards in nearby areas as documented in Powder 

River basin, Wyoming (fig. 2) (Law and others, 1991). On 

the east flank of the Powder River basin, thick, subbituminous Tertiary coalbeds are surface mined from some of the 

most economically important deposits in the United States. 

Owing to dewatering operations, the ground water levels 

have fallen as much as 24 meters in wells near the active 

mines and up to 3 meters as much as 5 kilometers away 

from the mines (Martin and others, 1988). This lowering of 

the ground-water level has resulted in desorption of the gas 

from the coal matrix in the area surrounding the surface 

coal mines. The desorbed gas has migrated within the coal 

to a laterally continuous anticline near the mine to form a 

commercial coalbed gas accumulation with only minor 

amounts of water. In addition, stress fractures and faults on 

the anticline have formed conduits for the gas to migrate 

out of the coalbeds and upward to the surface and into 

basements of nearby houses, causing an explosion danger. 

WATER DISPOSAL 

Water, commonly in large quantities, is produced from 

coalbed gas wells, especially during the early stages of gas 

production (fig. 11 ). The disposal of this produced water 

can not only affect the economics of the development of 

the coalbed gas, but also pose serious environmental concerns. In the United States, water disposal is controlled by 

Federal, State, and (or) local agencies. The disposal of 

produced waters will also be an environmental and economic concern in other countries as they develop their 

coalbed gas resources. 

The most economic methods of water disposal from 

coalbed gas reservoirs are discharge into streams, direct 

use for agricultural, wildlife, or industrial purposes, and 

evaporation. In addition, produced coalbed waters can be 

directly used in oil and gas fields as hydraulic fracture fluids and for enhanced oil recovery projects. More costly 

alternatives of disposal are underground injection and surface discharge after treatment, such as distillation, dilution, 

ion-exchange, reverse osmosis, and electrodialysis. The 

specific method of disposal will depend on the quality and 

quantity of the water. Problems and methods of water disposal are discussed by Zimpler and others (1988) and Burkett and others ( 1991 ). 

The quantity and quality of water vary considerably in 

coal-bearing basins and reflect the water's residence time 

and rock-water interactions in the subsurface and groundwater flow patterns. Total dissolved solids (TDS) in produced coalbed water range from less than 200 mg/L to 

more than 90,000 mg/L with most values being less than 

30,000 mg/L (Kaiser and others, 1991; Pashin, 1991 ). TDS 

and salinity tend to increase with the water's residence 

time in the subsurface and with increased time for rockwater interactions. As a consequence, TDS and salinity are 

generaJly higher in the central, deeper parts of basins as 

compared to the shallower parts of basins that are near 

recharge areas of relatively fresh meteoric water. Typically, 

produced water is neutral to slightly alkaline with pH values ranging from 7.0 to 8.5 and contains the carbonate, 

bicarbonate, chloride, sulfate anions, and sodium, potassium, calcium, and magnesium cations in variable amounts. 

If enough chemical data are available, maps of chlorinity 

and different water types can be used to map ground-water 

flow patterns (Kaiser and others, I 991; Pashin, 1991 ). For 

example, concentrations of chloride, which is unaffected 

by rock-water interactions, indicate directions of groundwater flow because low chloride waters occur in recharge 

areas of relatively fresh water circulation. 

Production rates of water can be as high as 950 m3 per 

day. However, most commercial coalbed gas wells produce 

less than 40 m3 per day after the initial dewatering phase. 

By water-well standards, most coalbed gas wells are lowyield wells. Higher rates of production are generally near 

areas of recharge where the waters are relatively fresh (low 

TDS); low rates of water production are in deeper parts of 

basins and (or) areas of low permeability where the water is 

commonly very saline. Although the volume of water from 

an individual coalbed gas well is generaJly low as compared 

to a water well, the cumulative volume of produced water 

can be enormous when a large number of weiis are drilled. 

For example, about 15x106 m3 of water was produced from 

more than 2,800 wells in the southeastern part of the Black 

Warrior basin in 1991 (fig. 2). Because of the humid climate, most of this water was discharged into streams without noticeable environmental consequences. In comparison, 

about 6xl06 m3 of water was produced by more than 1,700 

wells in the San Juan basin during the same time period. 

Because of the quality and quantity of the water and the dry 

climate of this region, most of this water was disposed of in 

underground injection wells (a more expensive method); the 

cost was offset by the higher production rates from individual gas wells in the San Juan basin relative to the rates from 

wells in the Black Warrior basin. 

RESOURCE POTENTIAL 

Worldwide resources of coal are estimated to be as 

much as 25 trillion metric tons (Kuuskraa and others, 

I 992). Most of these resources (about 90 percent) are concentrated in four countries-Canada, China, Russia, and 

the United States (fig. 13; table 2). However, the remaining 

resources are widely distributed. In many countries, such 
IIIII' 1211" 

.(};,~ 'l 

1411" 1611" lXII" 1611" 140" 

Cl 

~, 

/ Coal area of known or 

inferred geologic extent 

120" 100"90" 70" 

• One or more reported coal occurrences 

of small or unknown extent 

50" 30" 10" 0" Ill" .10" 

~ 

~~ 

0 

II 

511' 711" 911" 

------[7-

.1000 KM 

·l 

•(r 

~·· J 

Figure 13. Map showing global coal distribution. From E.R. Landis and J.N. Weaver, U.S. Geological Survey (written commun., 1992). 

II" Equator 

Ill' 

""' 0 

-
402 THE FUTURE OF ENERGY GASES 

Table 2. Major coal and coalbed gas resources (estimated) by 

country. 

[One trillion cubic meters=28.32 trillion cubic feet. From Kuuskraa and others, 

1992] 

Country 

Coal resources Coa1bed gas resources 

(billion metric tons) (trillion cubic meters) 

Russia------------------------· 6,500 

China-------------------------· 4,000 

United States ---------------· 3,950 

Canada-----------------------· 7,000 

Australia---------------------· I, 700 

Germany---------------------· 326 

United Kingdom-----------· 190 

Kazakhstan------------------· 170 

Poland -----------------------· 160 

India--------------------------· 160 

Southern Africa 1 -----------· ISO 

17-113 

30-35 

II 

6-76 

8-14 

3 

2 

3 

Ukraine ----------------------· 140 2 

Total------------------------------,.-24',4.,..,4"'6-----,.,85=---,.2"'62.-----

1

Includes Botswana, South Africa, and Zimbabwe. 

as the Czech Republic, Poland, and the Ukraine, coal is the 

only available abundant source of energy (Kelafant and 

others, 1992; Kuuskraa and others, 1992; Landis, in press). 

Major resources of coalbed gas are associated with the 

immense amounts of coaL Worldwide estimates of coalbed 

gas are estimated to range from 85 to 262 trillion cubic 

meters (table 2) (1 trillion cubic meters of gas=28.32 trillion cubic feet); the range of values indicates the scarcity 

of basic coal data in many coal-bearing areas of the world 

(Kuuskraa and others, 1992). Although the resource is 

widely distributed, most coal is concentrated in 12 countries, where coal is commonly a major source of energy 

(Kuuskraa and others, 1992). The major U.S. coal-bearing 

basins are estimated to have coalbed gas resources of 

about 11 trillion cubic meters (fig. 2) of which 3 trillion 

cubic meters is expected to be recoverable (Rightmire and 

others, 1984; ICF Resources, 1990). These coal-bearing 

areas are in cratonic and foreland basins without major 

structural deformation. The largest part of these resources 

is in Rocky Mountain basins, where the coalbeds are of 

Cretaceous and Tertiary age; lesser amounts are in the 

eastern and central United States, where the coalbeds are 

of Paleozoic age. 

CONCLUSIONS 

Large amounts of methane-rich gas are generated and 

stored in coalbeds. Recently, commercial production of 

coalbed gas has been established in the United States, and 

development will be expanded in other countries as they 

become aware of the resource potential and as technology 

is transferred. Coalbed gas can be utilized as an energy 

source that (I) is environmentally more acceptable than the 

mining and combustion of coal, (2) can partly replace coal 

as a fossil energy source, and (3) sometimes occurs where 

other conventional resources of oil and gas are not present. 

REFERENCES CITED 

Allardice, D.J., and Evans, D.G., 1978, Moisture in coal, in Karr, 

C., Jr., ed., Analytical methods for coal and coal products: 

New York, Academic Press, v. 1, p. 247-261. 

American Society for Testing Materials, 1973, Moisture in the 

analysis sample of coal and coke: ASTM Standards, Part 26, 

03173-73, p. 381-383. 

Ammosov, 1.1., and Eremin, I.V., 1963, Fracturing in coal: Moscow, IZDAT Publishers, 109 p. [Translated from Russian by 

Israel Program for Scientific Translations, Jerusalem.] 

Bertrand, P., Behar, F., and Durand, B., 1986, Composition of 

potential oil from humic coals in relation to their petrographic nature: Organic Geochemistry, v. 1-3, p. 601-608. 

Blake, D.R., and Rowland, F.S., 1988, Continuing worldwide increase in tropospheric methane: Science, v. 259, p. 1129-

1131. 

Boyer, C.M., II, Kelafant, J.R., Kuuskraa, V.A., Manger, K.C., 

and Kruger, D., 1990, Methane emissions from coal mining: 

issues and opportunities for reduction: U.S. Environmental 

Protection Agency, Air and Radiation (ANR-445), EPN400/ 

9-90/008, 86 p. 

Bromilow, J.G., and James, J.M., 1955, Drainage and utilization 

of firedamp: Colliery Engineering, v. 32, p. 222-232. 

Burkett, W.C., McDaniel, R., and Hall, W.R., 1991, The evaluation and implementation of a comprehensive production 

water management plan: Coalbed Methane Symposium, 

1991 [Proceedings], p. 43-56. 

Chung, H.M., Gormly, J.R., and Squires, R.M., 1988, Origin of 

gaseous hydrocarbons in subsurface environments: theoretical considerations of carbon isotope distribution: Chemical 

Geology, v. 71, p. 97-103. 

Clayton, C., 1991, Carbon isotope fractionation during natural 

gas generation from kerogen: Marine and Petroleum Geology, v. 8,p. 232-240. 

Clayton, J.L., in press, Composition of crude oils generated and 

expelled from coal and coaly organic matter dispersed in 

shales, in Law, B.E., and Rice, D.O., eds., Hydrocarbons 

from coal: American Association of Petroleum Geologists 

Studies in Geology. 

Decker, A.D., White, J., and Reeves, S.R., 1991, Coalbed methane exploration strategies successfully applied in the Bowen 

basin, Queensland, Australia: Coalbed Methane Symposium, 

1991 [Proceedings], p. 307-315. 

Deul, M., and Kim, A.G., 1988, Methane control researchSummary of results, 1964-1980: U.S. Bureau of Mines, Bulletin 687, 174 p. 

Diamond, W.P., in press, Methane control for underground coal 

mines, in Law, B.E., and Rice, D.O., eds., Hydrocarbons 

from coal: American Association of Petroleum Geologists 

Studies in Geology. 

Gray, 1., 1987, Reservoir engineering in coal seams: Society of 

Petroleum Engineers Preprint SPE Paper 12514, Gunther, J., 
COALBED GAS-AN UNDEVELOPED RESOURCE 403 

1965, Etude de Ia liaison gaz-charbon: Revue de l'lndustrie 

Minerale, v. 47, p. 693-708. 

Hunt, J.M., 1979, Petroleum geochemistry and geology: San 

Francisco, W.H. Freeman and Company, 617 p. 

ICF Resources, 1990, The United States coalbed methane resource: Quarterly Review of Methane from Coal Seams 

Technology, v. 7, no. 3, p. 10-28. 

Intergovernmental Panel on Climate Control, 1990, Methane 

emissions and opportunities for control: U.S. Environmental 

Protection Agency, Air and Radiation (ANR-445), EPN400/ 

9-90/007, 64 p. 

Ivenyar, M.S., and Lahiri, A., 1957, The nature of reactant 

groups in coal: Fuel, v. 36, p. 286-297. 

James, A. T., 1990, Correlation of reservoired gases using the carbon isotopic compositions of wet gas components: American 

Association of Petroleum Geologists Bulletin, v. 74, p. 1441-

1458. 

James, A.T., and Burns, B.J., 1984, Microbial alteration of subsurface natural gas accumulations: American Association of 

Petroleum Geologists Bulletin, v. 68, p. 957-960. 

Jones, A.H., Ahmed, U., Bush, D., Holland, M., Kelkar, S., 

Rakop, K., Bowman, K.C., and Bell, G.J., 1984, Methane 

production characteristics for a deeply buried coalbed reservoir in the San Juan basin: Quarterly Review of Methane 

from Coal Seams Technology, v. 2, p. 19-33. 

Joubert, J.I., Grein, C.T., and Bienstock, D., 1973, Sorption of 

methane in moist coal: Fuel, v. 52, p. 181-185. 

Juntgen, H., and Karweil, J., 1966, Gasbildung und Gasspeicherung in Steinkohlenftozen, Part I and II: Erdol Kahle, 

Erdgas, Petrochem, v. 19, p. 251-258, 339-344. 

Kaiser, W.R., Swartz, T.E., and Hawkins, G.J., 1991, Hydrology 

of the Fruitland Formation, San Juan basin, in Geologic and 

hydrologic controls on the occurrence and producibility of 

coalbed methane, Fruitland Formation, San Juan Basin: Gas 

Research Institute Topical Report; August 1987-July I 990, 

GRI-9110072, p. 195-241. 

Kelafant, J.R., Stevens, S.H., and Boyer, C.M., II, 1992, Vast resource potential exists in many countries: Oil and Gas Journal, v. 90, no. 44, p. 80-85. 

Khorasani, G.K., 1987, Oil-prone coals in the Walloon Coal 

Measures, Surat Basin, Australia, in Scott, A.C., ed., Coal 

and coal-bearing sequences-recent advances: Geological 

Society Special Publication 32, p. 303-310. 

Kim, A.G., 1977, Estimating methane content of bituminous coal 

from adsorption data: U.S. Bureau of Mines Report of Investigations 8245, 22 p. 

Kissell, F.N., McCulloch, C.M., and Elder, C.H., 1973, The direct method of determining methane content of coalbeds for 

ventilation design: U.S. Bureau of Mines Report of Investigations 7767, 17 p. 

Kruger, D.W., 1991, Coalbed methane: environmental protection 

at a profit: Coalbed Methane Symposium, 1991 [Proceedings], p. 193-202. 

Kuuskraa, V.A., Boyer, C.M., II, and Kelafant, J.A., 1992, Hunt 

for quality basins goes abroad: Oil and Gas Journal, v. 90, 

no. 40, p. 49-54. 

Kuuskraa, V.A., and Brandenberg, C.F., 1989, Coalbed methane 

sparks a new energy industry: Oil and Gas Journal, v. 87, 

no. 41, p. 49-56. 

Landis, E.R., in press, Global coal occurrence, in Law, B.E., and 

Rice, D.O., eds., Hydrocarbons from coal: American Association of Petroleum Geologists Studies in Geology. 

Law, B.E., in press, The relationship between coal rank and cleat 

spacing: implications for the prediction of permeability in 

coal: International Coalbed Methane Symposium, 1993 [Proceedings]. 

Law, B.E., Rice, D.D., and Flores, R.M., 1991, Coalbed gas accumulations in the Paleocene Fort Union Formation, Powder 

River basin, Wyoming, in Schwochow, S.D., Murray, D.K., 

and Fahy, M.F., eds., Coalbed methane of western North 

America: Denver, Rocky Mountain Association of Geologists, p. 179-190. 

Levine, J.R., 1987, Influence of coal composition on the generation and retention of coalbed natural gas: Coalbed Methane 

Symposium, 1987 [Proceedings], p. 15-18. 

---1991, The impact of oil formed during coalification on 

generation and storage of natural gas in coalbed reservoir 

systems: Coalbed Methane Symposium, 1991 [Proceedings], 

p. 307-315. 

Macrae, J.C., and Lawson, W., 1954, Cleats in coal seams: Transactions of Leeds Geological Association, v. VI, p. 227-242. 

Martin, L.J., Naftz, D.L., Lowham, H.W., and Ranki, J.G., 1988, 

Cumulative potential hydrologic impacts of surface coal 

mining in the eastern Powder River structural basin, northeastern Wyoming: U.S. Geological Survey Water-Resources 

Investigations Report 88-4046, 201 p. 

Mavor, M.J., Owen, L.B., and Pratt, T.J., 1990, Measurement and 

evaluation of coal sorption isotherm data: Society of Petroleum Engineers Preprints SPE Paper 20728. 

McCulloch, C.M., Deul, M., and Jeran, P.W., 1974, Cleat in bituminous coal: U.S. Bureau of Mines Report of Investigations 

7910, 15 p. 

McElhiney, J.E., Paul, G.W., Young, G.B.C., and McCartney, 

J.A., in press, Reservoir engineering aspects of coalbed 

methane, in Law, B.E., and Rice, D.D., eds., Hydrocarbons 

from coal: American Association of Petroleum Geologists 

Studies in Geology. 

Meissner, F.F., I 984, Cretaceous and lower Tertiary coals as 

sources for gas accumulations in the Rocky Mountain area, 

in Woodward, J.W., Meissner, F.F., and Clayton, J.L., eds., 

Hydrocarbon source rocks of the Greater Rocky Mountain 

region, Rocky Mountain Association of Geologists, p. 401-

431. 

Mills, R.A., and Stevenson, J.W., 1991, History of methane 

drainage at Jim Walter Resources, Inc.: Coalbed Methane 

Symposium, 1991 [Proceedings], p. 143-151. 

Palmer, I.D., Lambert, S.W., and Spitler, J.L., in press, Coalbed methane well completions and stimulations, in Law, 

B.E., and Rice, D.D., eds., Hydrocarbons from coal: American Association of Petroleum Geologists Studies in 

Geology. 

Pashin, J.C., 1991, Regional analysis of the Black Creek-Cobb 

coalbed-methane target interval, Black Warrior basin, Alabama: Geological Survey of Alabama Bulletin 145, 127 p. 

Rice, D.D., in press, Composition and origins of coalbed gas, in 

Law, B.E., and Rice, D.O., eds., Hydrocarbons from coal: 

American Association of Petroleum Geologists Studies in 

Geology. 
404 THE FUTURE OF ENERGY GASES 

Rice, D.O., and Claypool, G.E., 1981, Generation, accumulation, 

and resource potential of biogenic gas: American Association of Petroleum Geologists Bulletin, v. 65, p. 525. 

Rice, D.D., Clayton, J.L., Flores, R.M., Law, B.E., and Stanton, 

R. W., 1992, Some geologic controls of coal bed gas generation, accumulation, and production, western United States: 

U. S. Geological Survey Circular 1074, p. 64. 

Rightmire, C.T., Eddy, G.E., and Kirr, J.N., eds., 1984, Coalbed 

methane resources of the United States: American Association 

of Petroleum Geologists Studies in Geology No. 17, 378 p. 

Saxby, J.D., and Shibaoka, M.,l986, Coal and coal macerals as 

source rocks for oil and gas: Applied Geochemistry, v. 1, 

p. 25-36. 

Selden, R.F., 1934, The occurrence of gases in coal: U. S. Bureau of Mines Report of Investigations 3233. 

Smith, D.M., and Williams, F.L., 1981, A new method for determining the methane content of coal: 16th Intersociety Energy Conversion Engineering Conference [Proceedings], 

p. 1276--1272. 

Stach, E., Mackowsky, M. Th., Teichmuller, M., Taylor, G.H., 

Chandra, D., and Teichmuller, R., 1982, Stach's Textbook of 

Coal Petrology (3d ed.): Berlin, Gebruder Borntraeger, 535 p. 

Stanton, R.W., Rice, D.D., Clayton, J.L, and Flores, R.M., 1992, 

Matrix-gel vitrinite types and Rock-Eva! analysis of coal 

samples, Cretaceous age, from the San Juan and Piceance 

basin: Ninth Annual Meeting of the Society for Organic Petrography, Abstracts and Agenda, p. 57-58. 

Ulery, J.P., and Hyman, D.M., 1991, The modified direct method 

of gas content determination; applications and results: 

Coalbed Methane Symposium, 1991 [Proceedings]. p. 489-

500. 

van Krevelen, D.W., 1981, Coal (typlogy, chemistry, physics, and 

constitution): Amsterdam, Elsevier, 514 p. 

Woese, C.R., Kandler, 0., and Wheelis, M.L., 1990, Towards a 

natural system of organisms; proposal for the domains Archaea, Bacteria, and Eucarya: Proceedings of the National 

Academy of Science, v. 87, p. 4576-4579. 

Yee, D., Seidle, J.P., and Hanson, W.B., in press, Gas sorption on coal and measurement of gas content, in Law, 

B.E., and Rice, D.D., eds., Hydrocarbons from coal: American Association of Petroleum Geologists Studies in 

Geology. 

Zimpler, G.L., Harmon, E.J., and Boyce, B.C., 1988, Disposal of 

production waters from oil and gas wells in the northern San 

Juan basin, Colorado, in Fassett, J.E., ed., Geology and coalbed methane resources of the northern San Juan Basin, Colo-

.rado and New Mexico: Denver, Rocky Mountain Association 

of Geologists, p. 183-198. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Coal as a Source Rock of Petroleum and GasA Comparison Between Natural and Artificial Maturation 

of the Almond Formation Coals, 

Greater Green River Basin in Wyoming 

By Mario Garcia-Gonzalez1

, Donald B. MacGowan1, and Ronald C. Surdam1 

CONTENTS 

Abstract . ... .. . .. .. . ... .. .. .. . . . ... .. .. ... .. ..... .. .. . . ...... .. .. . .. .. . ... .. . . . .. 405 

Introduction ................................................................... 405 

Naturally Matured Samples .......................................... 406 

Sampling .. ..... .. ..... .. .. . . . ... .. .. . ... .. .. .... .. .. . ... ... . ..... ... . . .. 406 

Organic Petrography .............................................. 406 

Maceral Analysis of Almond Coals ................ 406 

Textural Variations of Almond Coals with 

Depth of Burial ............................................... 409 

Organic Geochemistry ... .. . . ... . .. .. . .. . .. . . . ... . . . . .. . . .. .. . ... 413 

Artificially Matured Samples ....................................... 418 

Organic Petrography .............................................. 419 

Maceral Analysis ............................................. 419 

Textural Description of Almond Coals After 

Hydrous Pyrolysis ........................................... 419 

Organic Geochemistry ........................................... 423 

Geochemical Modeling ................................................ 427 

Burial History ........................................................ 427 

Time-Temperature Profiles .................................... 428 

Geochemical Modeling Results ............................. 429 

Volume of Hydrocarbons Generated ............................ 431 

Su!llmary and Conclusions ........................................... 432 

Acknowledgments ........................................................ 434 

References Cited ........................................................... 435 

Appendix ....................................................................... 437 

1

Department of Geology and Geophysics, University of Wyoming, 

Laramie, Wyoming 82071. 

ABSTRACT 

Organic petrological and geochemical studies demonstrate that the Almond Formation coals contain great unrecognized volumes of stored gas and oil. Oil is generated 

during maturation of hydrogen-rich vitrinite (desmocollinite) and liptinite macerals into exsudatinite (waxy oil) and 

inertinite solid residue. The waxy oil is initially stored in 

pores and vesicles. As the coal thermally matures, stored 

hydrocarbons are expelled from the pores and vesicles. This 

phase change causes a significant volume increase, which 

may overcome the storage capacity of these coals, fracturing them and allowing primary migration of hydrocarbons. 

Kinetic modeling, based on hydrous pyrolysis experiments, indicates that at the basin center, most oil generated 

and expelled from Almond coals has been thermally 

cracked to gas, whereas at the basin flank the oil-to-gas 

reaction is unimportant. During hydrous pyrolysis these 

coals expel up to 0.17 barrels of oil and 404 cubic feet of 

gas per ton of coal, indicating excellent generative capacity. 

Calculations of the volume of Upper Cretaceous coals 

in the Greater Green River Basin at vitrinite reftectances 

between 0.9 and I. 7 percent indicate that these coals may 

have generated 24 billion barrels of oil and 66 trillion cubic 

feet of gas. 

INTRODUCTION 

The Greater Green River Basin (GGRB) contains one 

of the most important gas resources in the United States 

(Tyler and others, 1992). The Late Cretaceous Mesaverde 

405 
406 THE FUTURE OF ENERGY GASES 

Group is both the main source of hydrocarbons and the 

main reservoir in the GGRB. The Almond Formation is one 

of the most important reservoir sandstones in the Mesaverde Group, having yielded 100 million barrels of oil 

(MMbo) and 850 billion cubic feet (Bcf) of gas prior to 

1991, (Wyoming Oil and Gas Conservation Commission, 

1991 ). The Almond is stratigraphically situated in the upper 

part of the Mesaverde Group in the GGRB. For a complete 

review of the depositional environment of the Mesaverde 

Group during the Late Cretaceous, see Roehler (1988, 

1990). 

Law (1984) discussed the widespread occurrence of 

overpressured gas reservoirs in relation to the maturation of 

the source rocks in the GGRB and predicted the occurrence 

of overpressured gas accumulations on the basis of vitrinite 

reflectance measurements. This paper initially addresses the 

same problem with a different methodology, which includes organic petrology and geochemical analyses of naturally and artificially matured coal samples. With this 

methodology we are able to illustrate the maturation pathway of Almond coals-the early generation of oil, then 

thermal degradation of the oil to gas, and later the generation of gas from coal (kerogen type III). Definitions of coal 

petrology terms are contained in the appendix. 

The results of this research indicate that Almond coals 

are important source rocks for both oil and gas. Our new 

interpretation of the origin of the gas indicates a new set of 

ideas about the origin of, and exploration targets for, hydrocarbon accumulations in the GGRB based on the great potential of Almond coals for generating oil and gas. 

This paper will focus on the source rocks (coals, coaly 

shales, and shales) adjacent to Almond sandstones. We report petrologic and geochemical characteristics of the coals 

and shales of the Almond Formation from the most immature stage in the basin, in the outcrops around the Rocks 

Springs Uplift, to the deepest level of burial, in the center 

of the Washakie Basin at approximately 18,000 ft present 

burial depth. 

Petrologic studies were performed with reflection microscopy using white and blue light (546 nm wavelength) 

on polished sections of coals and shales. Sample preparation follows the procedure described in American Society 

of Testing Materials Standard D-2797-72 (American Society of Testing Materials, 1980). The petrologic descriptions 

include maceral identification and point counting, vitrinite 

reflectance measurements, and textural descriptions. 

Geochemical analyses carried out on Almond shales 

and coals include (1) anhydrous pyrolysis for maximum 

temperature of hydrocarbon generation (T max), production 

index (PI), genetic potential (GP), and hydrogen index 

(HI); (2) total organic carbon (TOC); and (3) nuclear magnetic resonance (NMR) for structural information on the 

kerogen. 

The hydrous pyrolysis (HP) experiments were conducted on a set of Almond coal samples following the procedure of Lewan (1985) and described by Yin and others 

(in press). Each experiment was carried out isothermally 

for 72 hours for each 10° increment over the temperature 

range from 290° to 360°C. After the experiments, petrographic and geochemical determinations similar to those 

described above were performed on the solid residue. 

The following sections present and discuss the results 

of the petrological and geochemical studies carried out on 

both naturally and artificially matured samples. 

NATURALLY MATURED SAMPLES 

SAMPLING 

Coal and shale samples were collected from drill cores, 

well cuttings, and strip mines. Figure 1 shows the sample 

locations; these locations are also listed in table 1. During 

sampling, Almond coal and shale samples from various 

depths ranging from the surface to a maximum depth of 

18,000 ft were obtained for petrological and geochemical 

examination. Because the samples came from different 

areas of the GGRB and burial histories vary from place to 

place, no strict correlation could be established between 

maturation level and present depth of burial for all samples. 

However, a general correlation trend between level of maturation and depth of burial was found using several maturation indicators discussed in the following sections. 

ORGANIC PETROGRAPHY 

Petrographic characterization of a coal at different 

depths of burial provides information on the evolution of 

maceral composition as well as on the rank or maturity 

stage of the coal. This study differs from standard petrographic studies of coal because it is the first attempt to 

correlate maturation (or coalification) with textural features of the maceral assemblage in coals ranging from 

subbituminous to semianthracitic and its significance to oil 

generation. A similar study by Mukhopadhyay and others. 

(1991) described some "distinct morphological changes" 

in coals after hydrous pyrolysis; however, Mukhopadhyay 

and others ( 1991) did not examine the relationship of 

these morphological changes to the maturation stages of 

coals between naturally and artificially matured samples. 

The maceral analysis in this study adopted the maceral 

classification of Stach and others (1982), which is illustrated in table 2. 

MACERAL ANALYSIS OF ALMOND COALS 

The results of the maceral point counting discussed 

below are summarized in table 3. The coals are vitrinite 
<::OAL AS A SOURCE ROCK OF PETROLEUM AND GAS 407 

rich (> 70 percent), especially in the vitrinite sub maceral 

desmocollinite (ds) at shallow depth; as depth of burial increases, the vitrinite content decreases to about 40 percent. 

The second most abundant vitrinite maceral is telocollinite 

(tl). The abundance of liptinite group macerals (Tl) in the 

coal is low to moderate (0 to 13 percent). Samples from 

outcrops and shallow depths ( <5,000 feet present burial 

depth) have a higher content of liptinite macerals than the 

deep samples. At current burial depths greater than 13,000 

feet, few or no Iiptinite macerals are observed. The predominant ·liptinite group maceral in the coal is cutinite 

(cu), followed by sporinite (sp) and resinite (rs). 

Kemmerer 0 

110' 109' 108' 

EXPLANATION - ..... J / [-:_ -, /I Basement rocks I 

..... / - / ' 

~thrust fault 1 , I I 

-~ _, , wiNo' / /' ,_ / _. ' 

/ '_ I RIVER ' 

/ UPLIFT'~ ~ ....._ I / '-. II '- / 

I \ - \I \ _., 

- I"_ ' I ' -" __ 

/ ' - ..... / 

I I , ,... /' '

1 

"' 1 

'",--\, 

'- .._ , \'-/ I I 

' - I 

o Lander 

107' 

MONTANA 

0 miles 40 

I I I I I I I I I 

I 

0 kilometers 60 

Big Piney 

~ 32•

0

.31 •30 

•29 

I 

~ 

I 

I 

....... --~~ 

GREAT DIVIDE \ 

BASIN ' •27 \ 

GREEN " \. 

RAWLINS 

UPLIFT 

/ ~· · ... ···· ... ·. r"•ASt;TEFf 25 •. 1"\\Vl -- ~ 

RIVER _.: ROCK .. : -p..RcH •22 • 21 

Rock Springs ~o SPRINGS .:\a •19,20 

•24 

•23 

BASIN . TUPLIFT ..... <;:\~16:~4,15 

·.... ..·· a• •9 . . 

:.. :: WASHAKIE 

• •12 

13 I 

1 

SIERRA 

MADRE 

UPLIFT 

·.. ·. • 6 BASIN 

. •5 •4 •2,3 

\ 

SAND WASH /~ 

BASIN 1 ~ 

~~~~--- ~-"" rc,u 

U P Ll FT \l '\:::('-l 

Figure 1. Map showing sample site locati?ns. Numbers refer to list in table l. 

43' 

42' 

41' 
408 THE FUTURE OF ENERGY GASES 

Table 1. Site names and locations. 

[Numbers refer to locations on figure I] 

Map No. 

2 

3 

4 

5 

6 

7 

8 

9 

Site name Location 

27 Unit----------------------------------- Tl2, R I 01, S 16 

Blue Gap II 7-4-92--------------------- T14, R92, S7 

Blue Gap II 2-8-14--------------------- Tl4, R92, S8 

Celsius 16-1----------------------------- T14, R94, Sl6 

Monument Valley No. 1--------------- T14, R97, S32 

Adobe Town No. 1--------------------- TIS, R97, S20 

Champlin 535--------------------------- T 16, R97, S 17 

Higgins 13A ---------------------------- T17, R98, S7 

1 Champlin 336A ---------------------- T17, R94, S21 

10 Fred Federal No. 1--------------------- T17, R99, S30 

11 Fed 44-4--------------------------------- T18, R98, S4 

12 AMOCO Champlin 276-D ----------- T19, R92, S13 

13 AMOCO Champlin 242--------------- Tl9, R93, S11 

14 Arch Unit 14-24-4--------------------- Tl9, R97, Sll 

15 Robinson Siding No. 1---------------- Tl9, R97, Sll 

16 Table Rock 59-------------------------- Tl9, R97, SIS 

17 Arch Unit 33B-12-4 ------------------- T19, R99; S22 

18 Playa Unit 5-24G ---------------------- T20, R99, S22 

19 Champlin 345-A------------------------ T20, R99, S35 

20 UPRR 44-35 ---------------------------- T20, R99, S35 

21 5 G. U.3 Coal--------------------------- T21, R93, S35 

22 Oliver I USA AMOCO A ------------ T21, R94, S23 

23 I Champlin 528 AMOCO A--------- T21, R90, Sl9 

24 I Champlin 446 AMOCO A--------- T22, R90, SIS 

25 NGC 3-12A Federal------------------- T22, R94, Sl2 

26 Oliver B 107----------------------------- T22, R96, SS 

27 Enterprise A-1 -------------------------- T25, RI07, S30 

28 Fed Pacific Creek No. 1--------------- T27, R 103, S27 

29 Government C38 ----------------------- T28, R 113, S3 

30 Wagon Wheel No. I ------------------- T30, R 108, SS 

31 Bar Cross 63X-12---------------------- T30, Rll2, S21 

32 Belco 5-29-27--------------------------- T30, Rll3, S27 

33 Merma No. 3-28------------------------ T36, Rll2, S28 

Macerals in the inertinite group (Tin) range in content 

from I to 60 percent in these coals, depending upon depth 

of burial. The predominant maceral in the inertinite group 

is semifusinite (sf), followed by fusinite (fu) and micrinite 

(mi); this assemblage evolves from semifusinite to fusinite 

with increasing thermal exposure (see "Artificially Matured Samples" section). The ternary diagram in fig. 2 

shows the evolution of maceral groups (liptinite, vitrinite, 

and inertinite) in the coal through increasing burial depth. 

Table 2. Maceral classification for hard coals (after 

Stach and others, 1982). 

[NA, not applicable] 

Group maceral Maceral Submaceral 

Vitrinite----------- Telinite----------------- Telinite 

Telocollinite 

Collinite --------------- Desmocollinite 

Corpocollinite 

Vitrodertinite---------- NA 

Liptinite ---------- Sporinite ---------------

Cutinite ----------------

Resinite ----------------

Alginite----------------

Exsudatinite -----------

Liptodetrinite ---------

1 nerti n i te---------- M i cri ni te---------------

Macrinite --------------

Semifusinite-----------

Fusinite ----------------

Sclerotinite ------------

Inertodetrinite---------

Vitrinite 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

NA 

Inertinite 

Figure 2. Ternary diagram showing maceral group composition 

of Almond coals at different burial depths. Arrow indicates maturation trend with increasing burial. 

Samples from shallow burial are rich in vitrinite with some 

liptinite, whereas samples from deep burial are richer in 

inertinite and almost totally depleted in liptinite macerals. 

The trend of maceral transformation with increasing 

maturation illustrates how the hydrogen-rich macerals 

(desmocollinite and liptinite) are transformed into inertinite macerals. The inertinite content of the deep samples 

reaches values of over 50 percent (table 3) as vitrinite and 

liptinite macerals are transformed into inertinite macerals 
= ~ B ,_ bO c: 

"' 2 c:-" 0 ~ 

~ M 15 ·~ E 'C: 

"' u z ,_ ~ E 

COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 409 

8 8 8 ~ 8 8 8 ~ 8 ~ 8 

0 0 0 0 ~ N 0 M 0 0 

~ 8 ° 8 ~ ~ 8 8 8 8 8 

0 0 0 0 0 0 0 0 0 0 0 

~ g g ~ ~ ~ ~ 8 8 8 8 

o o o N o o o o o o 

~ ~ ~ 8 ~ g 8 8 8 8 8 

0 0 ~ N ~ ~ ~ ~ 0 ~ N N ~ lrl M 

~ g ~ 8 ~ ~ 8 8 ~ ~ 8 

0 0 d 0 ~ ~ ~ ~ 00 ~ 00 

~ 0 ~ 8 ~ ~ 8 ~ 8 8 8 

N ~ 0 ~ ~ ~ 0 M 0 0 0 

~ 8 ~ ~ 8 8 8 8 8 8 8 

o N N o o N o o o 

~ @ ~ ~ 8 ~ ~ 8 ~ g 8 8 ~ N N N N o o o o o 

ci 

z 

0. 

i 

g ~ ~ ~ 8 ~ 8 ~ 8 8 8 ~ ~ ~ ~ ~ ~ 0 0 0 0 

~ ~ ~ 8 ~ ~ ~ ~ ~ ~ 8 ~ ~ ~ ~ g ~ ~ ~ ~ ~ ~ 

~ ~ ~ 8 ~ 8 8 8 8 8 8 

00 ~ ~ 0 00 0 0 ~ 0 d 0 \01:""--1:""--\0lrlrby aromatization and loss of aliphatic compounds in the 

kerogen; similar maceral transformations are observed 

during hydrous pyrolysis. The distinction between structureless telocollinite and semifusinite becomes difficult to 

recognize at vitrinite reflectance values higher than 0.9 

percent. These observations of maceral evolution with increasing maturation are supported by geochemical analyses, including the NMR spectra analyses, discussed below. 

TEXTURAL VARIATIONS OF ALMOND COALS 

WITH DEPTH OF BURIAL 

A marked difference is observed between the textures 

of the shallow and deep coal samples. Samples from outcrops of the Almond Formation in the Rock Springs Uplift, which have a mean maximum vitrinite reflectance of 

0.45 percent, show desmocollinite with a finely laminated 

texture forming a groundmass in which the inertinite and 

Iiptinite macerals are dispersed (fig. 3). As depth of burial 

increases, the original laminated texture becomes more homogeneous; in the 4,217-ft-deep sample, the original thin 

lamination is no longer observable (fig. 4). Also at this 

depth, micrinite macerals begin to form at the expense of 

the Iiptinite; a similar observation was reported by M. Teichmtiller (in Stach and others, 1982). According to Teichmtiller, the genesis of the micrinite coincides with the 

formation of petroleum from the liptinite macerals. This 

observation is supported by the occurrence of indigenous 

oil, present in fissures, coincident with the formation of 

micrinite in the 4,217-ft-deep sample (figs. 5, 6). 

At 6,944 ft present burial depth, a porous texture begins to develop in the coal (figs. 7, 8). Other important 

petrographic changes include an increase in the semifusinite content and the formation of exsudatinite (bitumen) in 

the pores. The incipient porous texture at 6,944 ft depth 

evolves to a vesicular texture at present burial depths 

greater than 10,000 ft; these vesicles are developed for the 

most part in semifusinite and fusinite macerals and are 

Figure 3. Photomicrograph of coal from an outcrop of the Almond Formation showing characteristic finely laminated texture 

of desmocollinite (d), with dispersed sporinite (sp), cutinite (cu), 

and inertinite (in) macerals. Reflected white light. 
410 THE FUTURE OF ENERGY GASES 

filled with exsudatinite (only observable under blue light, 

where it shows a characteristic orange fluorescence; figs. 

9, 10). The oil observed coming from fissures and pores 

(figs. 5, 6, II, and 12) in samples from depths between 

4,200 and 12,000 ft present burial depth suggests that the 

burial histories at the localities shown in figure I are such 

that the coal layers between 4,000 and 12,000 ft are presently in the conventional oil window; this conclusion is 

supported by nuclear magnetic resonance (NMR) and anhydrous pyrolysis analyses (discussed below). This depth 

range may vary plus or minus 4,000 ft, depending upon 

the subsidence or uplift experienced at a given locality. 

Figure 4. Photomicrograph of coal from the Almond Formation 

at a depth of 4,217 ft. The desmocollinite (d) looses its original 

laminate texture. Micrinite (m) starts to form from liptinite macerals. Sporinite (sp). Reflected white light. 

' • .. .. 

v 

.. 

kii - .... -

Figure 5. Photomicrograph of coal from the Almond Formation 

at a depth of 4,217 ft. Indigenous oil (ol) associated with fissures 

in vitrinite (v). Sporinite (sp). Reflected white light. 

The organic petrography clearly indicates that oil 

has been generated in samples from 4,000 through about 

12,000 ft present burial depth. However, oil is not always 

expelled from the coal until its storage capacity is overcome as increasing volumes of liquid and gaseous hydrocarbons are generated. This occurs at vitrinite reflectances 

of about 0.8 to 1.7 percent (determined on the basis of 

hydrous pyrolysis experiments). 

At depths greater than 14,000 ft, the vesicular nature 

of the coal texture begins to decrease, presumably owing to 

the expulsion of the exsudatinite (bitumen); also, the remaining exsudatinite no longer fluoresces. The vitrinite and 

semifusinite show optical relief and reflectance so similar 

Figure 6. Photomicrograph of same feature as figure 5 under reflected blue light showing fluorescence of indigenous oil (ol) and 

sporinite (sp) . 

Figure 7. Photomicrograph of coal from the Almond Formation 

at a depth of 6,944 ft. Development of porous texture as exsudatinite (ex) starts to form. Vitrinite (v), sporinite (sp), indigenous 

oil (ol). Reflected white light. 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 411 

that petrographic distinction between them is unclear. Coal 

samples from depths greater than 14,000 ft exhibit a texture characterized by flat surfaces with a minimum difference in optical relief between the semifusinite matrix and 

the occasional fusinite macerals (figs. I 3, I 4 ). The vitrinite 

or semifusinite matrices have reflectance values between 

1.5 and 2.0 percent. At this level of maturation, the vitrinite-semifusinite matrix begins to show an increase in birreflectance under crossed nicols. The maturity levels indicate 

that the samples are passing out of the liquid petroleum 

window (or bituminization stage) and are experiencing the 

onset of wet-gas generation (corresponding to the formation of sernianthracitic coal). 

Figure 8. Photomicrograph of same feature as figure 7 under reflected blue light showing fluorescence of exsudatinite (ex), 

sporinite (sp), and oil (ol). 

Figure 9. Photomicrograph of coal from the Almond Formation 

at a depth of 10,720 ft. Development of vesicular texture on 

semifusinite (sf), vesicles (vs) filled with exsudatinite. Vitrinite 

matrix (v). 

In sum, the textural and compositional changes observed in Almond coals with increasing depth of burial 

are (1) loss of the original laminated texture of desmocollinite, (2) transformation of Iiptinite macerals into 

micrinite, releasing oil, (3) formation of a porous texture 

that at deeper burial evolves to a vesicular texture, and 

Figure 10. Photomicrograph of same feature as figure 9 under 

reflected blue light showing fluorescence of the exsudatinite (ex) 

in the semifusinite vesicles. Vitrinite (v). 

v 

' 

Figure 11. Photomicrograph of coal from the Almond Formation 

at a depth of 10,837 ft. Vesicular texture on vitrinite matrix (v). 

Note the expulsion of oil from the vesicles filled with exsudatinite (ex). Reflected white light. 
412 THE FUTURE OF ENERGY GASES 

(4) rehomogenization of the vitrinite-semifusinite matrix. 

The changes in maceral composition in the coal result in 

a decrease in liptinite and an increase in inertinite macerals with depth. Similarly, the formation of semifusinite 

accompanies the formation of exsudatinite. 

Figure 15 shows the increase of mean vitrinite reflectance (R0 ) with depth for Almond coals and shales. Table 

4 gives the mean vitrinite reflectance for representative 

samples. The scatter in the data is likely due to variability 

Figure 12. Photomicrograph of same feature as figure II under 

reflected blue light, showing fluorescence of indigenous oil (ol) 

expelled from the vesicles filled with exsudatinite (ex). 

v 

Figure 13. Photomicrograph of coal from the Almond Formation at a depth of 14,249 ft. Vitrinite (v)-semifusinite (sf) matrix completely homogenized. Shale matrix (sh). 

in maximum thermal exposure relative to present burial 

depth and to the presence of some reworked vitrinite particles in the shales on which reflectance was measured. In 

general, the R0 data suggest that samples from the surface 

to about 12,000 ft present burial are in the conventional 

Figure 14. Photomicrograph of coal from the Almond Formation 

at a depth of 14,249 ft. Vitrinite (v) matrix and semifusinite (sf) 

showing similar optical relief and reflectances. 

0 

4000 

-

= 8000 

..r:::: 

..... 

a. 

Q) 

0 12000 

16000 

20ooo~~~~~~~~~~~~ 

0. 1 1 0 

R 0 

Figure 15. Mean vitrinite reflectance (R0 ) versus depth for the 

Almond Formation shales and coals, Greater Green River Basin, 

Wyoming. 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 413 

Table 4. Summary of measured vitrinite reflectance of shale 

and coal samples from selected sites, Almond Formation, 

Greater Green River Basin, Wyoming. 

[R0 , mean random vitrinite reflectance] 

Site name Map No. Depth Ro 

(ft) (pet) 

Outcrop sample---------------------- 0 0.45 

Arch Unit 14-24-4 ------------------ 14 4,217 0.47 

Arch Unit 14-24-4 ------------------ 14 4,218 0.57 

Arch Unit 14-24-4 ------------------ 14 4,247 0.60 

Arch Unit 14-24-4 ------------------ 14 4,406 0.58 

UPRR 44-35 ------------------------- 19 4,560 0.52 

Playa Unit 5-24G ------------------- 18 4,883 0.62 

Playa Unit 5-24G ------------------- 18 4,894 0.69 

Bar Cross 63X-12------------------- 31 6,943 0.71 

Higgins 13A ------------------------- 8 7,013 0.85 

Blue Gap II 7-4-92 ----------------- 2 9,150 0.90 

5 G. U .3 Coal------------------------ 21 10,720 0.88 

I Champlin 336A ------------------- 9 10,848 1.12 

I Champlin 528 AMOCO A ------ 23 12,091 1.45 

Adobe Town No.I ------------------ 6 13,000 2.10 

I Champlin 528 AMOCO A------ 23 14,240 1.60 

Wagon Whell No. I ---------------- 30 14,929 1.50 

Wagon Whell No. I ---------------- 30 14,942 1.69 

Wagon Whell No. I ---------------- 30 18,330 2.10 

oil window defined by Tissot and Welte (1984) to be between 0.5 and 1.3 percent. 

However, we redefine the entrance to the oil window 

for these coals as not merely the level of maturation where 

liquid hydrocarbons are generated but as the level of maturation at which liquid hydrocarbons are expelled from the 

coal. This new interpretation narrows the oil window for 

the center of the basin to the depth interval of 4,000 to 

12,000 ft. In this depth interval, the vitrinite reflectance 

ranges from 0.5 to 1.7 percent, with the main phase of oil 

generation and expulsion between 0.9 and 1.6 percent 

Rmax· The main phase of oil generation and expulsion was 

determined on the basis of hydrous pyrolysis experiments 

on Almond coals (discussed below). 

The "bottom" of the liquid window is defined petrographically as the stage of rehomogenization of the vitrinite-semifusinite matrix; this level of maturation occurs 

when exsudatinite is no longer observed in the naturally 

matured samples (Rmax=l.7 percent). 

The textural and compositional changes observed in 

Almond coals are indicative of the generation and expulsion of liquid hydrocarbons. These hydrocarbons are generated from source materials such as liptinite, which are the 

main source of liquid hydrocarbons in many coals, according to Teichmi.iller (in Stach and others, 1982). Teerman 

and Hwang (1991) reported desmocollinite (a hydrogenrich vitrinite) to be another important source of hydrocarbons. Desmocollinite is the main maceral constituent in 

Almond coals (table 3) and is the source of the exsudatinite 

formed during burial of the Almond Formation. Moreover, 

the development of vesicular textures in semifusinite and 

vitrinite, where the vesicles are filled with exsudatinite, 

clearly indicates that the expulsion of liquid hydrocarbons, 

mainly waxes, is the origin of such textures. 

There is not always a strict correlation between 

present depth of burial and maturation because burial and 

uplift vary from one area to another in the GGRB. For 

instance, samples with similar maturation levels (R0 ) are 

found at present depths of 13,000 ft and 18,000 ft (samples from Adobe Town No. 1, 13,000 ft, and Wagon 

Wheel, 18,330 ft; table 4). 

ORGANIC GEOCHEMISTRY 

NMR measures the distribution of various chemical 

functional groups in kerogen molecules; these include aliphatic and aromatic functional groups in the coal and kerogen in shale. Comparing the NMR spectra analyses from a 

suite of samples from different depths is useful in understanding both how the kerogen structure evolves during 

thermal maturation (Miknis, Sullivan, and others 1981) and 

when liquid petroleum and gas were generated (see reviews in MacGowan, Britton, and others, 1992, and Miknis, Jiao, and others, 1993). Figure 16 presents the NMR 

spectra for 15 shales of the Almond Formation from 4,594 

ft to 18,420 ft present depth in the GGRB. The large peak 

to the right is the aliphatic-group spectrum, and the large 

peak to the left is the aromatic-group spectrum. The aliphatic peak becomes progressively smaller and less well 

defined, and the aromatic peak becomes relatively larger 

and sharper, with increasing maturity and depth. These 

changes represent the maturation of the kerogen and the 

accompanying generation and expulsion of aliphatic hydrocarbons (liquid and gaseous) and closing of free radicals 

into aromatic rings with increasing thermal maturity of the 

kerogen (Miknis, Sullivan, and others 1981; Miknis, Jiao, 

and others, 1993). Somewhere between about 10,000 and 

15,000 ft (shale aromaticity ratio at about 0.9, table 5), 

depending upon the thermal exposure associated with maximum burial, these shales lose their potential to generate 

liquid hydrocarbons. From this maturity level onward, the 

cleavage of the kerogen mainly generates methane. This 

change in aliphaticity versus aromaticity indicated by the 

NMR analyses can be correlated with the second stage of 

coalification (Meissner, 1989), delineating the onset of the 

gas generation zone (volatile matter <10 percent, R0 >2 

percent). 
414 THE FUTURE OF ENERGY GASES 

.c -

0.. 

(j) 

0 

4594 

4688 

4694 

4721 

4900 

6600 

6665 

6861 

7441 

9055 

9159 

10663 

12265 

12273 

12604 

13659 

13661 

14314 

17330 

18420 

I I 1 I I i t I t t i 

400 300 200 

! I I I I I t I I I I I 

100 0 -100 

(ppm) 

NMR Spectra 

I I 

-200 

Figure 16. Nuclear magnetic resonance (NMR) spectra for the 

Almond Formation shales, Greater Green River Basin, Wyoming. 

Figure 17 is a similar plot of NMR spectra versus 

depth for 19 coal samples from the Almond Formation 

from 4,560 ft to 14,929 ft in the GGRB. The samples 

show a trend similar to that of the shales in decreasing 

aliphatic content and increasing aromatic content with 

depth. Between 10,898 and 14,929 ft depth, these coals 

lose much of their aliphatic-carbon. content. Also, in this 

depth interval there is a slow change in aliphatic-carbon 

content, which is explained by the coalification curve of 

Meissner (1989)-the slope of the curve decreases drastically once the second stage of coalification (high-volatiles 

bituminous) is reached, as illustrated in figure 18. A similar NMR spectra trend was obtained in the hydrous pyrolysis experiments (discussed below), suggesting that 

Almond coals still have some generative capacity for 

aliphatic-hydrocarbons, mainly gaseous, at the maximum 

Table 5. Carbon aromatJCJty (as determined by nuclear 

magnetic resonance) with depth for shales and coals in 

the Almond Formation. 

[Aromaticity ratio=(Aromatic carbon) I (Aromatic carbon+Aliphatic 

carbon)] 

Depth Coal Depth Shale 

(ft) aromaticity (ft) aromaticity 

4,560 0.69 4.594 0.77 

4,884 0.68 4,668 0.73 

4,884 0.75 4,693 0.69 

4,894 0.67 4,694 0.83 

6,667 0.67 4,721 0.75 

6,789 0.71 4,894 0.65 

6,944 0.69 4,900 0.62 

7,013 0.69 6,600 0.75 

9,150 0.72 6,665 0.74 

9,150 0.78 6,871 0.72 

10,720 0.77 7,441 0.71 

10,837 0.9 9,055 0.77 

10,898 0.83 9,150 0.72 

12,091 0.8 9,159 0.75 

13,000 0.91 10,663 0.84 

14,286 0.77 10,946 0.83 

14,929 0.84 12,071 0.78 

12,121 0.79 

12,265 0.88 

12,273 0.87 

12,604 0.94 

13,223 0.89 

13,659 0.9 

14,942 0.9 

17,330 0.94 

18,420 0.96 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 415 

4560 

4650 

4883.5 

4884 

4894 

6667 

6789 

6943.5 

7013 

~ 9150 .r::: 

a. 

<ll 

0 9150 

10719.5 

10837 

10898 

10946 

12091 

13000 

14286 

14929 

I I 

400 

I I I 

300 

I j I I I I I I I I I I I 

200 100 0 

(ppm) 

NMR Spectra 

I I I 

-100 

I I 

-200 

Figure 17. Nuclear magnetic resonance (NMR) spectra for the Almond Formation coals, Greater Green River Basin, Wyoming. 

depth of sampling (14,929 ft). This interpretation is supported by the fact that Almond shales from the maximum 

depth of sampling (> 18,000 ft) do not exhibit an aliphaticcarbon resonance peak. 

Table 5 lists carbon aromaticity (defined as the ratio 

[aromatic-carbon]/[aromatic-carbon+aliphatic-carbon]) and 

depth for samples for which NMR spectra were obtained. 

Figure 19 shows the fraction of aromatic-carbon in the kerogen versus depth for the Almond Formation shales and 

coals. Although there is scatter in the data, a general trend of 

increasing aromaticity with depth can be seen. The scatter is 

thought to be due to variability in maximum thermal exposure relative to present burial depth and possibly to variability in the maceral content of Almond coals and shales. The 

scatter in aromaticity at shallow depth is most likely due to 

variable oxidation of the kerogen once it has been infiltrated 

by meteoric water. 

Conventional anhydrous pyrolysis results (genetic potential, GP; hydrogen index, HI; maximum hydrocarbon 

generation temperature, T max; and production index, PI) 

for most samples are listed in table 6. Production index is 

a measure of thermal maturity; a kerogen is believed to be 

in the conventional oil window at a PI between 0.1 and 

0.4 in absence of oil migration (Tis sot and Welte, 1984 ). 

Figure 20 shows production index versus depth. This normally is indicative of the expected increase in thermal maturity with increasing depth, but may reflect changing 

organic-matter type and variable oil expulsion. The Almond Formation appears to be in the conventional oil window between about 4,200 and 14,500 ft present burial 

depth on the basis of PI data, which agrees with much of 

the vitrinite reflectance data (discussed earlier). 

80 

-- 70 ra 

"0 

-u 60 c.. 

- 50 ~ 

.._ 4 0 ~ 

eti 

E 30 

Q) 

- 20 ra 

0 

> 1 0 

0 

0 2 3 

Vitrinite reflectance 

4 5 6 

( R ) percent 0 

peat 

high-vol 

bit 

med-vol 

bit 

low-vol 

bit 

anthracite 

Figure 18. Relation of vitrinite reflectance (R0 ) to volatile matter 

and U.S. coal-rank classification. Modified from Meissner 

(1989). Daf, dry ash free; subbit, subbituminous coal; high-vol 

bit, high-volatiles bituminous coal; med-vol bit, medium-volatiles bituminous coal; low-vol bit, low-volatiles bituminous coal; 

semianth, semianthracitic coal. 
416 THE FUTURE OF ENERGY GASES 

0 I I I 0 I I I 

A 8 

4000 - - 4000 f- - • • • ••• • ., • 

. .. - • •• - 8000 • ..... 

-- - - - 8000 f- - - - ••• • • J: ...:::::: 

- , ..... a. • c.. • • ~ 12000 f- •• • - ~ 12000 - • - • •• • 

• • • 16000 - - 16000 - - • 

• 

20000 I I I 20000 I I I 

0.6 0.7 0.8 0.9 1 0.6 0.7 0.8 0.9 1 

Aromaticity ratio Aromaticity ratio 

Figure 19. A. Aromaticity ratio versus depth scatter plot for the Almond Formation shales. B. Aromaticity ratio versus depth, scatter 

plot for the Almond Formation coals. Greater Green River Basin, Wyoming. Aromaticity ratio=(Aromatic carbon)/(Aromatic carbon+ 

Aliphatic carbon). 

The geochemical characterization of the kerogen type 

in Almond coals and shales was obtained from an HI versus 

Tmax diagram (fig. 21) as suggested by Espitalie and others 

(1986). Figure 21 illustrates a general low-slope trend for 

the HI-T max plot, which is characteristic of type III 

kerogen. The scatter observed in this plot is possibly due to 

a mineral matrix effect in the shale samples that lowers the 

H1 values (Espitalie and others, 1986). 

Figure 22 presents T max versus depth for the coal and 

shale samples. T max is another measure of relative kerogen 

maturity. T max for these samples increases fairly linearly 

with depth, indicating a fairly normal maturation trend. According to Espitalie and others (1985), the T max range for 

the oil generation window lies between 400° and 600°C for 

type III kerogen (which is close to a vitrinite coal), with the 

threshold of oil generation between 430° and 435°C and the 

threshold of gas generation between 465° and 470°C (Espitalie and others, 1985). Figure 22 shows two T max populations at about 423° and 468°C, a distribution which allows 

determination of the depth range of the conventional oil 

window to be approximately between 4,000 and 12,000 ft. 

Both petrographic observations of Almond coals and 

geochemical characterizations of shales and coals of the 

Almond Formation indicate that all samples from outcrop 

to maximum depth of sampling have similar compositions 

of type III kerogen. 

In conclusion, the results of geochemical analyses (anhydrous pyrolysis and vitrinite reflectance) indicate that at 

the center of the basin, most of the Almond Formation 

samples from 4,000 to 12,000 ft present burial depth are in 

the conventional oil window. On the basis of T max 

(Tmax<!:468°C) and NMR (aromatic ratio<!:0.9) results, we 

delineated the entrance of the gas window between 12,000 

and 14,000 ft present burial depth. The boundary between 

the oil and gas windows coincides with the rehomogenization of the semifusinite-vitrinite matrix discussed above in 

the organic petrography section. 

Petrographic observations in both natural and artificially matured samples demonstrate that oil is generated 

over a vitrinite reflectance range from 0.5 to 1.7 percent 

This is a wider range than that given by Tissot and Welte 

( 1984 ), a range which is between 0.5 and 1.3 percent. It 

should be noted that in the upper range of reflectance values (maximum vitrinite reflectance (Rmax)<!:0.9 percent), 

the hydrous pyrolysis experiments show that gas is also 

being generated from the thermal degradation of liquid 

hydrocarbons. 

The depth ranges for the oil and gas windows at a 

given location in the GGRB depend upon the burial history of the source rock and especially on the level of erosion 

at that location. Therefore, these depth ranges vary considerably throughout the basin. 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 

Table 6. Results of anhydrous pyrolysis and total organic carbon (TOC) analysis 

on shale and coal samples from the Almond Formation at different depths of 

burial. 

[HC, hydrocarbon; S I =mg HC/g sample, hydrocarbons present in the sample; S2=mg HC/g sample, 

hydrocarbons generated during pyrolysis~ T max• maximum temperature of hydrocarbon generation; 

IC(pct), inorganic carbon in percent; TC(pct), total carbon in percent; TOC(pct), total organic carbon as 

a percentage; PI=SI/(SI+S2), production index; HI=S2/TOC, hydrogen index; GP=SI+S2, genetic potential; n.d., no data] 

Depth (ft) 

2,991 

4,560 

4,594 

4,688 

4,693 

4,693 

4,721 

4,884 

4,884 

4,894 

4,900 

5,365 

6,665 

6,881 

6,944 

6,955 

7,013 

7.024 

7.393 

7,441 

9,055 

9,056 

9,080 

9,150 

9,159 

10,671 

10,691 

10,898 

10,946 

12,071 

12,121 

12,091 

12,265 

12,604 

13,000 

13,223 

13,659 

13,453 

13,661 

14,286 

14,314 

14,338 

14,902 

14,929 

14,942 

16,119 

16,940 

17,330 

17,969 

18,330 

18,410 

Sl 

1.26 

5.90 

0.22 

0.81 

0.21 

1.95 

0.36 

8.89 

2.37 

1.24 

4.03 

0.44 

0.83 

1.57 

6.37 

0.66 

6.56 

0.83 

0.20 

0.93 

1.56 

3.82 

0.63 

4.69 

0.73 

4.54 

2.89 

16.03 

0.85 

0.38 

0.34 

15.70 

n.d. 

0.34 

0.73 

0.37 

0.24 

0.19 

0.23 

12.49 

0.20 

0.17 

6.59 

1.63 

1.71 

0.33 

3.08 

0.74 

0.83 

1.53 

0.60 

S2 

1.32 

106.50 

2.92 

9.34 

1.69 

2.76 

3.95 

165.80 

130.00 

42.50 

32.25 

2.51 

10.93 

32.67 

208.00 

3.43 

164.50 

9.43 

1.66 

10.70 

18.65 

57.70 

6.49 

48.68 

3.06 

34.55 

14.04 

I 16.50 

2.90 

1.07 

1.10 

124.90 

n.d. 

1.11 

5.01 

1.19 

0.97 

0.41 

1.00 

108.70 

0.69 

0.67 

31.21 

5.33 

1.91 

0.26 

2.11 

0.96 

1.19 

1.26 

0.77 

Tmax 

422 

403 

422 

419 

438 

418 

421 

434 

422 

418 

420 

427 

424 

422 

425 

434 

426 

422 

423 

424 

443 

440 

448 

445 

446 

453 

452 

456 

456 

446 

447 

450 

n.d. 

468 

428 

459 

468 

468 

469 

449 

452 

452 

469 

469 

468 

468 

n.d. 

n.d. 

453 

n.d. 

n.d. 

JC 

(pet) 

0.02 

5.89 

0.43 

0.16 

0.54 

2.26 

0.21 

0.01 

0.03 

0.00 

0.00 

1.23 

1.26 

0.12 

0.08 

0.13 

0.00 

0.85 

0.51 

0.27 

0.22 

0.01 

0.00 

0.01 

0.42 

0.00 

0.24 

0.01 

0.02 

0.95 

1.05 

0.35 

1.03 

1.22 

0.80 

0.47 

0.01 

0.66 

0.01 

0.03 

1.28 

0.40 

1.26 

0.04 

0.05 

2.48 

0.90 

1.56 

3.84 

1'.81 

1.33 

TC 

(pet) 

3.96 

41.00 

2.46 

5.41 

2.22 

4.57 

4.03 

76.32 

73.30 

15.70 

10.70 

2.97 

5.82 

15.78 

79.90 

1.47 

64.00 

5.00 

1.58 

3.64 

10.21 

33.30 

4.68 

27.92 

3.53 

24.90 

11.80 

83.80 

5.90 

2.08 

2.76 

75.99 

2.85 

3.47 

11.61 

2.48 

5.86 

1.87 

5.22 

54.89 

2.68 

1.80 

55.90 

11.52 

5.93 

3.24 

6.87 

3.17 

6.12 

3.58 

3.14 

TOC 

(pet) 

3.94 

35.11 

2.03 

5.25 

1.68 

2.31 

3.82 

76.31 

73.27 

15.70 

10.70 

1.74 

4.56 

15.66 

79.82 

1.34 

64.00 

4.15 

1.07 

3.37 

9.99 

33.29 

4.68 

27.91 

3.11 

24.90 

11.56 

83.79 

5.88 

1.13 

1.71 

75.64 

3.88 

2.25 

10.81 

2.01 

5.84 

1.21 

5.21 

54.86 

1.40 

1.40 

54.64 

11.48 

5.89 

0.76 

5.97 

1.61 

2.28 

1.77 

1.81 

PI 

0.49 

0.05 

0.07 

0.08 

0.11 

0.41 

0.08 

0.05 

0.02 

0.03 

0.10 

0.15 

0.07 

0.05 

0.03 

0.16 

0.04 

0.08 

0.11 

0.08 

0.08 

0.06 

0.09 

0.09 

0.19 

0.12 

0.17 

0.12 

0.23 

0.26 

0.24 

0.11 

n.d. 

0.23 

0.13 

0.24 

0.20 

0.31 

0.18 

0.10 

0.22 

0.20 

0.17 

0.23 

0.47 

0.56 

0.59 

0.44 

0.41 

0.55 

0.44 

HI 

34 

303 

144 

178 

100 

119 

104 

217 

177 

271 

329 

144 

240 

209 

261 

256 

257 

227 

155 

318 

187 

173 

139 

174 

99 

139 

121 

139 

49 

95 

64 

165 

n.d. 

49 

46 

59 

17 

33 

19 

198 

49 

48 

57 

46 

32 

34 

35 

59 

52 

71 

42 

GP 

2.58 

112.40 

3.14 

10.14 

1.90 

4.70 

4.30 

174.70 

132.37 

43.74 

39.28 

2.95 

11.80 

34.20 

214.37 

4.09 

171.06 

10.26 

1.86 

11.63 

20.21 

61.52 

7.12 

53.40 

3.80 

39.09 

16.93 

132.50 

3.70 

1.50 

1.40 

140.60 

n.d. 

1.40 

5.70 

1.60 

1.20 

0.59 

1.23 

121.20 

0.88 

0.84 

37.80 

7.00 

3.60 

0.60 

5.20 

1.70 

2.00 

2.80 

1.40 

417 
418 THE FUTURE OF ENERGY GASES 

ARTIFICIALLY MATURED SAMPLES 

Hydrous pyrolysis (HP) has been used to study the 

maturation of sedimentary organic material (see review in 

Surdam and others, 1989) and has recently been used to 

study the maturation of coal (Katz and others, 1991; Teer-

-

---

..c: 

-c. 

0 I 

4000~ 

0 

CJl) 8 0 

8000 r-- 0 

I 

am o 

§ 

I I I 

0 -

-

~ 12000- -

1 6000 r00 

0 

0 

oc 

0 

2 0 0 0 0 ._____._l __ ..___l----~.1 __ ...._ 1------lJ _ ___.J 

0 0.1 0.2 0.3 0.4 0.5 0.6 

Production index 

Figure 20. Production index (PI) versus depth for Almond Formation core samples, Greater Green River Basin, Wyoming. 

G' 675 

0 

f--

Ol 

--- () 450 I 

Ol 

E 

I 

36~0----~----~~~~~~~._----~----_J 

400 440 480 520 560 600 

T max (oC) 

Figure 21. Hydrogen index (HI) versus maximum temperature of 

hydrocarbon generation (T max) for Almond Formation samples. 

Milligrams of hydrocarbon per gram total organic carbon, mg 

HC/g TOC. Figure also shows the general trends of kerogen 

types I, II, III for comparison. 

man and Hwang, 1991; Mukhopadhyay and others, 1991; 

Khavari Khorasani and Michelsen, 1991; MacGowan, 

Britton, and others, 1992; MacGowan, Garcia-Gonzalez, 

and others, in press; Garcia-Gonzalez and Surdam, 1992; 

Yin, Surdam, and others, in press). 

Recent detailed chemical kinetic modeling based on 

elementary reactions has demonstrated that "high-temperature laboratory kinetic data can be used to model the timing and kinetics of kerogen maturation processes occurring 

at low temperature over geologic time spans (Freund, 

1 992). In addition, Lewan and others (1979), and Lewan 

(1985) have demonstrated that hydrous pyrolysis mimics 

many aspects of petroleum generation, including (1) petrographic aspects of oil generation and expulsion, and (2) 

composition of the oil produced. In spite of these observations, hydrous pyrolysis has been occasionally criticized as 

not accurately reflecting geologic processes because it substitutes high temperature for geologic time (see Saxby, 

1 982; Snowdon, 1979). 

An Almond Formation coal sample was subjected to 

72-hour isothermal hydrous pyrolysis experiments. These 

experiments were carried out on a suite of samples at temperatures of 290°, 300°, 310°, 320°, 330°, 340°, 345°, 

350°, and 360°C using the technique described by Lewan 

( 1985) and Lewan and others (1979); a detailed description of our laboratory techniques can be found in Yin, Surdam, and others, in press. 

0 

0 

4000 

ocfJ 

- ® 0 -- 8000 Oil Generation Window -

..c: ~ 

- <Q) c. 

(1) 12000 

c 0 

0 

16000 0 

0 

2oooo~~~~~~~~--~ 

400 420 440 460 480 500 

T (°C) 

max 

Figure 22. Maximum temperature (T max) versus depth for Almond Formation samples, Greater Green River Basin, Wyoming. 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 419 

ORGANIC PETROGRAPHY 

MACERAL ANALYSIS 

Table 7 summarizes the point-count data obtained from 

microscopic examination of Almond coal samples after hydrous pyrolysis. The starting material is characterized by 

(1) a vitrinite (Tv) content. of 76 percent, dominated by 

desmocollinite (ds), (2) a liptinite (TI) content of approximately 11 percent, dominated by cutinite (cu) and followed 

by sporinite (sp); the exsudatinite (ex) maceral, or bitumen, 

is absent, and (3) an inertinite (Tin) content of 13 percent, 

the most common inertinite macerals are micrinite (mi) and 

macrinite (rna), followed by semifusinite (sf). As the temperature of hydrous pyrolysis increases, the liptinite content 

decreases gradually to a residual minimum value at 310°C. 

Once this temperature is reached, no liptinites survive; all 

have been transformed into micrinite and exsudatinite (bitumen). Similarly, the vitrinite content gradually decreases 

at the 340°C eXperiment; it then abruptly goes to low levels 

as vitrinite is transformed into semifusinite, owing to the 

progressive loss of aliphatic compounds. In the sample at 

345°C, desmocollinite is not present, whereas the structureless telocollinite and semifusinite have increased. 

The ternary diagram (fig. 23) illustrates the course of 

these maceral transformations with temperature, excluding 

exsudatinite generation. Figure 24 shows the maceral composition with increasing temperature of the vitrinite, Iiptinite, and the inertinite maceral groups; figure 24 also 

includes the secondary maceral exsudatinite. Both figures 

23 and 24 show an increase with temperature of the inertinite maceral group accompanied by a decrease of the liptinite and vitrinite maceral groups. 

Exsudatinite and liquid petroleum are the secondary 

products of the maceral transformations corresponding to 

the maturation of Almond coals. The peak generation of 

exsudatinite is at 345°C. At higher temperatures, there is a 

decrease in exsudatinite owing to thermal cracking of the 

exsudatinite to lighter compounds, such as liquid and gaseous hydrocarbons. These petrographic observations are 

supported by the geochemical results discussed below. 

TEXTURAL DESCRIPTION OF ALMOND COALS 

AFTER HYDROUS PYROLYSIS 

The starting material in the hydrous pyrolysis experiments was Almond coal sampled at the surface. In outcrop 

around the Rock Springs Uplift, Almond coal has a vitrinite 

reflectance value (Rmax) of 0.45 percent. Table 7 includes 

Vitrinite 

Inertinite 

Figure 23. Ternary diagram showing the course of the maceral 

transformations with increasing temperature of hydrous pyrolysis 

experiments. Liptinite refers to primary macerals excluding exsudatinite. Arrow indicates trend of maturation with increasing temperature in hydrous pyrolysis. 

Table 7. Maceral point counting on Almond coals after hydrous pyrolysis. 

[ds, desmocollinite; tl, telocollinite~ Tv, total vitrinite; cu, cutinite; sp, sporinite; rs, resinite; Tl, total liptinite; mi, micrinite; rna, macrinite; fu, fusinite; sf, 

semifusinite;'Tin, total inertinite; ex, exsudatinite; St Mat, starting material; Ro(pct), mean vitrinite reflectance as a percentage] 

Sample ds tl Tv eu sp rs Tl mi ma fu sf Tin ex Ro 

(pet) (pet) (pet) (pet) (pet) (pet) (pet) (pet) (pet) (pet) (pet) (pet) (pet) (pet) 

Almond St Mat--- 71 5 76 8 2 II 3 4 2 3 13 0 0.45 

Almond 290 ------ 60 6 66 4 tr tr 5 4 3 2 15 24 6 0.95 

Almond 300 ------ 57 6 56 3 tr tr 4 6 3 18 28 5 0.99 

Almond 310 ------ 51 16 67 0 0 10 4 14 29 2 1.15 

Almond 320 ------ 50 26 76 0 0 0 0 6 3 2 12 23 2 1.35 

Almond 330 ------ 53 19 72 0 0 0 0 8 2 2 9 21 6 1.39 

Almond 340 ------ 19 35 0 0 0 0 0 6 2 4 23 35 11 1.50 

Almond 345 ------ 0 20 20 0 0 0 0 3 2 8 51 64 17 1.58 

Almond 350 ------ 0 15 15 0 0 0 0 5 2 10 57 65 12 1.65 

Almond 360 ------ 0 14 14 0 0 0 0 tr 2 13 61 77 II 1.71 
420 THE FUTURE OF ENERGY GASES 

100 

- 80 -(.) 

a. 

-s:::: 60 Q) 

-s:::: 

0 

(.) 

40 <1l 

... 

Q) 

(.) 

<1l 20 :2 

0 

290 300 310 320 330 340 

Temperature (°C) 

350 360 

_ ._Vitrinite - -EE-- Liptinite - ---- lnertinite-tl- Exsudatinite 

Figure 24. Maceral content after hydrous pyrolysis versus temperature of experiments. 

vitrinite reflectance data. The following is a description of 

the textural changes observed in Almond coals after hydrous pyrolysis at successively higher temperatures: 

I. Starting material: Almond coal from the surface 

shows a finely laminated desmocollinite groundmass with 

dispersed sporinite, cutinite, and inertinite macerals. 

Rmax=0.45 percent (fig. 25). 

2. 290°C: The desmocollinite groundmass loses its 

finely laminated texture and becomes more homogenous. 

Micrinite begins to appear, while the Iiptinite content is 

drastically reduced. The mean maximum reflectance on 

desmocollinite increases to Rmax=0.86 percent (fig. 26). 

3. 300°C: A porous texture begins to appear owing to 

oil generation and expulsion, and the micrinite continues to 

form from the liptinite macerals. The mean maximum reflectance on desmocollinite is Rmax=0.9 I percent (fig. 27). 

4. 31 0°C: The porous texture becomes predominant; 

many pores are developed near semifusinite macerals; 

Rmax= 1.22 percent (fig. 28). 

5. 330°C: The porous texture evolves to a vesicular 

texture in which the vesicles are filled with exsudatinite 

that shows a weak yellow fluorescence. This vesicular texture is present mostly on the semifusinite macerals, although it also appears on the vitrinite groundmass. 

Rmax= 1.39 percent (figs. 29, 30). 

6. 360°C: The vesicular texture is the predominant 

feature; it is developed mostly on semifusinite and fusinite 

macerals. The exsudatinite formed in the vesicles of the 

inertinite macerals during the pyrolysis shows a strong orange fluorescence (figs. 31, 32). Expulsion of oil from the 

exsudatinite vesicles occurs either by fracture of the vesicles or generation of increasing quantities of lighter aliphatic compounds, which at some point overcome the 

Figure 25. Photomicrograph of coal from an outcrop of the Almond Formation. Starting material for hydrous pyrolysis experiments. Finely laminated texture of desmocollinite (d) matrix with 

dispersed sporinite (sp) and cutinite (cu). Inertinite (in). Reflected 

white light. 

storage capacity of the vesicles causing fractures (figs. 33, 

34). The mean maximum reflectance is Rmax=l.70 percent; this is measured on telocollinite, since the desmocolIinite no longer has its original definitive characteristics. 

As opposed to the naturally matured samples, the 

solid-phase residue from hydrous pyrolysis experiments 

never reaches the stage of vitrinite-semifusinite rehomogenization that is observed in the naturally matured samples. 

This is generally observed in samples from deeper than 

14,000 ft present burial and is most likely due to the lack 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 421 

of high confining pressure in the hydrous pyrolysis experiments. This overburden pressure in nature acts to help 

fracture the vesicles and expel stored oil (exsudatinite). 

The hydrous pyrolysis experiments indicate that the 

generation and expulsion of liquid hydrocarbons occurs in 

two stages: (1) Oil is generated and expelled as liptinite 

macerals are transformed into micrinite, and (2) oil is expelled as the semifusinite vesicles, filled with exsudatinite, 

are fractured. These two processes represent primary miFigure 26. Photomicrograph of coal from the Almond Formation 

after hydrous pyrolysis at 290°C: Desmocollinite (d) loses its 

finely laminated texture. Micrinite (m) formed from sporinite 

(sp) macerals. Resinite (rs); inertinite (in). Reflected white light. 

Figure 27. Photomicrograph of coal from the Almond Formation 

after hydrous pyrolysis at 300°C: Beginning of formation of porous (p) texture due to oil expulsion. Micrinite (m), inertinite 

(in), vitrinite (v). Reflected white light. 

gration of oil from the coal source rock. As opposed to the 

naturally matured samples, the hydrous pyrolysis experiments show abundant exsudatinite at a vitrinite reflectance 

of 1.7 percent Rmax· This situation is not observed in the 

naturally matured samples, owing to the higher pressure 

experienced during burial that compresses the coals, expelling the exsudatinite. 

Figure 28. Photomicrograph of coal from the Almond Formation 

after hydrous pyrolysis at 3 J 0°C: Porous texture developed in 

vitrinite (v) matrix. Semifusinite (sf), pore (p). Reflected white 

light. 

Figure 29. Photomicrograph of coal from the Almond Formation 

after hydrous pyrolysis at 330°C: Vesicular texture on semifusinite (sf). Vesicles (vs) filled with exsudatinite (ex). Vitrinite (v). 

Reflected white light. 
422 THE FUTURE OF ENERGY GASES 

The correlation coefficient of vitrinite reflectance with 

temperature of the hydrous pyrolysis experiments is 0.99, 

indicating that R0 is a viable maturation parameter for this 

type of process, especially when reflectance is carefully 

measured on the vitrinite group (fig. 35). In this study, the 

measurements were taken on desmocollinite in the starting 

material and continued to be taken through the 31 0°C 

experiment; from the 320° through 360°C experiments, 

reflectances were taken on telocollinite because desmocollinite did not exhibit the original texture. We had difficulty 

Figure 30. Photomicrograph of same feature as figure 29 under 

reflected blue light showing fluorescence of exsudatinite (ex). 

Figure 31. Photomicrograph of coal from the Almond Formation 

after hydrous pyrolysis at 360°C: Vesicular texture on semifusinite (sf). Vesicles filled with exsudatinite (ex). Reflected white 

light. 

in differentiating between vitrinite and semifusinite in the 

350° and 360°C samples; nonetheless, the hydrous pyrolysis experiments allowed us to document that vitrinite reflectance increases with the maceral transformation that 

begins with desmocollinite and ends with semifusinite or 

homogeneous vitrinite. 

In summary, hydrous pyrolysis experiments on coal 

simulated the organic metamorphism that occurred during 

the natural burial of the coal. Both processes generated 

similar textural and maceral changes, including the generFigure 32. Photomicrograph of same feature as Figure 31 under 

reflected blue light showing strong fluorescence of exsudatinite 

(ex). 

Figure 33. Photomicrograph of coal from the Almond Formation 

after hydrous pyrolysis at 360°C: Expulsion of indigenous oil 

(ol) from vesicles filled with exsudatinite (ex). Vitrinite (v); 

semifusinite (sf). White reflected light. 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 423 

ation and expulsion of liquid and gaseous hydrocarbons. 

However, these hydrous pyrolysis experiments were not 

able to mimic the rehomogenization of the vitrinite-semifusinite matrix that indicates the onset of gas generation, 

probably owing to lack of high confining pressure in the 

experiments. 

Figure 34. Photomicrograph of same feature as figure 33 under 

reflected blue light showing fluorescence of the oil (ol) expelled 

from the vesicles filled with exsudatinite (ex). 

(.) 

0 

290 

300 -

310 -

OJ 320 - ..... 

::::J 

-~ 

..... 

OJ 

c.. 

E 

OJ 

I--

330 -

340 -

350 -

360 

0.4 

-

• 

I I I 

0.8 

I I 

-

• -

• -

• -

• -

• 

• -

I 1 I- I 

1.2 1.6 2 

Vitrinite reflectance ( R pet) 0 

Figure 35. Vitrinite reflectances versus temperature obtained 

for Almond Formation coal after hydrous pyrolysis. 

ORGANIC GEOCHEMISTRY 

The results of our organic geochemical analyses on 

the solid residue from the hydrous pyrolysis experiments 

(TOC, PI, GP and HI) are presented in table 8. 

Figure 36 shows expelled free oil recovered during 

each hydrous pyrolysis experiment as milligrams of oil per 

gram of coal. This is oil that had been generated and expelled from the coal during the course of the experiment 

and does not include stored bitumen (the material extractable by solvents but not expelled from the coals; for example, exsudatinite) which is adsorbed into the coal structure. 

The petrographic observations indicate that there is a great 

amount of bitumen stored in vesicles in the coal. Soxhlet 

extraction of bitumen in the coals after the experiments 

yielded up to 3.97 weight percent bitumen; this corroborates the organic petrographic observations (noted above) 

of large volumes of oil remaining in the coal after the generation and expulsion of the free-oil phase. A similar observation was made by Teerman and Hwang (1991) in their 

hydrous pyrolysis experiment on coal. Our hydrous pyrolysis experiments show expulsion of liquids and storage of 

abundant bitumen ( exsudatinite) throughout the range of 

experimental conditions. This situation is not observed in 

the naturally matured samples at depths greater than 12,000 

ft, possibly because in natural samples the higher pressure 

experienced during burial compresses the coals, expelling 

the liquid hydrocarbons. 

290 - I I I I 

300 - • -

(.) 310 - • -

0 

OJ 320 - • - ..... 

::::J 

-~ 

..... 330 - • - OJ 

c.. 

E 

Q) 340 1- • - I--

• 

350 1- • -

360 I I I 1- I 

0 5 1 0 1 5 20 25 30 

mg oil per gram coal 

Figure 36. Recovered oil (mg oil/g coal) versus experimental 

temperature for Almond Formation coal hydrous pyrolysis 

experiments. 
424 THE FUTURE OF ENERGY GASES 

Table 8. Results of anhydrous pyrolysis and total organic carbon (TOC) analyses on Almond coals after hydrous pyrolysis. 

[St Mat, staning material; HC, hydrocarbon; Temp, temperature (

0

C); S I =mg HC/g sample, hydrocarbons present in the sample; S2=mg HC/g sample, 

hydrocarbons generated during pyrolysis; T max• maximum temperature of hydrocarbon generation; C(pct), inorganic carbon in percent; IC(pct), inorganic 

carbon in percent; TC(pct), total carbon in percent; TOC(pct), total organic carbon as a percentage; PI=SII(Sl+S2), production index; HI=S2trOC, hydrogen 

index; GP=S I +S2, genetic potential; 01/Ca=mg Oil/g Coal, oil generated during hydrous pyrolysis] 

Sample Temp SI S2 Tmax 

Almond St Mat----- 80 0.26 99.79 423 

Almond St Mat----- 80 0.62 107.41 4]] 

Almond 290--------- 290 5.52 97.77 433 

Almond 300--------- 300 8.13 110.00 437 

Almond 310--------- 310 11.39 100.50 440 

Almond 320--------- 320 13.20 93.34 442 

Almond 330--------- 330 14.20 82.15 444 

Almond 340--------- 340 16.55 77.02 444 

Almond 345--------- 345 18.53 65.97 447 

Almond 350--------- 350 17.04 59.76 452 

Almond 360--------- 360 18.83 58.71 448 

At maximum generation, Almond coals expel 27 mg 

oil/g coal; this indicates that this coal has excellent oil 

generative capacity. The steep drop in oil recovery seen in 

experiments at temperatures above 345°C suggests that oil 

is being thermally cracked to gas at these temperatures. 

This is very similar to the trend noted by Teerman and 

Hwang (1991) in their experiments on Tertiary lignite. 

Figure 37 shows the production index (PI) versus 

temperature for Almond coals after the hydrous pyrolysis 

experiments. The standard interpretation of figure 37 

would be that the coal is in the conventional liquid oil 

window in the 310° to 360°C experiments. However, figure 36 clearly shows generation and expulsion of liquid 

hydrocarbons in all the experiments. Therefore, the conventional interpretation of anhydrous pyrolysis results 

may not be valid for these coals. Comparing figures 20 

and 37 demonstrates that on the basis of PI, samples from 

the well cores are very similar to samples artificially matured by hydrous pyrolysis; this is corroborated by the 

NMR data discussed below and the coal petrography presented above. 

Figure 38 shows the hydrogen index (HI) and genetic 

potential (GP) data for the hydrous pyrolysis experiments. 

As expected, there is a general decrease in HI and GP as 

temperature increases and the coal, as it matures, generates and expels both liquid and gaseous hydrocarbons. 

Solid-state 13C NMR techniques employing cross polarization with magic-angle spinning (see discussions in 

Miknis, Sullivan, and others,1981, and Miknis, Jiao, and 

others, 1993) were used to determine the changes in the 

carbon structure of the coals resulting from hydrous pyrolysis; the results are shown in figure 39. 

TC 

(pet) 

70.30 

68.90 

77.00 

77.60 

78.60 

76.40 

78.70 

81.10 

80.50 

80.30 

81.40 

IC TOC 

(pet) (pet) PI HI GP 01/Ca 

0.00 70.30 0.00 142 100 0.01 

0.00 68.90 0.01 156 108 0.01 

0.02 76.98 0.05 127 103 4.80 

0.02 77.58 O.D7 142 liS 7.20 

0.02 78.58 0.10 128 112 11.95 

0.04 76.36 0.12 122 107 14.60 

0.03 78.67 0.15 104 96 18.95 

0.01 81.09 0.18 95 94 23.35 

0.01 80.49 0.22 82 85 26.65 

0.03 80.27 0.22 74 77 25.90 

O.D2 81.38 0.24 72 78 21.05 

290 

300 • 

c; 310 0 • 

(I) 320 • .... 

::::J 

-

«S 

G> 330 

c.. • 

E 

(I) 

1-- 340 • 

• 

350 • 3Go~~--~--~~~~~ 

0 0.05 0.1 0.15 0.2 0.25 0.3 

Production index 

Figure 37. Production index versus temperature for Almond 

Formation coal after hydrous pyrolysis experiments. 

The NMR spectra for Almond coals in the hydrous 

pyrolysis experiments clearly show a loss of aliphatic-carbons relative to aromatic-hydrocarbons during hydrous pyrolysis. These aliphatic-carbon structures are hydrogen rich 

and largely are responsible for the liquid and gaseous hydrocarbons generated during hydrous pyrolysis. These data also 

indicate that most of the oil is generated in the temperature 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 425 

range of 290° to 330°C, as evidenced by the greater reduction in aliphatic-hydrocarbon relative to that of the starting 

materials in this temperature range. This is somewhat at 

odds with the PI data shown in figure 37, but supports the 

observed amount of oil generated during the experiment 

(fig. 36) and the petrographic observations noted above. The 

aliphatic-carbon remaining in the 360°C hydrous pyrolysis 

residue appears to consist mostly of methyl groups attached 

to aromatic rings, as evidenced by the characteristic peak at 

-14 to 17 ppm (Miknis, Jiao, and others, 1993). 

The aromatic-carbon band shows narrowing peak 

width with increasing temperature. This narrowing is indicative of an increase in the size of the aromatic rings, 

or of less substitution on the aromatic rings. During hydrous pyrolysis, cleavage of substituents bridging aromatics could lead to condensation reactions that yield larger 

aromatic rings (Miknis, Jiao, and others, 1993). 

(..) 

0 

Q) 

..... 

::s 

-ca 

..... 

Q) 

c.. 

E 

Q) 

1-

60 

290 

300 

310 

320 

330 

340 

350 

360 

70 

80 

80 

Hydrogen index 

100 120 140 160 

·' ' 

~ 

Hydrogen index I 

~· d 

I 

I 

• d 

/ 

.. / 

~ ~ 

I 

,; I 

. ., ~enetic potential 

•JJ 

90 100 110 120 

Genetic potential 

Figure 38. Hydrogen index and genetic potential versus temperature of experiment for Almond Formation coal after hydrous pyrolysis experiments. 

The NMR spectra also show a resonance band at -175 

ppm, attributable to carbons in a carboxylate functionality. 

During heating, decarboxylation reactions of these functional groups liberate C02

. The NMR spectra in figure 39 

() -

0 

-

Q) 

...... 

::J 

...... 

ctl 

...... 

Q) 

0.. 

E 

Q) 

1-

290 

300 

310 

320 

330 

340 

345 

360 

360 

(ppm) 

NMRSpectra 

Figure 39. Nuclear Magnetic Resonance (NMR) spectra of 

the solid phase Almond Formation coal residue of the hydrous pyrolysis experiments. 
426 THE FUTURE OF ENERGY GASES 

show that this carbon functionality disappears above a 

temperature of 300°C, illustrating a rapid evolution of 

C02 during the heating of subbituminous coals. 

Comparing figures 17 and 39 demonstrates that very 

similar trends of change in molecular structure with depth 

occur in the naturally matured well-core samples and the 

artificially matured samples. The coal core samples from 

the depth interval 4,560 ft to 14,286 ft (fig. 17) have NMR 

spectra that are very similar to those of the artificially matured samples shown in figure 39. This correlation is similar to the organic petrographic findings above and also 

indicates that hydrous pyrolysis simulates (at the molecular 

level) the natural maturation of these coals fairly well. 

MacGowan, Britton, and others (1992) compared NMR 

spectra of the Almond Formation coal residues after hydrous pyrolysis experiments with spectra of the same coal 

residue after soxhlet extraction. The results show a significant residue of generated oil that remains trapped in the 

coals during hydrous pyrolysis experiments. Thus, coals are 

indeed an important source of liquid hydrocarbons, as 

shown by comparing these volumes of expelled and stored 

oil with the genetic potential of typical shale (see Tissot and 

Welte, 1984 ). This is corroborated by the organic petrographic data above and by the findings of Teerman and 

Hwang (1991), Mukhopadhyay and others (1991), and 

Khavari Khorasani and Michelsen (1991). 

Headspace gas chemistry was also monitored during 

the hydrous pyrolysis experiments. Predominantly, C02 is 

released as the coal is artificially matured (fig. 40), and 

methane is the second most abundant gas released. Figure 

41 shows the distribution of the C 1-C6 hydrocarbon gases 

versus experimental temperature. Note that although the 

total amount of gas increases, the relative percentages of 

80 I 

..,. 70 r- & & :I: & 

u If & 

'0 60 1- C02 c 

ctl 

"' 50 - 0 

<-> 

0 40 -

Q) 

Cl 30 r- ctl 

'E 

Q) 20 - CH ~ 4 Q) 

c.. \K .1 0 1- D 

[] D 0 

0 1 I 

280 300 320 

the various gases remain constant, even after oil begins to 

crack to gas above about 345°C. On the basis of the gases 

recovered during hydrous pyrolysis it was determined that 

Almond coals are capable of expelling up to 404 ft3 of 

methane per metric ton (table 9); this value does not include the hydrocarbons stored in the pores and vesicles of 

coals, hydrocarbons which account for 435 ft3 of gas per 

metric ton of coal. It is important to emphasize that most 

of the naturally matured samples and all of the artificially 

matured samples do not reach the gas generation zone 

(R0 .. 2.0 percent), where the volume of gas generated 

increases by a factor of two according to Meissner (1989). 

A comparison between the methane generated during our 

hydrous pyrolysis experiments and the values given by 

Meissner ( 1989) indicates that most of the Almond Formation coal in the GGRB does not reach the gas-generation 

window, except for the areas of deepest burial at the center of the Washakie Basin. 

Coal in many basins worldwide has been shown to be 

a prolific producer of commercial quantities of oil; for example, the Gippsland Basin (Australia), the Kutai Basin 

(Borneo), the Ardjuna Basin (Java), and the Sand Wash 

Basin (United States) (Teerman and Hwang, 1991; Hunt, 

1991). Because the sieve-like molecular structure of coal 

adsorbs most of the generated oil, only coals that are rich 

in liptinite macerals generally generate sufficient oil for 

any liquid petrol'eum to be released (Snowdon, 1991 ). 

However, even vitrinite-rich coals can be producers of 

commercial quantities of oil if the vitrinite macerals are a 

hydrogen-rich variety, such as desmocollinite (Snowdon, 

1991; Mukhopadhyay and others, 1991; Teerman and 

Hwang, 1991). Oil expelled from such coals has a composition similar to oil from noncoal terrestrial kerogens 

I 

& - & 

& -

& 

& -

-

-

D -

D D D 

D -

I I 

340 360 380 

Temperature (oC) 

Figure 40. Almond Formation coal hydrous pyrolysis experiment percent C02 and CH4 

versus temperature. 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 427 

-

u "' 

u~ 

E 

0.. 

0.. 

1000000 

100000 -

10000 -

1000 -

0 

• 

0 

+ 

I 

0 

• 

0 

+ 

I 

• • • 

0 

0 

0 • • • 

0 

0 0 

+ + 

+ 

6 

I I 

• • c1 

• • c2 0 

0 0 0 

• • • c3 • 

-

0 c4 

0 0 0 -

+ cs 

+ + + 

- 6 6 c6 6 

6 6 

I 4' I 

6 6 

100'~------L-~------~------~------J_------~ 

280 300 320 340 360 380 

Temperature (oC) 

Figure 41. Almond Formation coal hydrous pyrolysis experiment: headspace hydrocarbon gas 

composition versus temperature. 

Table 9. Volume of oil and gas expelled during hydrous 

pyrolysis experiments. 

Sample Temp. Expelled oil Expelled melhane 

('C) (barrelsffon coal) (cubic ft!fon coal) 

Almond 290---- 290 0.03 30.50 

Almond 300---- 300 0.05 45.70 

Almond 310---- 310 0.08 65.00 

Almond 320---- 320 0.09 95.40 

Almond 330---- 330 0.12 135.00 

Almond 340---- 340 0.15 217.00 

Almond 345---- 345 0.17 231.00 

Almond 350---- 350 0.17 277.00 

Almond 360---- 360 0.14 404.00 

(Teerman and Hwang, 1991). As noted above, the coal in 

the present study ranges in composition from 40 to 90 percent vitrinite and contains as much as 78 percent desmocollinite. This composition, coupled with the evidence of 

oil and gas generated and expelled during the hydrous pyrolysis experiments, suggests that the Almond Formation 

coal may be an important source of petroleum hydrocarbons in the GGRB. Some fractured coal beds of the AI-· 

mond Formation act as aquifers in the GGRB (Heasler and 

Surdam, 1992); thus, most of the trapped oil generated in 

these coals would have been expelled by the hydrologic 

flux into the enclosing sandstones. It is important to recall 

that although the Almond Formation coal is an important 

source for both liquid and gaseous hydrocarbons, most of 

these hydrocarbons remain stored in vesicles and pores in 

the coals. On the other hand, the generation and expulsion 

of methane directly from Almond coals take place only in 

the deepest area of the Washakie Basin at a depth of about 

18,000 feet. However, as discussed in the following section, thermal degradation of oil and liptinite macerals generates important volumes of gases. 

GEOCHEMICAL MODELING 

Geochemical maturation modeling of Almond coals explains the origin and occurrence of oil and gas accumulations in the GGRB. Two parameters are required for this 

modeling: (1) time-temperature profiles derived from burial 

histories and (2) the kinetic data for the coal-to-oil-and-gas 

reactions derived from the hydrous pyrolysis experiments. 

BURIAL HISTORY 

Two contrasting burial reconstructions (constructed 

using the methodology summarized in Surdam and others, 

1989), one at the center of the Washakie Basin and the 

other in the area of the Rock Springs Uplift, were used to 

model the maturation of the Almond Formation coal and 

the generation of liquid and gaseous hydrocarbons. The 

first reconstruction was based on the Adobe Town Unit No. 

1 well, which reaches the Almond Formation at 17,059 ft 

depth and is located in the south Washakie Basin (Sec. 20, 

T. 15 N., R. 97 W.). Figure 42 shows the burial history 

diagram of this well, characterized by rapid burial between 

70 and 45 Ma, followed by moderate burial until 10 Ma. 

From 10 Ma to the present there has been uplift of 2,000 ft. 

The burial history reconstruction in the proximity of 

the Rock Springs Uplift was derived from the Fred Federal 
428 THE FUTURE OF ENERGY GASES 

No. I well, located on the east flank of the Rock Springs 

Uplift (Sec. 30, T. 17 N., R. 99 W.). The burial history in 

this area is characterized by continuous burial between 70 

and 40 Ma, followed by continuous uplift of approximately 

6,000 ft (fig. 43). 

The thickness of erosion at the center of the Washakie 

Basin and at the Rock Springs area was calculated using 

the vitrinite reflectance map of Pawlewicz and others 

(1986); this map presents depth of isoreflectance contours 

at R0 =0.8 percent. From the slope of the isoreflectance 

contours, the thickness of erosion or uplift was calculated 

for each area using the linear regression given by 

Pawlewicz and others (1986). 

0 

1000 

2000 

.§_ 

..c: 3000 c. 

Cl) 

c 4000 

5000 

6000 

70 60 50 

In constructing these two burial history diagrams, decompaction corrections were made for each lithology type, 

following the methodology of Sclater and Christie (1980). 

These corrections, as well as the amount of erosion, are 

essential in calculating time-temperature profiles through 

time during burial. 

TIME-TEMPERATURE PROFILES 

Time-temperature profiles (TIP) were calculated on 

the basis of steady-state heat flow, using the one-dimensional Fourier heat-flow equation. Measurements of heat 

Washakie Format1on 

Green River Format1on 

40 30 20 10 0 

Time (Ma) 

Figure 42. Burial history diagram for the center of the Washakie Basin. Derived 

from the Adobe Town No.I well. 

0 

1000 

2000 

E 

3000 ..r::: 

c.. Lance Formation Q) 

c 4000 Lewis Shale 

5000 Almond Formation 

6000 

70 60 50 40 30 20 10 0 

Time (Ma) 

Figure 43. Burial history diagram for the flank of the Washakie Basin in the area of the 

Rock Springs Uplift. Derived from the Fred Federal No.I well. 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 429 

flow in the GGRB and the Uinta Basin range from 45 to 

67 milliwatts per square meter (mW/m2) (Brigaud and 

others, 1990; Heasler, 1985). The geologic map of Wyoming (Love and Christiansen, 1985) shows volcanic and 

intrusive rocks of early Tertiary age as well as small Quaternary volcanic necks in the northern area of the Rock 

Springs Uplift; these observations may explain variations 

in heat flow throughout the region. Consequently, heat 

flow for our model was considered to decrease gradually 

from the Late Cretaceous until the present. The heat flow 

in the Washakie Basin was estimated to have beeri 67 

mW/m2 during the late Cretaceous and Paleocene, 65 

mW/m2 from the Eocene until the middle Miocene, and to 

have gradually decreased from 65 to 53 mW/m2 from the 

late Miocene until the present. The matrix thermal conductivity for each formation in the Washakie Basin (table 10) 

was estimated following the methodology of Brigaud and 

others ( 1990). The goal of the thermal modeling was to 

calculate formation temperature through time, and to obtain similar values to the present-day bottom-hole temperature of the wells from which the burial histories were 

reconstructed. Figures 44 and 45 illustrate the time-temperature profiles for the two burial histories (figs. 42, 43, 

respectively) and show the differences in the thermal evolution of the shallowly buried sediments on the flank of 

the Washakie Basin and of the more deeply buried sediments in the center of the basin. 

Table 10. Matrix thermal conductivities used in the 

thermal modeling of formations in the Washakie 

Basin. 

Formation 

Washakie Formation--------

Green River Formation ----

Wasatch Formation ---------

Fort Union Formation------

Fox Hill Sandstone ---------

Lance Formation ------------

Lewis Shale------------------

Almond Formation----------

Matrix thermal conductivity 

(mW/m2) 

3.50 

3.50 

3.50 

2.50 

2.50 

2.50 

2.50 

3.00 

GEOCHEMICAL MODELING RESULTS 

The mass of expelled oil recovered during the hydrous 

pyrolysis experiments on Almond coals, in conjunction 

with petrographic observations on the maceral transformations during these experiments, allowed us to determine the 

activation energy (Ea) and frequency factor (A0 ) values for 

the Ahrrenius equation. These values were obtained following the methodology discussed by Lewan (1985) and 

Comer (1992). However, we made further use of the hydrous pyrolysis experiments to determine not only the kinetic values for the oil generation but also the kinetic 

values of the thermal degradation of oil and kerogen to 

gas. Further details of this methodology are discussed by 

MacGowan, Garcia-Gonzalez, and others (in press). 

The kinetic parameters used in calculating reaction 

transformation ratios (TR; as discussed by Tissot and 

Welte, 1984) are essential for the geochemical modeling 

u 50 0 

Q) 

.... 

::I 

-; 1 0 0 .... 

Q) 

a. 

E 

Q) 

1- 150 

2 0 0 L---L---L---L--_L___l.___.J...._____I 

70 60 50 40 30 20 10 0 

Time (Ma) 

Figure 44. Time-temperature profile for the center of the 

Washakie Basin. Derived from the Adobe Town No.1 well. 

0 

40 

(.) 

0 

Cl> 80 .... 

::J 

~ 

~ 120 

E 

Cl> 

1-

160 

200 ~--~--~--~--J---~--~--~ 

70 60 50 40 30 20 1 0 0 

Time (Ma) 

Figure 45. Time-temperature profile for the flank of the Washakie Basin in the area of the Rock Springs Uplift. Derived from the 

Fred Federal No.I well. 
430 THE FUTURE OF ENERGY GASES 

of oil generation and destruction, gas generation, and organic-inorganic interactions during progressive diagenesis 

in the Mesaverde Group. 

Although occasionally criticized as not representative 

of geologic processes (Snowdon, 1979; Saxby, 1982), detailed chemical modeling of geochemical reactions has recently demonstrated that data from high-temperature 

experiments of short duration are applicable to models of 

lower temperature reactions occurring over geologic time 

(Freund, 1992). The geochemical calculations assume firstorder rate-law kinetics, but it is likely that the processes 

by which oil is generated from the kerogen and expelled 

to the liquid phase proceed by several, serial chemical reactions of higher order, as well as by physical, nonchemical processes (Price, 1985). However, it has been shown 

that these reactions and processes can be fairly well approximated over geological time in geochemical models 

by assuming first-order reaction-rate laws (see discussion 

in Surdam and others, 1989); for this reason we refer to 

these as "pseudo kinetics." 

Figure 46 shows an Ahrrenius-type plot for the generation of oil from kerogen during the hydrous pyrolysis of 

Almond coals. The activation energy Ea for this process 

was determined to be 31.57 kcal/mol with a frequency factor A0 of 1.544xl0 16Jmillion years (the correlation coefficient for the regression is 0.996). Figure 47 shows an 

Ahrrenius-type plot for the generation of gas from the 

thermal degradation of oil and kerogen during the hydrous 

pyrolysis of Almond coals. The activation energy for this 

process was determined to be 37.80 kcal/mol with a frequency factor of 4.232x1017/million years (the regression 

correlation coefficient is 0.998). 

The kinetic parameters derived from the experiments 

were used in conjunction with the time-temperature profiles derived from the burial history models to calculate 

3.4 

3.2 E a = 31.57 Kcallmole 

3 A0 = 1.5444 X 1 o 1 6 I million years 

-"' 2.8 • c: 2.6 ...J 

•• 

2.4 

2.2 

2 

• 1.8 

1.68 1.7 1.72 1.74 1.76 1.78 

1000/Temperature (°K) 

Figure 46. Ahrrenius-type plot for oil generation during hydrous 

pyrolysis of Almond Formation Coal. Lnk=LnA-E,JRT; k, rate 

constant; A, frequency factor; E3 , activation energy; R, gas constant; T, absolute temperature in Kelvin (K). 

transformation ratios for reaction progress, using the methodology discussed by Tis sot and Welte (1984 ). Transformation ratios reflect the reaction progress at any step in 

time in the burial history of the sedimentary unit being 

modeled.· Traditional interpretation of oil generation transformation ratios holds that the main phase of liquid petroleum generation occurs between transformation ratios of 

0.1 and 0.4 (Tissot and Welte, 1984 ). However, in our experiments, actual kinetic parameters were derived for the 

thermal cracking of oil and kerogen to gas, allowing the 

kinetic calculation of the longevity (length of time liquid 

petroleum remains stable before thermally cracking to gas) 

of the oil in the reservoir. In practice, when the transformation ratio calculated for the thermal cracking of oil is subtracted from the transformation ratio for the generation of 

oil, the difference yields the relative fraction of petroleum 

remaining after thermal degradation of the liquid petroleum or the cracking of oil to gas reaction at each time step 

in the model. For example, a relative fraction of 1.0 means 

that 100 percent of the oil which the source rock is capable 

of generating remains; a relative fraction of 0.5 means that 

50 percent of the oil that the source rock is capable of 

generating remains. Figures 48 and 49 show the reaction 

progress (transformation ratio) of the generation of oil, the 

generation of gas from the thermal cracking of both oil and 

kerogen, and the relative fraction of oil remaining at each 

model time step versus time for both the model of the center of the Washakie Basin and the model of the flank of the 

basin. Figure 48 shows that the main phase of oil generation in the basin's center is calculated to have been between 60 and 50 Ma, and that thermal destruction of the oil 

becomes important from about 40 Ma to the present (0 

Ma); at present, less than 5 percent of the oil that the 

7.5 

7.4 

Ea = 37.8 Kca I mole 

7.3 

A0 = 4.232 X 1017 I million years 

-"' 7.2 

c: 

...J 7.1 

• 

7 

6.9 

6.8 

6.7 

1.55 1.57 1.59 1.61 1.63 1.65 

1000/Temperature (°K) 

Figure 47. Ahrrenius-type plot for gas generation from oil degradation during hydrous pyrolysis of Almond Formation coal. 

Lnk=LnA-E,JRT; k, rate constant; A, frequency factor; E3 , activation energy; R, gas constant; T, absolute temperature in Kelvin 

(K). 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 

VOLUME OF HYDROCARBONS 

GENERATED 

431 

source rock is capable of generating is still thermally stable 

by our kinetic calculations. Thus, in the deep of the center 

of the Washakie Basin, one would primarily expect gas 

reservoirs with little oil present. On the other hand, on the 

flank of the Washakie Basin (fig. 49), the main phase of oil 

generation does not occur until about 50 to 40 Ma, and the 

thermal cracking of oil to gas reaction does not become 

important at all. Thus, in reservoirs on the basin's flank, 

one would primarily expect oil reservoirs. 

An approximate calculation of the volume of oil and 

gas generated by the Upper Cretaceous coals can be made, 

based on the coal resources in the Upper Cretaceous Mesaverde Group in the GGRB and the yield of oil and gas 

volumes obtained from Almond coals during hydrous pyrolysis experiments. 

1.0 

0 0.8 

~ 

c: 0.6 0 

-;;; 

E 

~ 

0 0.4 

u; 

c: 

~ "' 0.2 

0.0 

10 60 

·····•·•·•.•.• .... ............ . 

.... .. .... ..·· 

.·· ~-.. .. . . .. · .... 

.. ·· '· .. ,·· ·· ..... . .. ....... ······ .•. : .... : • ..

················· 

: • ... 

.... ··' ········-···-·····-····· 

50 40 30 20 10 0 

Time (Ma) 

Oil generation Gas generated from oil 

Fraction of oil remaining 

Figure 48. Reaction progress (transformation ratio) of the generation of oil, the 

generation of gas from thermal cracking of oil and the relative fraction of oil 

remaining versus time for the center of the Washakie Basin. 

1.0 

0 0.8 

~ 

c: 0.6 0 

-;;; 

E 0.4 0 

u; 

c: 

~ "' 0.2 

0.0 

10 60 50 

Oil generation 

.. · 

·······-· •••••••···· I ••••••• I ••••• o•l 

.. 

. ·········································•····· 

40 30 20 10 0 

Time (Ma) 

Gas generated from oil 

Fraction of oil remaining 

Figure 49. Reaction progress (transformation ratio) of the generation of oil, the 

generation of gas from thermal cracking of oil and the relative fraction of oil 

remaining versus time for the flank of the Washakie Basin. 
432 THE FUTURE OF ENERGY GASES 

Tyler and others (1992) reported 302 billion short tons 

of subbituminous coals in the GGRB in the Upper Cretaceous coaly section. In calculating the volume of coals at 

ranks higher than 0.9 percent vitrinite reflectance, we delineated the areal extent of the Almond Formation and Mesaverde Group at depths equal to or greater than 8,000 ft, 

depths which correspond to the rank (R0=0.85 percent) 

where the threshold of the hydrocarbon generation begins 

(according to the hydrous pyrolysis experiments). In the 

same way, the areal extent of the gas generation zone was 

delineated using the 12,000 ft isodepth contour, which is 

equivalent to a vitrinite reflectance of 1.6 percent. Figure 50 

shows the areal extent of the 8,000 and 12,000 ft isodepth 

contours for the Upper Cretaceous Mesaverde Group. 

To estimate the average thickness of the cumulative 

coal beds in the Upper Cretaceous section, the entire volume of the coals (calculated density range of 1.4 to 1.5 

g/cm3) was divided by the area of the GGRB. The result 

obtained is 13 ft average thickness. Table II gives the 

volume of liquid and gaseous hydrocarbons at standard 

temperature and pressure conditions (temperature=25°C, 

pressure=} atm) generated by the Upper Cretaceous coals 

in the GGRB. They are divided into the following categories: (1) expelled gas, (2) expelled oil, (3) stored hydrocarbons (calculated from the S I peak of the anhydrous 

pyrolysis data in table 6), and (4) total volume of oil and 

gas generated in the GGRB. 

On the basis of the data presented above, the Upper 

Cretaceous coals in the GGRB have expelled 18.5 billion 

barrels of oil (Bbo) and 37.3 trillion cubic feet (Tcf) of 

gas. The volume of hydrocarbons stored in the coal beds 

is 5.7 Bbo and 29 Tcf of gas. The figures indicate that this 

basin has great potential to contain important commercial 

accumulations of gas and liquid petroleum. 

SUMMARY AND CONCLUSIONS 

Petrologic and organic geochemical characterization 

of the trend in the maturation path of Almond coals was 

performed using both naturally and artificially matured 

samples. The results of this research indicate that these 

coals have generated oil, which when buried deep 

(> 12,000 ft), has been thermally cracked to gas. Thermogenic gas generation from Almond coals only occurs 

at the deepest burial depth in the center of the GGRB. 

This represents a new interpretation of the origin of gas 

in the GGRB and may set new goals in the exploration 

for hydrocarbons. Also the great potential of Almond 

coals to generate commercial accumulations of oil is underscored by this research. 

The natural maturation of Almond coals and the artificial maturation by hydrous pyrolysis of Almond coals 

follow parallel trends. They show similar textural evolution during maturation, characterized by the initial loss of 

the finely laminated texture on desmocollinite, followed 

by the appearance of a porous texture that later evolves to 

a vesicular texture owing to the generation in increasing 

quantities of petroleum-like compounds. With greater 

depth, (deeper than 12,000 ft) the vesicular texture decreases by rehomogenization of the vitrinite-semifusinite 

matrix owing to the expulsion of exsudatinite; this stage 

indicates the onset of the gas-generation zone. The maceral transformations start with the transformation of 

liptinite into micrinite. In the same way, desmocollinite 

loses its original textural characteristics, changing to telocollinite and then to semifusinite and fusinite; In a parallel process, exsudatinite is initially generated and later 

thermally degraded to petroleum and gas. 

The- hydrous pyrolysis experiments produced artificially matured coals that are similar in molecular structure (as 

elucidated by NMR spectra) and are petrographically similar to the naturally matured samples. The maturation trend 

with temperature observed in the hydrous pyrolysis experiments is also geochemically similar to the maturation 

trend with burial in the well samples. 

Primary migration of oil occurs as the generation of 

a sufficient volume of exsudatinite fractures the vitrinitesemifusinite vesicles, interconnecting vesicles, and pores 

through microfracturing that creates an effective porosity 

that allows primary migration (Garcia-Gonzalez and others, in press). Additionally, good coalbed reservoirs 

should be found where the coal strata are highly fractured, allowing the oil to migrate. Some coalbeds in the 

GGRB may act as aquifers (Heasler and Surdam, 1992) 

and in such cases liquid petroleum trapped in the fractured coal would be expelled by the hydrologic flux. 

Although these studies indicate that Almond coals 

generate appreciable volumes of liquids and gaseous hydrocarbons, the effectiveness of hydrocarbon expulsion 

may be low because most of the hydrocarbons remain 

stored in vesicles. Therefore, the mechanism required for 

hydrocarbon expulsion to occur is vesicle fracturing; in 

the case of the naturally matured samples in this study, 

fracturing may be caused by abnormal pressure. This 

pressure can be achieved by burial and thermal cracking 

of the exsudatinite to gas; both mechanisms can fracture 

the vesicles, allowing a more effective expulsion of the 

hydrocarbons from the coalbed. 

The petrographic observations indicate that oil is 

generated but not effectively expelled in the coal source 

rocks at current burial depth from the surface to about 

12,000 ft (Rmax between 0.45 and 0.95 percent). Below 

this depth (Rmax>0.95 percent), exsudatinite begins to 

crack to gas. This process fractures the vesicles, owing to 

the change in volume associated with the phase change, 

and results in a more effective expulsion of hydrocarbons 

from the coal. The hydrous pyrolysis experiments show 

that oil is actively generated and expelled in a vitrinite 

reflectance (Rmax) range of 0.8 percent to 1.7 percent. 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 433 

Vitrinite reflectance measurements (table 4) predict 

that late thermogenic gas from the conversion of kerogen 

directly to gas can only occur in the small area of the 

Washakie Basin where the Almond Formation is at 

18,000 ft or greater present burial depth (R0 >2.0 percent). Except for this area, Almond coals have not been 

buried deeply enough in the Washakie Basin to generate 

significant thermogenic gas from the coal. 

Kemmerer 0 

11 0° 109° 108° 

• I EXPLANATION 

CJ Basement rocks 

'/ 

I -' ~ \ 

,-- \..-'"'' 

, ,'-,":J!ND ' -

/ - 1RIVER ' 

~ UPLI,FT ~ ', 

/;--,-;1 I - ...- \ \ 

, ' I - ' f ...., 

-/' - ......... 

!_I, .... / ..... ,; ,I 

/ \- - \ 

&SSJ ~8.000 ft 

~ 12,000ft 

""-4....-. thrust fault 

o Lander 

' '-\ / I I 

/ - I 

:\". 

I 

ROCK l 

SPRINGS l 

.. TUPLIFT .··· . . . . : .. 

· ... · 

0 

I 

0 

MONTANA 

miles 

I I 11 I 

kilometers 

107° 

40 

60 

RAWLINS 

UPLIFT 

SIERRA 

MADRE 

UPLIFT 

43° 

42° 

41 ° 

Figure 50. Areal extension of oil and gas generation in the Greater Green River Basin. The 8,000 ft depth contour corresponds 

to a vitrinite reflectance of 0.8 percent. The 12,000 ft depth contour corresponds to a vitrinite reflectance of 1.5 percent. 
434 THE FUTURE OF ENERGY GASES 

Table 11. Volume of oil and gas generated (expelled and stored) by the Upper Cretaceous section coals in the Greater Green River 

Basin. 

[NA, not applicable; Bbo, billion barrels of oil; Tcf, trillion cubic feel] 

Coal rank Depth Coal resources Total expelled oil Total expelled gas Total stored oil Total stored gas 

Ro (pet) (ft) (Billion ton) (Bbo) 

0.8 to 1.3 2:8,000 47.60 7.14 

1.3 to 1.7 2:)2,000 66.80 11.30 

Total generation NA NA 18.44 

Chemical kinetic modeling of kerogen evolution on 

Almond coals, coupled with geochemical and petrographic studies based on hydrous pyrolysis experiments lead 

us to conclude that hydrous pyrolysis is a valid technique 

for the study of the natural thermal maturation of these 

coals. The hydrous pyrolysis experiments suggest that the 

Almond Formation coals may. be a viable source of liquid hydrocarbons in the GGRB (maximum yield in hydrous pyrolysis experiments was 0.17 barrels of expelled 

oil per metric ton of coal), as well as a prolific producer 

of natural gas (maximum yield in hydrous pyrolysis experiments was 404 ft3 of natural gas generated per metric 

ton of coal). In addition to the expelled hydrocarbons, 

the stored hydrocarbons account for 0.14 barrels of oil 

and 435 ft3 of gas per metric ton of coal. 

On the basis of our geochemical models, we conclude that at the center of the Washakie Basin gas was 

generated from the thermal cracking of the oil previously 

generated from Almond coals. We recognize, however, 

that the widespread occurrence of gas reservoirs in the 

GGRB makes it difficult to pinpoint the origin of a particular gas accumulation, because gases generated earlier 

from the Lower Cretaceous shale and coal sequences 

may have mixed with the gases generated in the Upper 

Cretaceous Almond Formation. 

The geochemical model also shows that on the basin 

flank near the Rock Springs Uplift little or no gas was 

generated from the thermal cracking of the oil; however, 

the oil found there may have originated from Almond coals. 

Figure 51 illustrates our summary of the maturation 

parameters discussed in previous sections and shows the 

depth range of the oil and gas windows for the Almond 

Formation in the center of the Washakie basin. Vitrinite 

reflectance and organic petrography observations allow definition of the oil generation window, including the main 

phase of oil generation and expulsion. Our vitrinite reflectance boundaries for the oil window are between 0.5 and 1. 7 

percent, values which differ from those reported by Tissot 

and Welte (1984; 0.5<R0 <1.3 percent). Tmax values obtained for the Almond Formation samples allowed determination of the oil and gas windows using the boundaries 

(Tel) (Bbo) (Tel) 

10.30 5.71 NA 

27.00 NA 29.00 

37.30 5.71 29.00 

defined by Espitalie and others (1985); however, T max values we determined for Almond coals place the boundary 

between the oil and gas windows at a shallower depth than 

our R0 and organic petrographic observations suggest. Aromaticity ratios from the NMR analyses place the boundary 

between the oil and gas windows at approximately the same 

depth that R0 and organic petrography indicate. In figure 51, 

the "present interpretation" column presents our summary 

interpretation of hydrocarbon generation, expulsion,, and reaction (oil to gas), and gas generation windows for the 

maturation of Almond coals at the center of the Washakie 

Basin. It is necessary to state again that the depths at which 

the boundaries of the oil and gas windows vary depending 

on the level of uplift at each locality in the GGRB. 

Our calculations indicate (see table II) that the 

Upper Cretaceous coals in the GGRB have generated 

24.1 Bbo of which 18.4 Bbo have been expelled from the 

coals. Similarly these coals have generated 66.3 Tcf of 

gas of which 37.3 Tcf have been expelled from the coals. 

These volumes of hydrocarbons that were potentially· 

generated and expelled by the Upper Cretaceous coals 

call attention to the tremendous potential for gas and oil 

accumulations in the GGRB. 

ACKNOWLEDGMENTS 

The authors wish to thank Dr. Steven Boese (Department of Geology and Geophysics, University of Wyoming) 

for his analytical help and Dr. Francis P. Miknis (Western 

Research Institute, University of Wyoming) for the NMR 

analyses. We would also like to acknowledge useful discussions with Douglas Britton and Dr. Thomas L. Dunn, Dr. 

Zun Sheng Jiao and Dr. Pegui Yin (Department of Geology 

and Geophysics, University of Wyoming). David Copeland 

(Department of Geology and Geophysics, University of 

Wyoming) greatly improved the manuscript with many 

suggestions. Thanks also to outside reviewers Dr. Jean 

Whelan and Dr. Lorraine Buxton Eglington (Woods Hole 

Oceanographic Institution) for their thoughtful input and 

suggestions that also improved this manuscript. 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 435 

Ro NMR 

(pet) 

Aromaticity 

ratio 

Organic 

petrography 

Present 

interpretation 

>. 

ro 

"'C 

I 

+-' 

c::: 

QJ 

(/) 

QJ 

.... 

a.. 

0 

4000 

8000 

12000 

16000 

20000 

<I) 

6 § 

N 

<I) 

Vl 

.<::: "' 

0. 

c 

·c;; 

:::;: 

0.90 

2.00 

c 

0 

-e 

"' u 

0 

-15 

>, 

..c ;: 

" 0 ·s -g c:r ·- :.J ;: 

410 

430 

468 

Vl u 0. '.;::i ::J 

"' 0 .<::: ~ 

.9- O'l 

roro 

~ c 0 0 

·;:; Vl u 

~] 

.., 

c 

2 

c 

0 u u 

-~ g. 

~e 

'" Ol ..... 

c c "' 0 

~ 't 0 c u-2 

0.6 

Immature 

stage; Relatively 

desmocollinite immature 

finely stage 

laminated 

Transition zone 

Liquid 

hydrocarbon 

generation 

and storage 

Transition zone Generation of 

exsudatinite 

0.75 

and formation 

of vesicles Liquid 

hydrocarbon 

to gas 

reaction 

and 

expulsion of 

hydrocarbons 

Rehomogeni- Transition zone 

zation of the 

vitrinitesemifusinite Kerogen to 

matrix gas reaction 

Figure 51. Summary of different maturation indicators for the Almond Formation in the center of the Washakie Basin, Greater Green 

River Basin, Wyoming. 

This research was supported by Gas Research Institute 

Contract No. 5091-221-2146 and U.S. Department of Energy Cooperative Agreement No.DE-FC21-86MCI1076. 

REFERENCES CITED 

American Society of Testing Materials, 1980, Preparing coal 

samples for microscopical analysis by reflected light: Philadelphia, American Society of Testing Materials, Standard D2797-72. 

Brigaud, F., Chapman, D.S., and Le Douaran, S., 1990, Estimating thermal conductivity in sedimentary basins using lithologic data and geophysical well logs: American Association 

of Petroleum Geologists Bulletin, v. 74, p. 1459-1477. 

Comer, J.B., 1992, Thermal alteration, in Droppo, R., ed., 

Geochemistry of organic matter in sediments and sedimentary rocks, SEPM Short Course 27, notes: Tulsa, Society 

of Economic Paleontologists and Mineralogists, p. 73-100. 

Espitalie, J., Deroo, G., and Marquis, F., 1985, La pyrolyse 

rock-eva! et ses applications, deuxieme partie: Revue de 

!'institute Franc;:ais du Petrole, v. 40, p. 755-784. 

---1986, La pyrolyse rock-eva! et ses applications, troiseme 

partie: Revue de I' institute Franc;:ais du Petrole, v. 41, p. 73-

89. 

Freund, H., 1992, Application of a detailed chemical kinetic model 

to kerogen maturation: Energy and Fuels, v. 6, p. 318-26. 

Garcia-Gonzalez, M., MacGowan, D.B., and Surdam, R.C., in 

press, Mechanisms of petroleum generation from coal, as evidenced from petrographic and geochemical studies; examples 

from Almond Formation coals in the Greater Green River 

Basin, Wyoming, in Andrews, S., and Strook, B., eds., Wyoming Geological Association 50th Anniversary Field Conference Guidebook: Wyoming Geological Association. 

Garcia-Gonzalez, M., and Surdam, R. C., 1992, Coal as a source 

of petroleum; a comparison between the petrology of the Mesaverde Group coals, in burial and hydrous pyrolysis, in 

Mullen, C., ed., Wyoming Geological Association 43d Field 

Conference Guidebook: Wyoming Geological Association, 

p.237-244. 

Heasler, H.P., 1985, Geothermal resources of Wyoming (map): 

Department of Geology and Geophysics, University of Wyoming, Laramie, scale 1:500,000. 

Heasler, H.P., and Surdam, R.C., 1992, Pressure compartments in 

the Mesaverde Formation of the Green River and Washakie 

Basins, as determined from drill stem test data, in C. Mullen, 

ed.,Wyoming Geological Society 43d Field Conference 

Guidebook, p. 207-220. 

Hunt, J.M., 1991, Generation of gas and oil from coal and other 

terrestrial organic matter: Organic Geochemistry, v. 17, 

p. 675-680. 
436 THE FUTURE OF ENERGY GASES 

Katz, P.A., Kelley, R.A., Royle, R.A., and Jorjorian, T., 1991, 

Hydrocarbon products of coals as revealed by pyrolysis-gas 

chromatography: Organic Geochemistry, v. 17, p. 711-722. 

Khavari Khorasani, G., and Michelsen, J.K., 1991, Geological and 

laboratory evidence for the early generation of large amounts 

of liquid hydrocarbons from subineritinite and subereous 

components: Organic Geochemistry, v. 17, p. 849-863. 

Law, B.E., 1984, Relationships of source rock, thermal maturity, 

and overpressuring to gas generation and occurrence in lowpermeability Upper Cretaceous and Lower Tertiary rocks, 

Greater Green River Basin, Wyoming, Colorado, and Utah, in 

Woodward, J., Meissner, F., and Clayton, J., eds., Hydrocarbon source rocks of the greater Rocky Mountain region: 

Rocky Mountain Association of Geologists, p. 469-490. 

Lewan, M.D., 1985, Evaluation of petroleum generation by hydrous pyrolysis experimentation: Philosophical Transactions 

of the Royal Society of London, series A, v. 315, p. 123-134. 

Lewan, M.D., Winters, J.C., and McDonald, J.H., 1979, Generation of oil-like pyrolysates from organic-rich shales: Science, 

v. 203, p. 57-59. 

Love, J.D., and Christiansen, A.C., 1985, Geologic Map of Wyoming, U.S. Geological Survey, scale l :50,000. 

MacGowan, D.B., Britton, D.R., Miknis, F.P., and Surdam, R.C., 

1992, Organic geochemistry and maturation trends of shales 

and coals, Almond Formation, Mesaverde Group, Greater 

Green River Basin, Wyoming; a comparison with laboratory 

maturation of Almond Coals by hydrous pyrolysis: in Mullen, 

C., ed., Wyoming Geological Association 43d Field Conference Guidebook, p. 221-235. 

MacGowan, D.B., Garcia-Gonzalez, M., Britton, D.R., and Surdam, R.C., in press, Timing of hydrocarbon generation, 

organic-inorganic diagenesis and the formation of abnormally pressured gas compartments in the Cretaceous of the 

Greater Green River Basin; a geochemical model, in Andrews, S., and Strook, B., eds.,Wyoming Geological Association, 50th Anniversary Field Conference Guidebook: 

Wyoming Geological Association. 

Meissner, F.F., 1989, Cretaceous and Lower Tertiary coals as 

sources for gas accumulations in the Rocky Mountain area, 

in Woodard, J., Meissner, F., and Clayton, J., eds., Hydrocarbon source rocks of the greater Rocky Mountain region, 

Rocky Mountain Association of Geologists, p. 401-431. 

Miknis, F.P., Jiao, Z.S., MacGowan, D.B., and Surdam, R.C., 

1993, NMR characterization of Mowry Formation shales: 

Organic Geochemistry, v. 20, p. 339-347. 

Miknis, F.P., Sullivan, M., Bartuska, V.J., and Maciel, G.E., 

1981, Cross-polarization magic angle spinning 13C NMR 

spectra of coals of varying rank: Organic Geochemistry, v. 3, 

p. 19-28 

Mukhopadhyay, P.K., Hatcher, P.G., and Calder, J.H., 1991, Hydrocarbon generation from deltaic and intermontane fluviodeltaic coal and coaly shale from the Tertiary of Texas 

and Carboniferous of Nova Scotia: Organic Geochemistry, 

v.17, p. 765-783. 

Pawlewicz, M.J., Kickus, M.K., Law, B.E., and Dickinson, 

W.W., 1986, Thermal maturity maps showing depth to 0.8 

percent vitrinite reflectance in the Greater Green River 

Basin, Wyoming, Colorado, and Utah: U.S. Geological Survey Miscellaneous Field Studies Map MF-1890. 

Price, L.C., 1985, Geologic time as a parameter in organic metamorphism and vitrinite reflectance as absolute paleo-geothermometer: Journal of Petroleum Geology, v. 6, p. 5-38. 

Roehler, H.W., 1988, The Pintail Coal Bed and Barrier Bar G; a 

model for coal of barrier bar-lagoon origin, Upper Cretaceous 

Almond Formation, Rock Springs Coal Field, Wyoming: U.S. 

Geological Survey Professional Paper 1398, 60 p. 

---1990, Stratigraphy of the Mesaverde Group in the central 

and eastern Greater Green River Basin, Wyoming, Colorado, 

and Utah: U.S. Geological Survey Professional Paper 1508, 

52 p. 

Saxby, J., 1982, A reassessment of the range of kerogen maturities in which hydrocarbons are generated: Journal of Petroleum Geology, v. 5, p. 117-128. 

Sclater, J.G., and Christie, P.A., 1980, Continental stretching; an 

explanation of the post-mid-Cretaceous subsidence of the 

central North Sea Basin: Journal of Geophysical Research, 

v. 85,p. 3711-3739. 

Snowdon, L.R., 1979, Errors in extrapolation of experimental 

kinetic parameters to organic geochemical systems: American Association of Petroleum Geologists Bulletin, v. 63, 

p.ll28-ll34. 

---1991, Oil from Type III organic matter: resinite revisited: 

Organic Geochemistry, v. 17, p. 743-747. 

Stach, E., Mackowsky, M.T.H., Teichmiiller, M., and others 

1982, Stach's textbook of Coal Petrology: Gebriider Borntraeger, 3d edition, 535 p. 

Surdam, R.C., Dunn, T.L., MacGowan, D.B., and Heasler, H.P., 

1989, Conceptual models for the prediction of porosity evolution with an example from the Frontier Sandstone, Bighorn Basin, Wyoming, in Coalson, E., Kaplan, S., Keighin, 

C., Oglesby, C., and Robinson, J ., eds., Rocky Mountain Association of Geologists Guidebook, p. 7-28. 

Teerman, S.C., and Hwang, R.J., 1991, Evaluation of the liquid 

hydrocarbon potential of coal by artificial maturation techniques: Organic Geochemistry, v. 17, p. 749-764. 

Tissot, B.P., Pelet, R., and Ungerer, P.H., 1987, Thermal history of 

sedimentary basins, maturation indices, and kinetics of oil 

and gas generation: American Association of Petroleum Geologists Bulletin, v. 71, p. 1445-1466. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and occurrence (2d ed.): New York, Springer Verlag, 699 p. 

Tyler, R., Ambrose, W.A., Scott, A.R., and Kaiser, W.R., 1992, 

Evaluation of the coal-bed methane potential in the Greater 

Green River, Piceance, Powder River and Raton basins, in 

Mullen, C., ed., Wyoming Geological Association 43d Field 

Conference Guidebook, p. 269-302. 

Wyoming Oil and Gas Conservation Commission, 1991, Wyoming oil and gas fields and units of production, 1991: Wyoming Oil and Gas Statistics, part 12, 87 p. 

Yin, P., Surdam, R.C., Boese, S.W., MacGowan, D.B., and Miknis, F.P., in press, Simulation of hydrocarbon source rock 

maturation by hydrous pyrolysis: in Andrews, S., and 

Strook, B., eds., Wyoming Geological Association 50th 

Field Conference Guidebook. 
COAL AS A SOURCE ROCK OF PETROLEUM AND GAS 437 

APPENDIX. KEY WORD DEFINITIONS. 

Aliphatic (alkane): A hydrocarbon with the molecular 

formula CnHZn+Z· It includes hydrogen-saturated, straightchain, branched-chain and cyclic hydrocarbons such as 

methane, ethane, propane and isobutane. 

Aromatic: Hydrocarbons containing one or more hydrogen-undersaturated rings. Monoaromatic compounds 

have the molecular formula CnHzn_6. Typical aromatic 

compounds are benzene, toluene, and xylenes. Polycyclic 

aromatic hydrocarbons contain several rings with two or 

more carbon atoms shared between rings. 

Coal maceral: Microscopically recognizable constituents of coal that can be differentiated by their morphology. 

Macerals are analogous to the minerals of inorganic rocks 

but differ in having less uniform chemical composition 

and physical properties. The carbon content of macerals 

increases with increasing temperature. The major maceral 

groups are vitrinite, liptinite (exinite), and inertinite. 

Desmocollinite (vitrinite B): Mixture of detritus of 

liptinite and inertinite macerals dispersed in gel. The earlier mixture of plant debris becomes homogenized by 

geochemical gelification. 

Exsudatinite: Secondary product of liptinite and huminite constituents of subbituminous and high-volatile bituminous coals; its origin is related to that of fluid petroleum. 

Fusinite: The richest maceral in carbon of all the constituents of coal, characterized by the strongest reflectance 

among coal macerals. Two types of fusinite are recognized-pyrofusinite and degradofusinite. 

Genetic Potential (GP): The total potential, as determined by anhydrous pyrolysis (mg hydrocarbon/gram 

source rock) that the source rock is capable of generating; 

that is, generated plus stored hydrocarbons; GP=S I +S2 

(anhydrous pyrolysis peaks; Sl= the amount, in mg/g 

source rock, of hydrocarbon already generated by the 

source rock; S2= the amount of hydrocarbon generated 

during anhydrous pyrolysis, in mg/g source rock). 

Hydrogen Index (HI): The relative amount of hydrogen per total organic carbon (mg H/g TOC) stored in the 

kerogen, as determined by anhydrous pyrolysis (S2/TOC). 

Inertinite: The coal maceral group that shows little or 

no reaction during the process of heating. Inertinite includes fusinite, sclerotinite derived from· fungal remains, 

and other high-carbon materials with a low-hydrogen content and a high reflectance. 

Kerogen: The disseminated organic matter of sedimentary rocks that is insoluble in mono-oxiding acids, 

bases, and organic solvents. The organic matter, initially 

deposited with unconsolidated sediments, is not kerogen 

but a precursor that is converted to kerogen during diagenesis. Sapropelic kerogens yield oil and gas on heating, 

while humic kerogens yield mainly gas. Kerogen includes 

both marine- and land -derived organic matter, the latter 

being the same as the components of coal. 

Liptinite (exinite): A coal maceral group that comprises the macerals sporinite, cutinite, suberinite, resinite, 

alginite and liptodetrinite. Liptinite macerals are derived 

from relatively hydrogen-rich plant remains such as 

sporopollenin, resins, waxes and fats. Liptinite is widely 

disseminated in sediments and is an important source of 

crude oil. Liptinite macerals are the dominant organic constituent of boghead coals and oil shales. 

Nuclear Magnetic Resonance (NMR): An analytical 

technique that measures the relaxation period (resonance) 

of paramagnetic nuclei which have been induced to spin in 

an opposite direction to normal spin by the application of 

an external magnetic field. In organic geochemistry, generally 1

H and 13C are analyzed. The technique gives information on the basic molecular structure and the distribution of functional groups in the molecule. 

Semifusinite: The intermediate stages between fusinite and telinite are termed semifusinite. Semifusinite 

shows lower reflectance than fusinite but higher reflectance than vitrinite. 

Source rock: A sediment that in its natural setting has 

generated and released enough hydrocarbons to form a 

commercial accumulation of oil or gas. 

Telocollinite: Structureless humified plant tissues 

often associated with telinite. telocollinite is related to cell 

lumens, whereas telinite is related to cell walls. 

T max: The maximum temperature at which a source 

rock generates hydrocarbons during anhydrous pyrolysis 

experiments. 

Total Organic Carbon (TOC): The total organic carbon that is sourced from thermally and diagenetically altered terrestrial, lacustrine, and marine organic compounds 

in a source rock. This is generally determined as the analytical difference between total carbon and inorganic carbon in the source rock. 

Vitrinite: A coal maceral group that is the dominant 

organic constituent of humic coals. Vitrinite forms the familiar brilliant black bands of coal. Macerals in the vitrinite group include telinite derived from plant cell walls and 

collinite from the cell filling. Vitrinite particles are found 

in about 80 percent of clays and sands. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Biogeochemistry of Natural Gases in Three Alkaline, 

Permanently Stratified (Meromictic) Lakes 

By Ronald S. Oremland1 and Laurence G. Miller1 

CONTENTS 

Abstract ......................................................................... 439 

Introduction ................................................................... 439 

Site Descriptions ........................................................... 440 

Monimolimnion Chemistry and Gaseous 

Hydrocarbons ................................................................ 441 

Methane in the Mixolimnion ........................................ 443 

Gas Seeps . .. ....... .. . . . . .. .. .. .. ... . .. .. .. . .. ... ...... ...... .. .. .. .. .. .. ... .. . 444 

Microbial Activities in the Anoxic Sediments ............. 445 

Summary ....................................................................... 450 

Conclusions ................................................................... 450 

References Cited ........................................................... 450 

ABSTRACT 

Methane and associated light hydrocarbons are present 

as dissolved gases in the water columns of three alkaline, 

permanently stratified (meromictic) lakes: Big Soda Lake 

(Nevada), Mono Lake (California), and Soap Lake (Washington). Methane originates in the bottom sediments, but 

higher gaseous hydrocarbons (that is, gaseous hydrocarbons of higher molecular weight) have either microbial or 

thermal sources in the different lakes. Stable isotopic composition, hydrocarbon indices, radiocarbon dating, abundance-versus-depth profiles, and biological experiments 

indicate that methane is formed in the sediments by microbial processes. Methanogenesis and sulfate-reduction have 

1

Water Resources Division, U.S. Geological Survey, 345 Middlefield Road, MS 465, Menlo Park, CA 94025. 

much higher activity in the shallow littoral sediments than 

in the colder, more saline pelagic sediments of all three 

lakes. Methane-rich gas seeps are common in Mono Lake 

and emanate from a natural-gas deposit underlying the 

current lakebed. Seeps do not occur in either Big Soda 

Lake or Soap Lake. Ethane and higher alkanes are present 

in Big Soda Lake and Mono Lake, but are not present in 

significant quantities in Soap Lake. It is not clear if the 

presence of these higher alkanes is a consequence of biological activity, a result of mixing with thermogenic gases, 

or a combination of both factors. These results indicate the 

potential complexity and diversity encountered in studying 

light-hydrocarbon biogeochemistry in thermally and microbially active systems. Hence, in the case of methane, 

detailed multidisciplinary studies are often needed to determine its origin. For ethane and higher alkanes, there is 

currently a paucity of basic scientific information to allow 

for unequivocal identification of microbial and thermogenic sources. 

INTRODUCTION 

Methane, the main component of natural gas, is 

formed by two major processes that occur in the Earth's 

crust: (1) microbial methanogenesis in anaerobic ecosystems (microbial methane), and (2) the exposure over time 

of deposited organic matter to geologic heat sources (thermogenic methane). Because petroleum formation is often 

associated with the latter process (but not the former), 

there has been financial impetus to devise techniques to 

distinguish between these two types of natural gases. 

These techniques require either a detailed scrutiny of the 

limited information contained within the methane molecule itself (for example, stable isotopic ratios of 13Ct12c 

439 
440 THE FUTURE OF ENERGY GASES 

and D/H, and radiocarbon content) or the methane's abundance relative to that of associated gases (for example, 

CH4/[C2H6+C3H8]). Such methods and their limitations 

have been discussed in detail by a number of authors (Bernard, 1979; Claypool and Kvenvolden, 1983; Schoell, 

1983; Whiticar and others, 1986; Oremland, 1988), and 

they have been widely applied to the study of methane 

biogeochemistry. Another mechanism of methane formation involves the catalytic reduction of C02 with H2 at 

high temperatures, which is believed to occur in deep-sea 

spreading centers (Welhan and Craig, 1979) and whose 

product is referred to as abiogenic methane (Apps and van 

de Kamp, this volume). Finally, a fourth type of methane, 

termed "primordial" (also of abiogenic origin), has been 

hypothesized to exist within the earth's mantle as a remnant of the original accretionary matter associated with the 

Earth's formation (Gold, 1979; Gold, this volume). However, an unambiguous sample of primordial methane has 

never been collected, and hence its properties and even its 

existence are unconfirmed. 

Our understanding of the processes involved in natural-gas formation, the importance of methane in biogeochemical cycles, and the evolutionary significance of 

methanogenic bacteria has expanded enormously over the 

past 25 years. Impetus for much of this work was derived, 

in part, from the energy crises of the 1970's and 1980's; 

however, these crises were not the only motivating forces. 

From a biological perspective, bacterial formation of 

methane has been known since the time of Pasteur, but the 

first detailed work with pure isolates and mass cultures 

took place much later (Bryant and others, 1967; Wolfe, 

1971, 1992) and ultimately led to an appreciation of the 

unique biochemistry and genetic composition of methanogenic bacteria. Genetic analyses (16s ribosomal RNA base 

sequences) resulted in the classification of methanogens 

within a unique kingdom, known as Archaebacteria (Balch 

and others, 1979; Woese and Fox, 1977; Jones and others, 

1987). Considerable advances have also been made with 

regard to the biochemistry and genetics of the methaneoxidizing bacteria (Whittenbury and others, 1970; Anthony, 1982; Crawford and Hanson, 1984). Along with these 

basic biological findings have been many studies of the 

ecological and geochemical aspects of the methane cycle 

in nature (see reviews by Oremland, 1988; Winfrey, 1984; 

Ward and Winfrey, 1985). In addition, the identification of 

methane as an important atmospheric greenhouse gas has 

heightened our need to understand its global biogeochemistry (Cicerone and Oremland, 1988; Cole, this volume). 

Some of the results of these biogeochemical and ecological investigations of methane have refined our understanding of the assumptions used in natural-gas classification. For 

example, the alkane abundance ratio (CH4/[C2H6+C3H8]) 

assumes that production of C2+ alkanes proceeds only from 

thermogenic reactions. Nonetheless, bacterial formation of 

higher alkanes (alkanes of higher molecular weight) has 

been noted (Davis and Squires, 1954; Oremland, 1981; 

Vogel and others, 1982; Oremland and others, 1988). Stable 

carbon isotopic ratios of methane (o13C) assume that light 

values-more negative than -60 parts per thousand-are 

associated with bacterial formation processes. However, the 

ability of methane-oxidizing bacteria to fractionate in favor 

of 12C can result in 13C-enriched unoxidized methane (Silverman and Oyama, 1968; Coleman and others, 1981). Furthermore, the anaerobic biodegradation of components of 

crude oil deposits can result in bacterial methanogenesis, 

which can obscure the methane source (Ivanov and others, 

1983). 

These issues prompted our research interest over the 

past decade in alkaline, hypersaline, meromicitic (permanently stratified). Such environments are thought to be 

precursors of certain lacustrine oil deposits and oil-rich 

shales (Bradley, 1931; Smith and Robb, 1973; Tis sot and 

others, 1978; Demaison and Moore, 1980; Tuttle and 

Goldhaber, in press). In addition, because high abundances 

of methane, ethane, and propane were reported in the waters and sediments of the anoxic, hypersaline Orca Brine 

in the Gulf of Mexico (Sackett and others, 1979), we undertook research on lakes of this type in order to enhance 

our understanding of natural-gas biogeochemistry. The 

persistence in each lake of a stratified water column with 

anoxic bottom waters has allowed us to investigate detailed microbiological processes and their influence on 

methane biogeochemistry. Furthermore, we have found 

that these sites often have multiple sources of methane 

(for example, microbial, thermal, and ancient microbial), 

which has allowed us to classify these gases by using extensions of established practices. In this paper we review 

some of the highlights of our investigations of three alkaline, meromictic lakes, and present new comparative data 

with respect to natural gases in these three lakes. 

SITE DESCRIPTIONS 

The locations and outlines of Big Soda Lake, Mono 

Lake, and Soap Lake are shown in figure 1, and comparative limnological data are listed in table 1. These and subsequent data have been drawn from published works on 

Mono Lake (Mason, 1967; Jellison and Melack, 1988; 

Oremland and others, 1987; Oremland and King, 1989; 

Oremland, 1990; Miller and others, 1993; Oremland and 

others, 1993), Big Soda Lake (Oremland and others, 1982; 

Priscu and others, 1982; Oremland, 1983; Cloem and others, 1983a, b; Oremland and Des Marais, 1983; Kharaka 

and others, 1984; Zehr and others, 1987; Smith and Oremland, 1987; Iversen and others, 1987; Cloem and others, 

1987; Oremland and others, 1988), and Soap Lake (Friedman and Redfield, 1971; Walker, 1974, 1975; Sanchez and 

others, 1986). All three are terminal, closed-basin lakes, 

with Mono Lake covering the largest area. In terms of dura-
BIOGEOCHEMISTRY OF NATURAL GASES 441 

Table 1. Limnological properties of Mono Lake, Big Soda Lake, and Soap Lake. 

[Pycnocline depth is depth of the salinity gradient] 

Limnological propeny 

Area (km2

) --------------------------------

Depth (m) ---------------------------------

Pycnocline depth (m) --------------------

Duration of meromixis (yr)-------------

Sa1inity (giL) of mixolimnion----------

Salinity (giL) of monimolimnion ------

pH ------------------------------------------

Mono Lake 

150 

30 

20 

5 

80 

90 

9.7 

Big Soda Lake 

1.6 

62 

35 

80 

27 

88 

9.7 

Soap Lake 

3.4 

27 

20 

2,000(?) 

18 

141 

9.7 

Productivity (g C/ m2 yr) -------------- 340-550 500 391 

-----------·------------------------

0 10 km 

>--+-+-+-+-; 

Big Soda 

Lake 

0 

0 1.0 km 

H++H 

Figure 1. Locations and outlines of Mono Lake, Calif.; Big Soda 

Lake, Nev.; and Soap Lake, Wash. 

tion of meromixis (prolonged stratification due to salinity-

- based density differences between surface and bottom waters), Mono Lake had a brief meromictic event associated 

with the 1982-1983 El Nifio, and returned to its normal 

monomictic (a single autumn turnover of the water column) 

condition in I988. Big Soda Lake and Soap Lake have 

much stronger salinity gradients and therefore can be considered to be in permanently meromictic states. Meromixis 

in Big Soda Lake resulted from local groundwater recharge 

associated with the Newlands Reclamation Project at the 

beginning of the 20th century. Although a similar situation 

exists for Soap Lake, separation of the highly saline bottom 

waters from the surface waters may have persisted there for 

centuries. All three lakes have similar levels of primary 

productivity and are poised at a pH of 9.7. Monimolimnion 

sediments (anoxic waters and sediments below the salinity 

gradient) from Big Soda Lake are unusual in that they had 

multicolored layers (brown, red, green, white) present in 

the upper 15 em, and displayed green and grey banding 

patterns throughout the upper I m of sediment (Oremland 

and others, 1988). Soap Lake monimolimnion sediments 

are also unusual, being characterized by layers of precipitated mirabilite (Na2S04•1 OH20) interspersed with green 

organic-rich sediment. Mono Lake sediments are the most 

conventional in appearance, being dull green to black in 

color, and having no immediately obvious layering with the 

exception of an approximately 0.5-cm-thick volcanic ash 

layer (about 50 em subbottom depth) from the eruption of 

Panum Crater (about 1350 AD). A closer examination of 

Mono Lake cores reveals, however, a pattern of fine laminations, probably formed from sinking phytoplankton 

blooms. 

MONIMOLIMNION CHEMISTRY AND 

·GASEOUS HYDROCARBONS 

Although all three environments may be classified as 

biological extremes because of their pH and salinity, there 

is a further distinction when the chemical properties of the 

monimolimnions of the three lakes are compared. Soap 

Lake bottom water is about 60 percent more saline than 

that of the other two lakes (table I) and contains significantly higher levels of dissolved carbonate/bicarbonate 

and sulfate (table 2). Apparently sulfate was, at one time, 

at saturation levels in Soap Lake, as indicated by the presence of obvious layers of precipitated mirabilite (Na2S04• 

IOH20) in the fluid-like monimolimnion sediments. This 

mineral was not observed in the sediments of either Mono 

or Big Soda Lake. Most important in terms of environmental extremes, however, is Soap Lake's very high level 
442 THE FUTURE OF ENERGY GASES 

Table 2. Some chemicaJ properties of dissolved methane in monolimnion waters and sediments of 

Mono Lake, Big Soda Lake, and Soap Lake. 

[n.d., not detennined] 

Chemical property 

Sulfate (millimolar)-------------------------------------

Sulfide (miilimolar)-------------------------------------

Carbonates (molar)-------------------------------------

Methane (micromolar) ---------------------------------

1\13C(CH4) (permil), in water-------------------------

b13C(CH4) (permil), in sediment---------------------

bD(CH4) (permil), in water and sediment---------

C/(C2+C3), in water-----------------------------------

C/(C2+C3), in sediment-------------------------------

14CH4, percent in modem carbon --------------------

Sediment methane flux (millimoles/m2 day)-------

of dissolved sulfide (140 millimolar), which is one and 

two orders of magnitude greater than that measured in Big 

Soda Lake and Mono Lake, respectively. Apparently, the 

duration of meromixis is proportional to the quantity of 

dissolved sulfide accumulated. This sulfide indicates a period of prolonged bacterial sulfate reduction fueled by 

sinking organic matter from the mixolimnion (surface waters above the salinity gradient) occurring in the presence 

of an essentially unlimited supply of sulfate available as 

an electron acceptor. However, the presence of such high 

sulfide levels poses a challenge to bacterial survivaL 

Methane was present at comparable levels (55 micromolar) in the bottom waters of Mono Lake and Big Soda 

Lake. The source of this methane was the sediment, as 

indicated by a steady increase of dissolved methane with 

sediment depth, reaching approximately 2. 7 millimolar at 

I m subbottom depth in Mono Lake (Oremland and others, 

1987) and 0.33 millimolar in Big Soda Lake (Oremland 

and Des Marais, 1983). Premeromixis values of bottomwater methane for Mono Lake were 8 micromolar, and 

reached 55 micromolar only after 4 years of stratification 

(Miller and others, 1993). In contrast, methane was always 

55 micromolar in Big Soda Lake, presumably reflecting a 

steady state between production and consumption (Iversen 

and others, 1987). Dissolved methane profiles in the water 

columns of all three lakes are shown in figure 2. In Soap 

Lake, bottom waters had very high levels (1.2 millimolar) 

of dissolved methane. However, a concentration gradient 

was not observed across the sediment-water interface. This 

lack of a gradient was due to the extremely fluid nature of 

the bottom sediments, which had the consistency of a loose 

gel (porosity>0.95). In this matrix we frequently observed 

the rapid upward migration of gas bubbles throughout the 

recovered core. Because such migration obliterates any 

methane gradients, more refined techniques, such as in-situ 

core freezing, would be required to establish the nature of 

the gradient. 

Mono Lake 

130 

I 

.4 

55 

-72 

-86 

-210 to -290 

750 

600 

80 

0.2-1.2 

.. 

CD 

- 1000 .. 

CD 

Q. 

0 

CD 100 -0 

E 

0 

.. 

() 10 ·-E 

c 

CD 1 s::: 

ca 

.r:. 

-

CD 0.1 

== 

Big Soda Lake Soap Lake 

71 186-265 

13 140 

.4 1.0 

55 1,200 

-60 -47 to -50 

-72 n.d. 

n.d. n.d. 

180 2,950 

1,750 10,000 

n.d. n.d. 

1.4-2.9 n.d . 

oo 

0 

'(-o-----0 -o 0 

I o<iooO 0 o· . I i' . a~o 0 ' 0 

9 o[{/ 

I d I ·O 

0 _ o- J oj 

D-.0 .o/ 

0-0-Q 

0 10 20 30 40 50 60 

Depth in meters 

Figure 2. Dissolved methane in water columns of Soap Lake 

(squares) during August 1990, Mono Lake (diamonds) during 

July 1990 (post meromixis), and Big Soda Lake (circles) during 

October 1984. 

Mono Lake and Big Soda Lake bottom waters and 

sediments all had appreciable concentrations of ethane, 

propane, and butanes. In Mono Lake, ethane and propane 

levels reached 3 and 1 micromolar, respectively, in the 

sediments and exhibited profiles similar to that of methane, which suggest a similar source (Oremland and others, 

1987). A similar sediment profile was obtained during 

sampling in the summer of 1990 (fig. 3). The situation was 

different in Big Soda Lake, where C2+ alkanes decreased 

with depth in the sediment while methane increased 

(Oremland and Des Marais, 1983). This trend was also apparent in the summer 1990 sampling, although propane 
BIOGEOCHEMISTRY OF NATURAL GASES 443 

~0.3 Q) 

-; 

E 

1: 

::.. 0.6 

J: 

... 

c.. 

w 0 0.9 

ETHANE OR PROPANE 

(micromoles per kilogram) 

2 4 6 8 10 

1.2L-----~------~------L-----~ 

0 1 2 3 4 

METHANE (millimoles per kilogram) 

CH 4 / (C 2 H 6 + C 3 H a) 

Figure 3. Amounts of methane (triangles), ethane (circles), and 

propane (solid squares) in Mono Lake monimolimnion sediments 

collected during summer of 1990, reported in volume of gas per 

weight of sediment. Also shown is ratio CH4/(C2H6+C3H8) (open 

squares). 

was not quantified (fig. 4). Ratios of CH4/(C2H6+C3H8) 

decreased slightly with depth in Mono Lake sediments 

(Oremland and others, 1987), whereas a slight increase 

was observed in the 1990 sampling (fig. 3). Increases in 

this ratio were observed with sediment depth in Big Soda 

Lake (table 2; fig. 4). In both cases, the hydrocarbon ratios 

were high enough (much greater than 1 00) to signal a microbial source for the methane, and this interpretation was 

reinforced by the light values of 613C detected in the bottom waters and sediments. In addition, the D/H ratios and 

14C content of methane in Mono Lake also signaled a microbial source of recent origin (table 2). 

The source of the higher molecular weight alkanes, 

however, is unclear. In Mono Lake, the similarity of the 

methane, ethane, and propane profiles (fig. 3) suggests a 

common bacterial source in the sediments, and incubated 

sediments displayed the capacity to form ethane (Oremland 

and others, 1987; Oremland and others, 1988b). However, 

thermogenic gas seeps occur in the lake (see section "Gas 

Seeps") and a mixture of thermal and microbial sources 

cannot be ruled out. In Big Soda Lake, the decrease of C2+ 

hydrocarbons with sediment depth suggests a hydrocarbon 

source in the water column. Because this lake is the remnant of a Pleistocene volcanic eruption, thermogenic sources cannot be ruled out. We did not test these sediments for 

their ability to bacterially generate ethane upon incubation; 

however, sediments from the mixolimnion demonstrated 

ETHANE (micromoles per kilogram) 

0.0 0.2 0.4 0.6 0.8 

o.--------.--------,-,---x----.----_, 

-~ 0.4 

Q) 

-

Q) 

E 

1: 

::.. 0.8 

J: 

... 

c.. 

w 0 1.2 

1.6 L_ ___ _j_ ___ _.L ____ .L._ ___ _J 

0 80 160 240 

METHANE (micromoles per kilogram) 

CH 4 /C 2 H 6 

320 

Figure 4. Amounts of methane (squares) and ethane (triangles) 

in Big Soda Lake monimolimnion sediments collected during 

summer of 1991, reported in volume of gas per weight of sediment. Also shown is ratio CH4/C2H6 (circles). 

this capacity, with ethane thiol and diethylsulfide implicated as precursors (Oremland and others, 1988). 

The characteristics of the gaseous hydrocarbons in 

Soap Lake differed from those of Mono and Big Soda 

Lakes. The 613C for methane was considerably heavier (by 

13 to 25 per mil), but this observation was based on only 

four water-column samples (range of 613C=-46 to -50 per 

mil) and did not include the sediments. Hence, it is possible 

that a strong, progressive 12C-enrichment occurs with depth 

in the Soap Lake sediments as was observed in the other 

two lakes. The most striking feature of the gaseous hydrocarbons in Soap Lake was the very large hydrocarbon abundance ratios, in part due to the absence of any detectable 

propane or butanes and only a trace level of ethane (about 

2.5 nannomolar). The absence of significant levels of C2+ 

alkanes was unexpected, because we had previously observed their presence at Mono and Big Soda Lakes. The 

fact that Soap Lake does not display any obvious signs of 

geothermal activity may account for this observation. Alternatively, the high sulfide levels in the bottom waters may 

have prevented the microbes responsible for C2+ alkane 

formation from forming these gases. 

METHANE IN THE MIXOLIMNION 

Some of the characteristics of methane found in the 

surface waters (mixolimnion) of the lakes are listed in 

table 3. Dissolved methane concentrations at the air/water 
444 THE FUTURE OF ENERGY GASES 

Table 3. Characteristics of methane in surface waters (mixolimnion) of Mono 

Lake, Big Soda Lake, and Soap Lake. 

Methane characteristic Mono Lake Big Soda Lake Soap Lake 

CH4 (micromolar) ------------- 0.1-1.3 0.1-0.6 0.4 

I\ 13C(CH4) (permil) ----------- -20 to -54 -21 to -68 -47 

Flux to atmosphere 0.4 to 201 0.8 to 3.1 2.5 to 8.3 

(micromoles/m2 hour). 

Gas seeps? --------------------- Yes 

interface typically ranged between 0.1 to 1.3 micromolar, 

values which represent 50- to 650-fold saturation with respect to the partial pressure of methane in the atmosphere. 

Outward flux of this methane was measured with deployed 

floating chambers (Miller and Oremland, 1988). Fluxes 

were generally in the range of a few micromoles/ m2/ hour; 

however in Mono Lake where we conducted the most extensive samplings, we sometimes observed fluxes that were 

about two orders of magnitude higher (table 3). The stable 

carbon isotopic composition of this methane was markedly 

enriched in 13C relative to the source methane in the sediments. This heavy isotopic enrichment was a consequence 

of bacterial methane oxidation occurring in the water columns of the lakes. The overwhelming majority of this oxidation was in the anoxic bottom waters rather than at the 

aerobic/anaerobic interface, a conclusion that was borne 

out by in-situ experiments with 14CH4 (Iversen and others, 

1987; Oremland and others, 1993). The influence of bacterial methane oxidation in these circumstances upon the 

o13c values cannot be overstated. In both Mono and Big 

Soda Lakes, values as heavy as -20 permil were often encountered. Such strongly 12C-depleted methane would normally be interpreted as signalling a thermogenic source of 

methane (Schoell, 1983). In this case, however, methane is 

microbial in origin but additionally has been subjected to 

microbial oxidation. Soap Lake mixolimnion methane had 

a o13C of -46 permil (depth=l7 m), a value which may 

also reflect some degree of microbial oxidation. 

GAS SEEPS 

Gas seeps were commonly observed in Mono Lake, but 

were absent from the other two lakes. The Mono Lake 

seeps were continuous flow (0.1-4 liters/min), were numerous (more than 700 were tabulated), consisted mainly of 

methane ( 61-98 percent of total gas volume), and originated from a subsurface natural-gas deposit (Oremland and 

others, 1987; Orem1and and others, 1993). The deposit covered about one third of the lake bottom. Seeps located in 

hot springs had a stronger thermogenic character (for example, o13C=-48 permil; C1/(C2+C3)=15), whereas all of the 

other seeps had parameters that signaled a microbial origin 

(for example, o13C=-70 permil; C1/(C2 +C3)=33,000). 

No No 

0 0 0 

o. 1#1 

o •• 

BIOGENIC 

0 

• 

----------------, 

---

THERMOGENiC 

-50 -60 -70 

813CH4 (permil) 

-80 -90 -100 

Figure 5. o13CH4 versus CH4/(C2H6+C3H8) for seep and hot 

spring gases collected in Mono Lake, the Mono Basin, and from 

Long Valley as reported by Oremland and others (I 993) and by 

Oremland and others (1987). Classification "envelopes" for gases 

originating from biogenic sources (bacterial), thermogenic sources, or mixtures of both sources are from Whiticar and others 

(1986) and are indicated by dashed lines. Mono Lake biogenic 

seeps (dots); Mono Lake hot spring (thermal) seeps (open stars); 

Long Valley seep gases (open circles). End member values for 

gas bubbles collected from Dechambeau Ranch freshwater pond 

(located on Mono Lake's northern shore) (open box); Dechambeau Ranch hot spring (filled box). Endmember value of gases 

associated with decomposing, submerged shoreline grasses collected from the south shore of Mono Lake at Navy beach (filled 

triangle). 

However, all the seep methanes had low radiocarbon values 

(less than 11 percent modem carbon), which indicated an 

age of more than 20,000 years. Because the radiocarbon 

content of dissolved methane in the monimolimnion (80 

percent modern carbon) was equivalent to that present in 

the dissolved inorganic carbon (81 percent modern carbon; 

Peng and Broecker, 1980), a modern microbial origin was 

deduced for this methane, which was different from that of 

the seep methane. 

In figure 5 are shown the characteristics (o13C versus 

C1/[C2+C3]) of the Mono Lake seep methane, as well as 

those of methane in gas seeps at other locations in the 
BIOGEOCHEMISTRY OF NATURAL GASES 445 

Table 4. Methane concentration in gas samples from seeps 

at Hot Creek, Calif. (A and B), and proximal fumaroles (C 

and D), collected before, during, and after an earthquake 

(from Oremland, l983b). 

[Values are in volume percent. The eanhquake had a magnitude of 5.7; it 

struck 30 km southeast of Mammoth Lakes, Calif .. at 9:45 a.m. on October 4, 

1978. Gas samples were collected within 3 hours of the first shockwave. 

n.d., not determined] 

Site Sept 17, 1978 Oct. 4, 1978 Oct. 9, 1978 

A 0.16 0.12 0.12 

B .07 .06 n.d. 

c n.d. .01 .01 

D n.d. .01 .01 

Mono Basin and in Long Valley, California. The results fall 

clearly into two patterns: microbial and thermogenic. The 

Long Valley seep gases were mostly associated with hot 

springs in the Mammoth Lakes region, such as found in 

Hot Creek. These seeps had highly variable methane levels, ranging from 0.04 to 58 percent by volume (Oremland 

and others, 1993). This methane originated from current 

microbial sources, as indicated by its isotopic ratios and 

hydrocarbon indices (fig. 5) plus the fact that sediments 

clearly displayed methanogenic activity when incubated at 

6rC (Oremland, 1983b). Some of these seeps were monitored before, during, and after a magnitude 5.7 earthquake 

in 1978 to determine if an abrupt increase in their methane 

content could be discerned as predicted by Gold (1979). As 

can be seen in table 4, the methane content of the seeps 

actually declined after the earthquake. Thus the question 

remains whether primordial methane is a causative factor 

of seismic activity, or even if it exists at all. 

MICROBIAL ACTIVITIES IN THE 

ANOXIC SEDIMENTS 

Detection of microbial methanogenesis was reported 

previously in experiments with sediment slurries from Big 

Soda Lake (Oremland and others, 1982; Oremland and others, 1987) and Mono Lake (Kiene and others, 1986; Oremland and others, 1987; Oremland and King, 1989; Oremland, 

1990). Experiments with 14C-labelled methane precursors 

(trimethylamine, acetate, bicarbonate, methanol, and dimethylsulfide) have been published for Mono Lake (Oremland 

and King, 1989; Oremland and others, 1993). However, in 

the case of Soap Lake, the geochemical data were insufficient to determine whether the methane originated from 

ancient or current microbial activity. To determine if methanogenic activity in Soap Lake sediments could still occur at 

the high ambient sulfide concentrations, we conducted a 

preliminary experiment with bottom sediment slurried in a 

ratio of I: I with bottom water and incubated under N2 with 

CD' 

(.) 

co 

g. 30 

'C 

wco ZCI) 

<(.s::: 

:::c£ 20 

Iii~ ~0 

E 

~ 10 (.) .E 

- 20 40 60 80 100 

DAYS 

Figure 6. Methanogenesis during prolonged incubation of Soap 

Lake sediments slurries. Slurries were incubated with I 0 millimolar trimethylamine (dots), or without amendments (triangles). 

Data points represent mean of three slurries, and bars (where 

shown) indicate ± one standard deviation. Headspace, 80 mL 

volume. 

and without amendment of trimethylamine, a noncompetitive methanogenic substrate (Oremland and Polcin, 1982). 

Unamended slurries steadily produced a small amount of 

methane over prolonged incubation, while those amended 

with trimethylamine exhibited an approximate 10-fold enhancement of activity (fig. 6). These results were construed 

to indicate the presence of a potentially active methanogenic 

bacterial flora in the pelagic sediments of Soap Lake. However, the activity was slow relative to that of slurry experiments conducted with sediments from Big Soda and Mono 

Lakes (Oremland and others, 1982; Kiene and others, 1986; 

Oremland and King, 1989). 

During the summer of 1990 we conducted a field program to quantify and compare the relative activities of 

methanogenesis and sulfate-reduction in the littoral and 

pelagic sediments of the three lakes. We collected 1-mlong gravity cores from the pelagic sediments and approximately 0.3-m-long hand cores collected by divers from 

the littoral sediments. Cores were extruded and subsampled at specified depths with 10-mL or 5-mL subcores. 

The subcores were injected with radioisotopes ( 14C-trimethylamine, 2- 14C-acetate, NaH14C03, or Na2

35S04) and 

incubated at their respective in-situ temperatures for 24 

hours (NaH14C03 for 46 to 92 hours) after which activity 

was arrested by freezing. The details of this procedure and 

the subsequent extraction procedures for 35s-sulfide and 

14C-methane have been given elsewhere (Oremland and 

King, 1989; Oremland and others, 1993). We employed 

the 14C-labelled acetate and trimethylamine to qualitatively scan for the presence of microbial mineralization of 

these compounds (to 14C02 and (or) 14CH4). Because a 
446 THE FUTURE OF ENERGY GASES 

number of substrates (such as acetate, methylamines, 

methanol, formate, dimethylsulfide, bicarbonate) may be 

potential methane precursors, their employment to estimate in-situ kinetics includes the need for an accurate assessment of in-situ pool sizes (pore-water substrate 

concentrations), which must be achieved prior to their use. 

Addition of too large a quantity of radioisotope coqld i[lcrease the unlabelled pool sizes (

14C-substrates have low 

specific activities), resulting in overestimates of activity. 

Because substrate pool sizes are generally quite low (for 

example, 0.1 micromolar) in these environments (Oremland and King, 1989), use of radiolabelled organi9 methane precursors to assess in-situ methanogenesis from all 

potential substrates posed too many technical difficulties 

for the purpose of a preliminary survey. Hence we chose 

14C-bicarbonate because its addition would not affect the 

high carbonate/bicarbonate pools of these lakes, anq 

LC02 in pore waters is easily measured. To compensate 

for the large isotope-dilution effect, we used elevated I 

amounts of isotope per sample (50 microcuries), used prolonged incubations, and extracted 14C-methane in a cryogenic trap/oxidation line for analysis by ·liquid scintillation 

counting (Whelan and others, 1986). 

0.00 

0.10 

-

U) 

... 

s 

~ 0.20 

c 

:::. 

:I: 

~ 0.30 

w 

0 

0.40 

0 

0 

SULFATE REDUCTION RATE 

(micromoles . liter -1. day -1) 

50 100 150 200 

SULFIDE (millimoles. liter-1) 

5 10 15 . 20 

In the littoral-zone sediments of all three lakes, both 

acetate and trimethylamine were oxidized to C02, but only 

Soap Lake sediments exhibited any capacity for production 

of CH4, and this production was from acetate (table 5). Pelagic sediments were all able to mineralize acetate to C02, 

and with the exception of those from Soap Lake, all could 

mineralize trimethylamine to C02. Only Soap Lake pelagic 

sediments displayed a capacity for methanogenesis (from 

ac!!tate ). These results indicate that mineralization of both 

trimethylamine and acetate in the sediments of all three 

lakes was dominated by sulfate reduction. 

Depth profiles of sulfate reduction and methanogenesis via C02 reduction (from bicarbonate) for the littoral 

sediments of Mono, Big Soda, and Soap Lakes are shown 

in figures 7, 8, and 9, respectively. The activity in the pelagic sediments of the three respective lakes are shown in 

figures 10, 11, and 12. The littoral-zone sediments of all 

three lakes demonstrated detectable levels of sulfate reduction and methanogenesis. In broad terms, methanogenic 

activity (recorded on figures as C02 reduction) usually exhibited subsurface maxima for all cores, whereas sulfate 

reduction generally decreased with depth down the cores. 

In the pelagic sediments, Mono Lake demonstrated obviC02 REDUCTION RATE 

(micromoles . liter -1. day -1) 

250 0 1.0 2.0 3.0 4.0 5.0 

METHANE (millimoles . kg - 1) 

25 4Q 60 80 100 120 140 

0.50 .__ _ __._ __ ___,_ __ _..._ __ ..~.--_ ___, 

40 60 80 100 120 140 200 300 400 500 600 700 

A SULFATE (millimoles. liter-1) 

Figure 7. Bacterial activities in Mono Lake littoral sediments. A, Sulfate reduction. B, Methanogenesis (C02 reduction). TC02, total C02. Reduction rates are reported in 

micromoles of reduced compound (SO/- or HC03

2

-) per 

B TCO 2 (millimoles . liter-1) 

liter of sediment pore water per day. Sulfide, sulfates, and 

TC02 amounts are reported in millimoles of compound per 

liter of sediment pore water; methane amounts in millimoles per kilogram of sediment. 
BIOGEOCHEMISTRY OF NATURAL GASES 447 

ous sulfate reduction (fig. 10 A), which was generally consistent with previous measurements (Oremland and others, 

1993). Methanogenic activity, however, was lower than 

sulfate reduction (fig. lOB) and both decreased with depth 

down the core. Sulfate showed a marked decrease with 

core depth due to removal by sulfa,te reduction, and this 

result was reflected by generally increased sulfide with 

core depth. In Big Soda Lake, sulfate-reduction was highest at the core surface and declined with depth (fig. llA). 

However, although sulfide increased with depth, there was 

no corresponding decrease in sulfate. No discernible methanogenic activity was detected at any depth in the core 

(fig. liB). In Soap Lake, sulfate reduction was detected 

down the length of the core; however, sulfate increased 

markedly with depth, possibly due to resolution of precipitated mirabilite (fig. 12A). Methanogenic activity was detected only at the surface of the core (fig. 12B). 

The integrated rates of sulfate reduction and methanogenesis are presented in table 6. Sulfate reduction was 

clearly the dominant process for anaerobic carbon mineralization in both the littoral and pelagic sediments of the 

three lakes. Methanogenesis was, in comparison, only of 

minor importance in terms of carbon mineralization. This 

0.10 

-~ 

s 

~ 0.20 

.5 

-

~ 0.30 

ll. 

w 

c 

0.40 

0 

SULFATE REDUCTION RATE 

{micromoles . liter -1. day -1) 

25 50 75 100 

SULFIDE {millimoles. liter-1) 

2 4 6 8 

Table 5. Formation of 14C02 or 14CH4 from 14C-Iabelled trimethylamine or acetate in samples taken from littoral and pelagic 

sediments of Big Soda Lake, Mono Lake, and Soap Lake. 

[Positive sign indicates at least one sample of a core profile was active (that is, was 

fonning 14co2 or 14CH4); negative sign indicates that activity was absent at all 

depths assayed] 

Acetate Trimethylamine 

Site 

C02 CH4 C02 CH4 

Littoral sediments 

Big Soda Lake + + 

Mono Lake + + 

Soap Lake + + + 

Pelagic sediments 

Big Soda Lake + + 

Mono Lake + + 

Soap Lake + + 

C02 REDUCTION RATE 

{micromoles . liter-1. day -1) 

125 0 0.005 0.010 0.015 0.020 0.025 

METHANE {millimoles. kg-1) 

10 0 10 20 30 40 50 

0.50 .__ _ __. __ __,_ __ __._ __ -~.-_ ____...J 

~ ~ ® ~ ~ ro ® 50 60 70 80 

TCO 2 {millimoles . liter-1) 

90 

A SULFATE {millimoles .liter-1) 

Figure 8. Bacterial activities in Big Soda Lake littoral sediments. A, Sulfate reduction. B, Methanogenesis (C02 reduction). TC02, total C02• Reduction rates are reported in 

micromoles of reduced compound (SO/- or HCO/-) per 

B 

liter of sediment pore water per day. Sulfide, sulfates, and 

TC02 amounts are reported in millimoles of compound per 

liter of sediment pore water; methane amounts in millimoles per kilogram of sediment. 
448 

0 

THE FUTURE OF ENERGY GASES 

SULFATE REDUCTION RATE 

(micromoles . liter -1. day -1) 

1 000 2000 3000 4000 5000 0 

SULFIDE (millimoles . liter -1) 

C02 REDUCTION RATE 

(micromoles. liter-1. day-1) 

10 20 30 40 

METHANE (millimoles . kg -1) 

50 

0 5 1 0 15 20 25 0 500 1 000 1500 2000 2500 0.00 rr----,-----,---:::;rr---,----.-------, 

0.10 

-

~ 

.! 

~ 0.20 

c 

:.:. 

::1: 1- 0.30 

D. 

w 

a 

0.40 

0.50 '------"-----'-----'---------'----' 

0 1 0 20 30 40 50 500 

A SULFATE (millimoles. liter-1) B 

600 700 800 900 1000 

TCO 2 (millimoles . liter-1) 

Figure 9. Bacterial activities in Soap Lake littoral sediments. A, Sulfate reduction. B, Methanogenesis (C02 reduction). TC02, total C02. Reduction rates are reported in 

micromoles of reduced compound (SOl- or HCO/-) per 

liter of sediment pore water per day. Sulfide, sulfates, and 

TC02 amounts are reported in millimoles of compound per 

liter of sediment pore water; methane amounts in millimoles per kilogram of sediment. 

0 

SULFATE REDUCTION RATE 

(micromoles .liter-1. day-1) 

25 50 75 100 125 150 0 

C02 REDUCTION RATE 

(micromoles . liter-1. day -1) 

0.10 0.20 0.30 0.40 0.50 0.60 ,---,----.---,----,---,----. 

SULFIDE (millimoles .liter-1) METHANE (millimoles. kg-1) 

0 5 1 0 15 20 25 30 0 500 1 ODD 1500 2000 2500 3000 

0.00 r-c9J::::C:::::~-~?:n-l 

0.20 

...... 0.40 

I!! 

Figure 10. Bacterial activities in 

Mono Lake pelagic (monimolimnion) sediments. A, Sulfate reduction. B, Methanogenesis (C02 

reduction). TC02, total C02. Reduction rates are reported in micromoles of reduced compound 

(Sol- or Hcol-) per liter of 

sediment pore water per day. Sulfide, sulfates, and TC02 amounts 

are reported in millimoles of compound per liter of sediment pore 

water; methane amounts in millimoles per kilogram of sediment. 

~ 0.60 c 

::::;. 

i!: 0.80 

Q. 

w 

0 

1.00 

1.20 

Sulfate 

1.40 L.__.J.....__....L_ _ _j__---l. _ __.J_--.J 

0 20 40 60 80 100 120 200 

A SULFATE {millimoles .liter-1) B 

300 400 500 600 700 800 

TCO 2 (millimoles . liter-1) 
BIOGEOCHEMISTRY OF NATURAL GASES 

0.10 

~ 0.20 

~ 

~ E 0.30 

j!: 0.40 

a. 

w 

c 

0.50 

0.60 

SULFATE REDUCTION RATE 

(micromoles .liter-1. day-1) 

5 10 15 20 25 

SULFIDE (millimoles. liter-1) 

4 6 8 10 

30 

12 

C02 REDUCTION RATE 

(micromoles. liter-1. day-1) 

0 0.005 0.010 O.o15 0.020 0.025 

METHANE (millimoles . kg -1) 

40 50 60 70 80 90 

C02 

-Reduction 

Rate 

0.030 

100 

0.70 L_ _ _L... _ _L._ _ ___l._. _ ___L __ c..._____J 

20 30 40 50 60 70 80 220 230 240 250 260 270 280 

A SULFATE (millimoles. liter-1) B TCO 2 (millimoles . liter-1) 

Figure 11. Bacterial activities in Big Soda Lake 

pelagic (monimolimnion) sediments. A, Sulfate 

reduction. B, Methanogenesis (C02 reduction). 

TC02, total C02. Reduction rates are reported 

in micromoles of reduced compound (SO/- or 

SULFATE REDUCTION RATE 

(micromoles .liter-1. day-1) 

HC03 

2-) per liter of sediment pore water per 

day. Sulfide, sulfates, and TC02 amounts are 

reported in millimoles of compound per liter of 

sediment pore water; methane amounts in millimoles per kilogram of sediment. 

C02 REDUCTION RATE 

(micromoles . liter-1. day -1) 

0 1 00 200 300 400 500 600 0 0.10 0.20 0.30 0.40 0.50 0.60 

SULFIDE (millimoles .liter-1) METHANE (millimoles. kg-1) 

20 40 60 80 100 120 0 500 1 000 1500 2000 2500 3000 

0.10 

~ 0.20 

~ 

,S! 

Gl 

E 0.30 

j!: 0.40 

a. 

w 

c 

0.50 

0.60 

0. 70 .__ __ _._ __ __.~. __ _,__ _ _.__ _ ____c._______, 

.-~-,----,-~~----,----,---. 

0 500 1 000 1500 2000 2500 3000 500 600 700 800 900 1 000 11 00 

A SULFATE (millimoles .liter-1) 

Figure 12. Bacterial activities in Soap Lake 

pelagic (monimolimnion) sediments. A, Sulfate 

reduction. B, Methanogenesis (C02 reduction). 

TC02, total C02. Reduction rates are reported 

in micromoles of reduced compound (SO/- or 

B TCO 2 (millimoles . liter-1) 

HC03 

2

-) per liter of sediment pore water per 

day. Sulfide, sulfates, and TC02 amounts are 

reported in millimoles of compound per liter of 

sediment pore water; methane amounts in millimoles per kilogram of sediment. 

449 
450 THE FUTURE OF ENERGY GASES 

observation is not surprising, considering the high sulfate 

content of all three lakes. Sulfate reduction and methanogenesis were greater in the littoral sediments than in the 

pelagic sediments. Again, this result is not surprising considering that sediments were incubated at their in-situ temperatures (pelagic, 6-l2°C; littoral, 20-24°C). However, 

with the exception of Big Soda Lake pelagic sediments, all 

environments displayed the capacity for methanogenesis 

via C02 reduction. In previous work at Mono Lake, we 

reported pelagic sulfate reduction during meromixis (1986) 

to be 13.4 millimoles/m2 day, which was about twice the 

activity measured in 1990 (Oremland and others, 1993). 

With respect to methanogenesis from bicarbonate, however, 

we reported rates of 340 and 500 micromoles/m2 day during 1986 and 1988, respectively. These values are about 2 

orders of magnitude greater than our 1990 estimate 

(table 6). At present we have no explanation for this discrepancy, other than sample variability. 

Table 6. Integrated rates of sulfate reduction and methanogenesis for the littoral and pelagic sediments of Soap Lake, 

Mono Lake, and Big Soda Lake. 

Soap Mono Big Soda 

Lake Lake Lake 

Littoral sediments 

Sulfate reduction 175 32 8.4 

(millimoles SO/-Im2 day ). 

Methanogenesis 1.2 229 1.4 

(micromoles CH4/m2 day). 

Pelagic sediments 

Sulfate reduction 73 6.6 3.4 

(millimoles so/-lm2 day). 

Methanogenesis 0.2 4.3 0 

(micromoles CHim2 day). 

SUMMARY 

Methane is present in all three lakes. Microbiological 

experiments in all three lakes confirms that their sediments 

are active with respect to methanogenesis. However, considerable variability was observed between samples, and 

accurate assessments of methanogenic activity are as yet 

lacking. The contribution of this current methanogenesis to 

the methane observed in the lakes appears to be important; 

however, in the case of Mono Lake the picture is clouded 

by the presence of thermogenic methane as well as ancient 

microbial methane. The need for additional studies to better quantify methanogenic activity, as well as sulfate reduction, is obvious. In addition, more extensive radiocarbon 

dates for methane from the sediments and water columns 

of all three lakes would better refine our estimates of methane derived from current methanogenic activity relative to 

that derived from ancient microbial or thermogenic sources. Analysis of ethane and higher molecular weight hydrocarbons to determine their stable isotopic composition and 

radiocarbon contents may also shed some light on whether 

their origins are thermogenic or microbial. 

CONCLUSIONS 

1. Methane was present in the waters and sediments of 

all three lakes. 

2. Microbial methanogenesis was responsible for most 

of the methane detected, although the methane's stable 

isotopic composition was sometimes enriched with 13c 

from microbial oxidation. 

3. In Mono Lake, and possibly in Big Soda Lake, 

thermogenic gases were also present. 

4. It is not clear whether the C2+ alkanes detected in 

Mono Lake and Big Soda Lake pelagic sediments were 

formed by microbial reactions, mixing with thermogenic 

sources, or a combination of these two factors. 

5. The absence of C2+ alkanes from the Soap Lake 

system is unexplained. 

REFERENCES CITED 

Anthony, C., 1982, The biochemistry of methylotrophs: New 

York, Academic Press, 431 p. 

Balch, W.E., Fox, G.E., Magrum, L.J., Woese, C.R., and Wolfe, 

R.S., 1979, Methanogens-Reevaluation of a unique biological group: Microbiological Reviews, v. 43, p. 260-296. 

Bernard, B.B., 1979, Methane in marine sediments: Deep Sea 

Research, v. 26, p. 429-443. 

Bradley, W.H., 1931, Origin and microfossils of the oil shale of 

the Green River Formation of Colorado and Utah: U.S. Geological Survey Professional Paper 168, 58 p. 

Bryant, M.P., Wolin, E.A., Wolin, M.J., and Wolfe, R.S., 1967, 

Methanobacterium omelianskii, a symbiotic association of 

two species of bacteria: Archives of Microbiology, v. 59, 

p. 20-31. 

Cicerone, R.J., and Oremland, R.S., 1988, Biogeochemical aspects of atmospheric methane: Global Biogeochemical Cycles, v. 2, p. 299-327. 

Claypool, G.E., and Kvenvolden, K.A., 1983, Methane and other 

hydrocarbon gases in marine sediments: Annual Review of 

Earth & Planetary Sciences, v. 11, p. 299-327. 

Cloern, J.E., Cole, B.E., and Oremland, R.S., 1983a, Seasonal 

changes in the chemistry and biology of a meromictic lake 

(Big Soda Lake, Nevada, USA): Hydrobiologia, v. 105, 

p. 195-206. 

---1983b, Autotrophic processes in meromictic Big Soda 

Lake, Nevada: Limnology and Oceanography, v. 28, p. 1049-

1061. 
BIOGEOCHEMISTRY OF NATURAL GASES 451 

Cloem, J.E., Cole, B.E., and Wienke, S.M., 1987, Big Soda Lake 

(Nevada). 4. Vertical fluxes of particulate matter-Seasonality and variations across the chemocline: Limnology and 

Oceanography, v. 32, p. 815-824. 

Coleman, D.D., Risatti, J.B., and Schoell, M., 1981, Fractionation 

of carbon and hydrogen isotopes by methane-oxidizing bacteria: Geochimica et Cosmochimica Acta, v. 45, p. 1033-1037. 

Crawford, R.L., and Hanson, R.S., 1984, Microbial growth on C1 

compound: Proceedings of the 4th International Symposium, 

American Society for Microbiology, Washington, DC., 343 p. 

Davis, J.B., and Squires, R.M., 1954, Detection of microbially 

produced gaseous hydrocarbons other than methane: Science, v. 119, p. 381-382. 

Demaison, G. J., and Moore, G.T., 1980, Anoxic environments 

and oil source bed genesis: American Association of Petroleum Geologists Bulletin, v. 64, p. 1179-1209. 

Friedman, 1., and Redfield, A. C., 1971, A model of the hydrology 

of the lakes of the lower Grand Coulee, Washington: Water 

Resources Research, v. 7, p. 874-898. 

Gold, T.J ., 1979, Terrestrial sources of carbon and earthquake , 

outgassing, Journal of Petroleum Geology, v. 1, p. 3-19. 

Ivanov, M.V., Belyaev, S.S., Zyakun, A.M., Bondar, V.A., and 

Laurinavichus, K.S., 1983, Microbiological formation of 

methane in the oil-field development: Geokhimiya, v. II, 

p. 1647-1654. 

Iversen, N., Oremland, R.S., and Klug, M.J., 1987, Big Soda 

Lake (Nevada). 3. Pelagic methanogenesis and anaerobic 

methane oxidation: Limnology and Oceanography, v. 32, 

p. 804-814. 

Jellison, R., and Melack, J.M., 1988, Photosynthetic activity of 

phytoplankton and its relation to environmental factors in 

hypersaline Mono Lake, California: Hydrobiologia, v. 158, 

p. 69-88. 

Jones, W.J., Nagle, D.P., Jr., Whitman, W.B., 1987, Methanogens 

and the diversity of archaebacteria: Microbiological Reviews, v. 51, p. 135-177. 

Kharaka, Y.K., Robinson, S.W., Law, L.M., and Carothers, W.W., 

1984, Hydrogeochemistry of Big Soda Lake, Nevada-An 

alkaline, meromictic desert lake: Geochimica et Cosmochimica Acta, v. 48, p. 823-835. 

Kiene, R.P., Oremland, R.S., Catena, A., Miller, L.G., and Capone, D.G., 1986, Metabolism of reduced methylated sulfur 

compounds in anaerobic sediments and by a pure culture of 

an estuarine methanogen: Applied and Environmental Microbiology, v. 52, p. 1037-1045. 

Mason, D.T., 1967, Limnology of Mono Lake, California: Berkeley University of California, Ph.D. dissertation, 110 p. 

Miller, L.G., Jellison, R., Oremland, R.S., and Culbertson, C.W., 

1993, Meromixis in hypersaline Mono Lake, California 3-

Biogeochemical response to stratification and overturn: Limnology and Oceanography, v. 38, p. 1040--1051. 

Miller, L.G., and Oremland, R.S., 1988, Methane efflux from the 

pelagic regions of four lakes: Global Biogeochemical Cycles, v. 2, p. 269-277. 

Oremland, R.S., 1981, Microbial formation of ethane in anoxic, 

estuarine sediments: Applied and Environmental Microbiology, v. 42, p. 122-129. 

---1983a, Hydrogen metabolism by decomposing cyanobacterial aggregates in Big Soda Lake, Nevada: Applied and 

Environmental Microbiology, v. 45, p. 1519-1525. 

---1983b, Methane in association with seismic activity: Eos, 

v. 64, p. 410-411. 

---1988, Biogeochemistry of methanogenic bacteria, in Zehnder, A.J.B., ed., Biology of anaerobic microorganisms: 

New York, John Wiley & Sons, p. 64.1-705. 

---1990, Nitrogen fixation dynamics of two diazotrophic 

communities in Mono Lake, California: Applied and Environmental Microbiology, v. 56, p. 614--622. 

Oremland, R.S., Cloern, J.E., Safer, Z., Smith, R.L., Miller, L.G., 

Cole, B., and others, 1988a, Microbial and biogeochemical 

processes in Big Soda Lake, Nevada, in Fleet, A., Kelts, K., 

and Talbot, M~. eds., Lacustrine petroleum source rocks: Geological Society oLLondon Special Publication 40, p. 59-75. 

Oremland, R.S., and Des Marais, D.J., 1983, Distribution, abundance and carbon isotopic composition of gaseous hydrocarbons in Big Soda Lake, Nevada-An alkaline, meromictic 

lake: Geochimica et CosmochimicaActa, v. 47, p. 2107-2114. 

Oremland, R.S., and King, G.M., 1989, Methanogenesis in hypersaline environments, in Cohen, Y., and Rosenberg, E., 

eds., Microbial mats-Physiological ecology of benthic microbial communities: Washington, D.C., American Society 

for Microbiology, p. 180--190. 

Oremland, R.S., Marsh, L., and Des Marais, D.J., 1982, Methanogenesis in Big Soda Lake, Nevada-An alkaline, moderately hypersaline desert lake: Applied and Environmental 

Microbiology, v. 43, p. 462-468. 

Oremland, R.S., Miller, L.G., Culbertson, C.W., Robinson, S., 

Smith, R.L., and others, 1993, Aspects of the biogeochemistry of methane in Mono Lake and the Mono Basin of California, in Oremland, R.S., ed., Biogeochemistry of global 

change-Radioactively active trace gases: New York, Chapman and Hall, p. 704-741. 

Oremland, R.S., Miller, L.G., and Whiticar, M.J., 1987, Sources 

and flux of natural gases from Mono Lake, California: 

Geochimica et Cosmochimica Acta, v. 51, p. 2915-2929. 

Oremland, R.S., and Polcin, S., 1982, Methanogenesis and sulfate reduction-Competitive and non-competitive substrates 

in estuarine sediments: Applied and Environmental Microbiology, v. 44, p. 1270-1276. 

Oremland, R.S., Whiticar, M.J., Strohmaier, F.E., and Kiene, 

R.P., 1988b, Bacterial ethane formation from reduced, ethylated sulfur compounds in anoxic sediments: Geochimica et 

Cosmochimica Acta, v. 52, p. 1895-1904. 

Peng, T-H., and Broecker, W., 1980, Gas exchange rates for three 

closed-basin lakes: Limnology and Oceanography, v. 25, 

p. 789-796. 

Priscu, J.C., Axler, R.P., Carlton, R.G., Reuter, J.E., Arneson, 

P.A., and Goldman, C.R., 1982, Vertical profiles of primary 

productivity, biomass, and physicoGuttierchemical properties 

in meromictic Big Soda Lake, Nevada, U.S.A.: Hydrobiologia, v. 96, p. 113-120. 

Sackett, W.M., Brooks, J.M., Bernard, B.B., Scwab, C.R.S., and 

Chung, H., 1979, A carbon inventory for Orca brines and sediments: Earth and Planetary Science Letters, v. 44, p. 73-81. 

Sanchez, A.L., Murray, J.W., Schell, W.R., and Miller, L.G., 

1986, Fallout plutonium in two oxic-anoxic environments: 

Limnology and Oceanography, v. 31, p. 1110-1121. 

Schoell, M., 1983, Genetic characterization of natural gases: 

American Association of Petroleum Geologists Bulletin, 

v. 67, p. 2225-2238. 
452 THE FUTURE OF ENERGY GASES 

Silverman, M.P., and Oyama, V.I., 1968, Automatic apparatus for 

sampling and preparing gases for mass spectral studies of 

carbon isotope fractionation during methane metabolism: 

Analytical Chemistry, v. 40, p. 1883-1877. 

Smith, J.W., and Robb, W.A., 1973, Aragonite and the genesis of 

carbonates in Mahogany zone oil shales of Colorado's 

Green River Formation: U.S. Bureau of Mines Report 7727, 

21 p. 

Smith, R.L., and Oremland, R.S., 1987, Big Soda Lake (Nevada). 2. Pelagic sulfate reduction: Limnology and Oceanography, v. 32, p. 794-803. 

Tissot, B.P., Deroo, G., and Gooda, A., 1978, Geochemical study 

of the Uinta Basin-Formation of petroleum from the Green 

River Formation: Geochimica et Cosmochimica Acta, v. 42, 

p. 1469-1486. 

Tuttle, M.L., and Goldhaber, M.B., in press, Sedimentary sulfur 

geochemistry of the paleogene Green River Formation, 

western United States; Implications for interpreting depositional and diagenetic processes in saline alkaline lakes: 

Geochimica et Cosmochimica Acta. 

Vogel, T.M., Oremland, R.S., and Kvenvolden, K.A., 1982, Low 

temperature formation of hydrocarbon gases in San Francisco Bay sediment (California, USA): Chemical Geology, 

v. 37, p. 289-298. 

Walker, K.F, 1974, The stability of meromictic lakes in central 

Washington: Limnology and Oceanography, v. 19, p. 209-

222. 

---1975, The seasonal phytoplankton cycles of two saline 

lakes in central Washington: Limnology and Oceanography, 

v. 20,p.40-53 

Ward, D.M., and Winfrey, M.R., 1985, Interactions between 

methanogenic and sulfate-reducing bacteria in sediments: 

Advances in Aquatic Microbiology, v. 3, p. 141-179. 

Welhan, J.A., and- Craig, H., 1979, Methane and hydrogen in 

East Pacific Rise hydrothermal fluids: Geophysical Research 

Letters, v. 6, p. 829-831. 

Whelan, J.K., Oremland, R.S., Tarafa, M., Smith, R.L., Howarth, 

R., and Lee, C., 1986, Evidence for sulfate reducing and 

methane producing microorganisms from sites 618, 619, and 

622, in Buoma, A., and others eds., Initial reports of the 

Deep Sea Drilling Project, v. 96: Washington, D.C., U.S. 

Government Printing Office, p. 767-775. 

Whiticar, M.J., Faber, E., and Schoell, M., 1986, Biogenic methane 

formation in marine and freshwater environments-C02 reduction vs. acetate fermentation-isotope evidence: Geochimica et Cosmochimica Acta, v. 50, p. 693-709. 

Whittenbury, R., Phillips, K.C., and Wilkenson, J.F., 1970, Enrichment, isolation, and some properties of methane-utilizing 

bacteria: Journal of General Microbiology, v. 61, p. 205-218. 

Winfrey, M.R., 1984, Microbial production of methane, in Atlas, 

R.M., ed., Petroleum microbiology: New York, Macmillan, 

p. 153-219. 

Woese, C.R., and Fox, G.E., 1977, Phylogenetic structure of the 

prokaryotic domain-The primary kingdoms: Proceedings of 

the National Academy of Sciences, U.S.A., v. 74, p. 5088-

5090. 

Wolfe, R.S, 1971, Microbial formation of methane: Advances in 

Microbial Physiology, v. 6, p. 107-146. 

---1992, Biochemistry of methanogenesis, in Danson, M., 

Rought, D., and Lunt, G., eds., The Archaebacteria-Biochemistry and biotechnology: Biochemical Society Symposium 58, Portland Press, London, p. 41-50. 

Zehr, J.P., Harvey, R.W., Oremland, R.S., Cloern, J.E., George, 

L.H., and Lane, J.L., 1987, Big Soda Lake (Nevada). 1. Pelagic bacterial heterotrophy and biomass: Limnology and 

Oceanography, v. 32, p. 781-793. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

A Comparison of Hydrocarbon Gases from Natural Sources in 

the Northwestern United States 

By Thomas D. Lorenson1 and Keith A. Kvenvolden1 

CONTENTS 

Abstract ......................................................................... 453 

Introduction ... .. .. .. .. .. .. .. . .. . ... ... . .. ... .. .. .. . . . ... . . .. ... .. . ... .. . .. .. . . 454 

Sampling Techniques and Methods of Analysis .......... 454 

Results and Discussion ................................................. 455 

Northwestern Wyoming ......................................... 456 

Yellowstone National Park .............................. 457 

Cody, Wyoming, Area ..................................... 460 

Rattlesnake Mountain Anticline ................ 460 

Absaroka Range .. .. ... . .. .... .. . . .. . .. . ... . .. .. .. ... . . 463 

Grand Teton National Park and Vicinity ....... 463 

Teton-Bridger Wilderness .............................. 466 

Wind River Range ........................................... 466 

Overthrust Belt in Wyoming ......................... 466 

The Northwestern Great Basin and the 

Olympic-Wallowa Lineament ............................... 466 

The Cascade Volcanoes of Northern California .... 467 

Southwestern Oregon ........................................... 467 

Northwestern Washington .................................... 468 

Summary ....................................................................... 469 

References Cited . .. ..... .. .. .. .... .. . . .. .. .. .. .... ... ... . . .. .. . .. . .. . . . .. . . 469 

ABSTRACT 

The northwestern United States hosts a remarkable 

quantity and variety of thermal springs, seeps, and other 

natural-gas sources. Although many studies have dealt with 

the liquids and nonhydrocarbon gases emanating from 

1

U.S. Geological Survey, MS 999, 345 Middlefield Rd., Menlo 

Park, CA 94025. 

these sources, few have focused on hydrocarbon gases. Of 

these gases, methane in particular is now recognized as an 

important reactive trace gas in the Earth's atmosphere that 

plays a significant role in global warming because of its 

greenhouse properties. To understand better the magnitude 

and occurrence of emissions of hydrocarbons from natural 

sources to the atmosphere, we have begun a survey of 

these gases throughout the northwestern United States. 

This area encompasses a number of different tectonic provinces: the Yellowstone hot spot, the northern Basin and 

Range Province, the Cascade volcanic arc, and the Cascadia subduction complex. Each province hosts springs and 

seeps with some unique compositions owing to the geological processes operating there. Methane is present in each 

area at concentration levels ranging from about 2 parts per 

million by volume (ppm-v) to 95.6 percent (by volume). 

Hydrothermal activity in the Yellowstone area produces 

spring gases containing less than 4 percent methane, with 

carbon dioxide as the balance gas. The Grand Teton National Park area, immediately to the south, has a wide variety of gas compositions with either methane, carbon 

dioxide, or nitrogen as the primary gas component. Where 

methane is abundant, higher molecular weight hydrocarbon 

gases (ethane, ethene, propane, propene, isobutane, and nbutane) are also found in ppm-v concentrations. In the 

northern Great Basin, thermal springs and seeps typically 

occur along fault zones at the base of mountain ranges. 

Methane concentrations range from 0.2 to 47 percent, with 

higher molecular weight hydrocarbon concentrations from 

0 to 3,100 ppm-v. Areas covered by the Cenozoic Columbia River Basalt Group and the basalts of the Snake River 

Plain continue to have high heat flow and produce thermal 

springs and seeps, often located along fault zones. The 

compositions and concentrations of hydrocarbon gases 

from these areas are similar to those of gases from the 

453 
454 THE FUTURE OF ENERGY GASES 

northern Great Basin. Gases from the southern Cascade 

volcanic arc (Mount Shasta and Mount Lassen) are composed typically of carbon dioxide, with minor amounts of 

methane (less than 1.2 percent); however, some fumaroles 

at Mount Lassen have minor quantities of higher molecular 

weight hydrocarbon gases. Along the Pacific coast, melanges of the Cascadia subduction complex host many 

seeps and springs. In some seeps the gas consists almost 

exclusively of methane (94.3 to 99.9 percent, normalized 

to total hydrocarbon gases) with amounts of higher molecular weight hydrocarbon gases ranging from about 5 ppmv to 3.5 percent. In southwestern Oregon, melanges and 

forearc basinal turbidites and deltaic sandstones with lowgrade coal seams contribute methane and some higher 

molecular weight hydrocarbon gases to the headspace of 

shallow water wells and exploration wells. Methane and 

some higher molecular weight hydrocarbon gases are emitted directly into the atmosphere by passive diffusion from 

outcrops. Methane concentrations from the wells range 

from 27 ppm-v to 95.6 percent, and higher molecular 

weight hydrocarbon concentrations range from not detectable to 119 ppm-v. In each of the tectonic provinces, the 

different gas compositions reflect the different processes 

involved in gas generation. 

INTRODUCTION 

Seeps of natural gas rich in methane are often observed at the surface of the Earth. These seeps provide 

samples from which subsurface processes of gas generation can be inferred. Gas generation and subsequent release can have important effects on the global budget of 

methane, an important greenhouse gas. In addition, gas 

seeps rich in hydrocarbons can be a useful exploration tool 

for location of new oil and gas prospects. We have observed that natural-gas seepage takes many forms, from 

familiar fumaroles to more usual (or at least less obvious) 

manifestations, including gas leakage from shallow water 

wells and from rock outcrops. We can readily measure the 

gas composition of each of these gas sources, but measuring flux rates is much more difficult. Only rarely have we 

attempted to measure gas fluxes, and we do not address 

this issue in a quantitative way because of the paucity of 

observations. From the perspective of methane and higher 

molecular weight hydrocarbon contributions to the atmosphere, flux is an important issue. From the exploration 

angle, however, the relative concentration of gases above 

background levels is important because this kind of information can lead to identifying potential subsurface petroleum occurrence. 

The purpose of this study is to document the variety, 

nature, and geologic settings of natural-gas seeps in the 

northwestern United States. This is a continuing endeavor, 

and thus, the report represents our results up to this juneture. At this point we have studied four distinct geologic 

areas: (1) magma and associated hot fluids of an intercontinental hot spot rising through organic-rich sedimentary 

rocks in and near Yellowstone National Park, Wyoming; 

(2) areas of large-scale crustal extension and thinning in 

the Great Basin, where organic-rich sediments rapidly sink 

in basins and come in contact with thermal fluids; (3) deep 

subduction zones whose processes are manifested as gases 

arising from the Cascade volcanoes of northern California; 

and (4) two locations along the Pacific Ocean where subduction complexes and related sedimentary forearc basins 

have been accreted. In each of these settings sampling sites 

were located by one of two means: (1) use of published 

maps of geothermal resources in each state, denoting natural thermal springs and thermal wells; and (2) use of 

guides who have worked in particular areas and have noted 

features such as gassy springs, seeps, and domestic wells. 

Thus far only a small fraction of known sample sites have 

been sampled by us, and much remains to be done. 

This study focuses on the hydrocarbon gases, mainly 

methane (C1), and its saturated and unsaturated homologs, 

ethane (C2), ethene (C2: 1), propane (C3), propene (C3:1 ), 

isobutane (i-C4), normal butane (n-C4), and pentane (C5), 

together referred to as higher molecular weight hydrocarbons. No provisions were taken to correct for the very low 

solubilities of the hydrocarbon gases in water. Thus, our 

results represent the composition of the gas phase in the 

sample bottle at the time of sampling. These concentrations 

approximate the compositions of the natural seep gases. 

SAMPLING TECHNIQUES AND 

METHODS OF ANALYSIS 

Field sampling of spring and seep gases involved 

identifying trains of bubbles rising through water and then 

trapping the gas in glass containers. Gas samples were collected by water displacement in 350- and 250-mL glass 

bottles equipped with spring-loaded rubber and ceramic 

stoppers (Kvenvolden and Pettinga, 1989). Serum vials 

(1 00-mL glass bottles) capped with teflon -coated silicone 

crimp seals were also used. The sample bottles were filled 

with water from the seep site (natural spring water or river 

water) and inverted so that the mouth of the bottle was 

submerged. Gas was directed into the bottles by two different means. At exceptionally slow-bubbling sites (less 

than about 5 mL/min), a water-filled plastic 40-liter trash 

bag was anchored over the gas seep and allowed to fill 

with gas over a period of 1 to 4 hours. With the bag still 

under water, a small hole was pierced in the corner, allowing the gas to escape into an inverted collecting funnel and 

finally into the sample bottle. At seeps with sufficient gas 

flow, an il}verted funnel with plastic tubing was submerged in water and used to divert the bubbles directly 

into the sample bottle. Wherever the water was too shal-
A COMPARISON OF HYDROCARBON GASES FROM THE NORTHWESTERN UNITED STATES 455 

low, a water-filled bucket was used as a substitute. After 

the gas had filled the sample bottle, I mL of the bactericide Zephrine Chloride (I :750) was injected into the interior neck of the bottle, and then the bottle was sealed, 

leaving a small amount of sterilized water in the bottle to 

enhance the seal against leakage. The samples were stored 

in an inverted position at room temperature until analyzed. 

In southwestern Oregon, we concentrated on sampling 

gases from shallow private water wells and source-rock 

outcrops, as well as gases released by breaking up source 

rocks to allow the escape of adsorbed gases. In the first 

two cases, we used gas-sampling bags made of three laminated layers: an inert polyethylene liner, an impervious 

aluminum layer to prevent diffusion of gases through the 

bag, and a polyester outer coating. The bags are filled inside a sealed canister capable of holding a light vacuum, 

thus allowing sample gas to be drawn into the bag. They 

are equipped with septa, which allow insertion of a needle 

and withdrawal of sample gas without exposure to the atmosphere. Typically, water wells are equipped with a 

capped vent port from which we collected most of our gas 

samples. In wells that did not have a vent cap, the gases 

were in direct contact with the atmosphere. In both cases, 

however, the sampled gas was mixed with the atmosphere. 

Because hydrocarbon gases have low solubilities in water, 

we assume that nearly all of the hydrocarbon gases are 

released into the headspace of the well and that the ratios 

of the hydrocarbon gases collected reflect their ratios in 

nature. The amount of air contamination of the well headspace was not determined, and thus we consider the 

reported concentrations of the gases to be the minimum 

amount present. 

When sampling rock outcrops, we focused on joints or 

other natural fractures in the rock. Each location was widened by digging out debris with a rock pick. A gas sample 

was taken within 1 em of the fresh, exposed rock with 

either a gas-tight syringe or a gas bag. Severe air contamjnation was unavoidable, so the reported concentrations are 

much less than minimum concentrations leaking from the 

outcrop. 

To sample gas from nonweathered source rocks, we 

broke the rock sample into small pieces and immediately 

placed them into a septa-equipped, friction-sealed paint 

can. The headspace was purged with helium for 5 minutes, 

and then the adsorbed gases were allowed to collect in the 

headspace. We emphasize that not all of the gas in the 

source rock is extracted, and the concentration of the gas 

is not absolute. Nevertheless the ratios of hydrocarbon 

gases measured should reflect a reasonable estimate of the 

proportions of gases that are leaking into the atmosphere 

from these rocks exposed on the surface of the Earth. 

The samples were analyzed at three U.S. Geological 

Survey (USGS) laboratories (Palo Alto, Calif.; Menlo Park, 

Calif.; and Denver, Colo.) and at the petroleum geochemistry laboratory at Oregon State University (Corvallis, Oreg.). 

Gas chromatography was used to analyze the gases. The 

results are reported as parts per million by volume (ppm-v) 

and as percent (by volume) of the total gas mixture 

(tables 1-3) and of the total hydrocarbons (table 4). In addition, the gas wetness ratio (C 1/C2 ) and the isotopic composition of methane and carbon dioxide were also determined. 

Isotopic compositions of methane and carbon dioxide were 

determined by mass spectrometry at three laboratories: the 

USGS petroleum lab in Denver Colo.; BRG in Hanover, 

Germany; and Global Geochemistry Corp., Canoga Park, 

Calif. Results are reported in the 0 (permil) notation relative to the Peedee belemnite (PDB) standard: 

and relative to Standard Mean Ocean Water (SMOW): 

oD(permil)=(RsampiefRstandard-1 )xI o-3, where R=D/H 

RESULTS AND DISCUSSION 

Because the sampled seeps occur in a large region in 

the northwestern United States, and in many geologic 

provinces, we will discuss the composition and origins of 

these gases within the context of five geographic areas as 

shown in figure 1. The specific locations of sample sites 

are shown in figures 2 through 6. 

Each of the five geographic areas are discussed separately from east to west, and data from each area are presented in corresponding tables, where they are listed from 

east to west. Hydrocarbon compositions-and in some instances the isotopic composition of methane, ethane, and 

carbon dioxide-are listed in tables 1 through 4. The data 

CANADA 

USA 

MONT 

PACIFIC 

2 

WYO 

OCEAN 

Figure 1. The study areas in the northwestern United States. Geologic provinces are generalized. Numbered boxes show areas of 

figures 2 through 6. 
456 THE FUTURE OF ENERGY GASES 

in tables 1 through 3 are concentrations of hydrocarbon 

gas in the total gas mixture. The data in table 4 are gas 

concentrations relative to total hydrocarbon gases present. 

Many of the gas analyses include permanent gas concentrations, which are reported elsewhere as cited. Cross plots 

of these isotopic compositions developed by Schoell 

(1980) and Whiticar and others (1986) are shown in figures 7 and 8. Such views of isotopic composition help 

constrain the origins of the gases in question. 

NORTHWESTERN WYOMING 

In northwestern Wyoming gas seeps are common in 

and around Yellowstone and Grand Teton National Parks. 

Yellowstone National Park, in particular, has numerous 

gas seeps manifest as bubbling hot springs. A number of 

previous studies have provided information on gas compositions (Gunter and Musgrave, 1966, 1971; Gunter, 1978; 

Nehring and Truesdell, 1978; Des Marais and others, 

1981 ; Truesdell and Thompson, 1982). Outside Yellowstone National Park, there apparently has been less interest 

in gas-seep compositions. A preliminary report by KvenF-- ' 

0 

..c 

co 

:Q 

1 

\ I 

-~ 

I 

t I 

Jackson 

Lake 

Teton 

Nat' I 

Park 1-23 

. "'~ . ~ ... 1-26 1'-22 

~ 1-25 

Wyoming 

Dubois 

~ "0' }?,· 

'"er Basin 

L______o_____.J 

20 KM 

Figure 2. Sample locations in northwestern Wyoming. Prefix 

"1-" in sample site number indicates that analysis of sample is 

reported in table 1 (sample numbers are listed without prefix in 

table). 

volden and others (1989b) compared the molecular and 

isotopic compositions of 10 gas seeps sampled in 1988: 2 

in Yellowstone National Park, 7 in Grand Teton National 

Park, and 1 outside the national park boundaries. That report demonstrated that compositions of seep gases in Yellowstone National Park are dominated by C02, whereas in 

the Grand Teton National Park, C1 and N2 are the principal gases. Concentrations of the higher molecular weight 

hydrocarbon gases in both areas are highly variable. 

In order to expand our understanding of the compositions of naturally occurring gas in seeps in northwestern 

Wyoming, Lorenson and others ( 1991) resampled in 1989 

and 1990 most of the sites visited in 1988 by Kvenvolden 

and others (1989b). Additional samples were obtained in 

the Teton-Bridger Wilderness area and in the area between 

Yellowstone National Park and the city of Cody, Wyoming 

!!' 

ol: ut~ 

Malheur 

Lake 

2-7• 

2-8• 

ALVORD 

DESERT 

.... .... .... 

20 KM 

Figure 3. Sample locations in Idaho and eastern Oregon. Prefix 

"2-" in sample site number indicates that analysis of sample is 

reported in table 2 (sample numbers are listed without prefix in 

table). 
A COMPARISON OF HYDROCARBON GASES FROM THE NORTHWESTERN UNITED STATES 457 

(fig. 2). In all we sampled seeps in six geographic areas: 

(I) Yellowstone National Park; (2) the Cody, Wyo., area, 

which includes the Rattlesnake Mountain Anticline and the 

Absaroka Range; (3) Teton National Park and vicinity; (4) 

Teton-Bridger Wilderness at the northwest end of the 

Washakie Range (Love and Christiansen, 1985) along the 

North Buffalo Fork Thrust Fault; (5) uplifted Paleozoic 

rocks along the margins of the Wind River Range; and (6) 

Klamath 

Falls 

Goose Lake 

graben .....__ 

Oregon 

California 

2

_

12 . MTLASSEN 

'2-13 Susanville o 

~ 

20 KM 

~akeview 

' ----,---·-·-

2-9: ro • I "0 

ro 

> 

Q) 

z 

Figure 4. Sample locations in south-central Oregon and northern 

California. Prefix "2-" in sample site number indicates that analysis of sample is reported in table 2 (sample numbers are listed 

without prefix in table). 

c_____..______j 

20 KM 

Figure 5. Sample locations in southwestern Oregon. Prefix "3-" 

in sample site number indicates that analysis of sample is reported in table 3 (sample numbers are listed without prefix in table). 

the overthrust belt in Wyoming. Sample sites are shown in 

figure 2, and our results are reported in table 1. 

YELLOWSTONE NATIONAL PARK 

(SAMPLE SITES 1-1 THROUGH 1-16) 

Yellowstone National Park and the Absaroka Range to 

the east are located in a region of Tertiary volcanic activity. 

The evolution of the Yellowstone volcanic province has 

been discussed by Smith and Christiansen (1980) and Smith 

and Braile (1982). Volcanic rocks as old as early Eocene 

cover Paleozoic and Mesozoic strata that were folded, uplifted, and eroded during the Cretaceous Laramide Orogeny. 

Small packages of the pre-Tertiary rocks are inferred by 

Destruction o 

Island 

PACIFIC 

OCEAN 

EXPLANATION 

6 Gas or oil seep 

-¢- Exploratory well with 

gas show 

20 KM 

Lake 

Cr

~ 

escent c;-::::, 

gas seep 

Washington 

Figure 6. Sample locations in northwestern Washington. Prefix 

"4-" in sample site number indicates that analysis of sample is 

reported in table 4 (sample numbers are listed without prefix in 

table). 
458 THE FUTURE OF ENERGY GASES 

Table 1. Composition of hydrocarbon gas from northwestern Wyoming. 

[nd, none detected; ppm·v, parts per million by volume;---. not determined] 

Figure Sample No. Name of sample site 

2 Wahb Springs 

2 2 Putrified Forest 

2 3 The Mushpots, south area 

2 3 The Mushpots, north area 

2 4 Hot Spring Basin, site A, south area 

2 4 Hot Spring Basin, site C, northwest area 

2 4 Hot Spring Basin, site B, southwest area 

2 5 Rainbow Springs 

2 6 Tower Falls South 

2 7 Calcite Springs south vent, site I 

2 7 Calcite Springs south vent, site 2 

2 7 Calcite Springs north vent 

2 7 Calcite Springs middle vent 

2 7 Calcite Springs middle vent 

2 8 Rainy Lake 

2 9 Tower Bridge SE (site I) 

2 9 Tower Bridge NW (site 2) 

2 10 Washburn Hot Springs 

2 10 Jade Hot Springs (vent) 

2 II Clear Lake 

2 12 Sulphur Springs 

2 13 Witch Creek, Heart Geyser Basin 

2 14 Huckleberry Hot Springs 

2 15 Phantom Fumarole 

2 16 Firehole River, northern Lower Geyser Basin 

2 17 De Maris Hot Springs, east vent 

2 17 De Maris Hot Springs, east vent 

2 17 De Maris Hot Springs, east vent 

2 17 De Maris Hot Springs. middle vent 

2 17 De Maris Hot Springs, west vent 

2 17 De Maris Hot Springs, west vent 

2 17 De Maris Hot Springs, westernmost vent 

2 18 Cedar Mountain vent 

2 19 Sulphur Lake 

2 20 Sweetwater Mineral Springs 

2 20 Sweetwater Mineral Springs 

2 20 Sweetwater Mineral Springs 

seismic data (Lehman and others, 1986; Smith and Braile, 

1982), stratigraphic interpolations (Tonnsen, 1982), and regional mapping (Prostka and others, 197 5) to underlie volcanic rocks in the north section of the park. Buried 

prevolcanic sedimentary rocks may act as a hydrocarbon 

source for gases and petroleum found in springs hosted by 

volcanic rock. 

Carbon dioxide is by far the dominant gas in the sampled seeps of Yellowstone National Park. Abundances 

vary from nearly 97 percent at Calcite Springs to 80 percent at Jade Hot Springs (Lorenson and others, 1991 ). 

These amounts are typical of hydrothermal areas (White, 

1957; Lyon and Hulston, 1984). Methane, although much 

Sample date Latitude Longitude Methane Ethane 

(N.) (W.) (ppm-v) (ppm-v) 

Yellowstone 

Jul-90 44° 49.75 110° 06.90 2040.00 41.70 

Jul-90 44° 50.48 1100 09.81 27870.00 1141.40 

Mar-91 44° 38.03 110° 13.38 7590.00 126.20 

Mar-91 44° 38.50 110° 13.45 12180.00 118.20 

Oct-90 44° 44.63 110° 14.95 1490.00 24.62 

Oct-90 44°45.11 110° 15.60 11140.00 301.30 

Oct-90 44° 44.06 110° 15.61 11800.00 128.11 

Oct-90 44° 46.14 110° 16.25 39680.00 2225.00 

Jul-90 44° 53.71 110° 22.60 30900.00 1271.24 

Jul-89 44° 54.28 110° 23.67 89.70 2.26 

Jul-90 44° 54.28 110° 23.67 920.00 29.88 

Jul-89 44° 54.36 110° 23.70 39.00 nd 

Jun-88 44° 54.31 110° 23.73 5800.00 36.00 

Jul-90 44° 54.31 110° 23.73 375.00 105.53 

Jul-90 44° 54.53 110° 24.11 3000.00 93.00 

Jul-90 44° 55.18 110° 24.22 6320.00 60.95 

Jul-90 44° 55.28 110° 24.30 7130.00 67.95 

Jul-89 44° 45.90 110° 25.75 3600.00 62.00 

Jul-89 44° 45.57 1 we 26.25 3230.00 58.45 

Aug-90 44° 42.84 110° 28.70 1110.00 5.43 

Aug-90 44° 39.34 110° 28.96 680.00 0.06 

Oct-90 44° 17.34 110° 31.02 39900.00 113.00 

Jul-90 44° 06.90 110° 41.00 10.77 nd 

Aug-90 44° 14.42 110° 43.43 750.00 1.31 

Aug-90 44° 37.20 110° 51.71 32780.00 227.70 

Cody, Wyo., 

Jul-89 44° 30.58 109° 06.58 2690.00 100.80 

Jul-90 44° 30.58 109° 06.58 3070.00 101.58 

Jul-89 44° 30.56 109° 06.60 2410.00 90.95 

Jul-90 44° 30.56 109° 06.60 3130.00 117.36 

Jul-89 44° 30.54 109° 06.66 1360.00 58.50 

Jul-90 44° 30.54 109° 06.66 1590.00 65.80 

Jul-90 44° 30.53 109° 06.69 770.00 32.98 

Jul-90 44° 29.73 109° 11.61 650.00 7.56 

Jul-89 44° 40.32 109° 37.13 1060.00 nd 

Jun-88 44° 30.25 109° 39.02 6700.00 126.00 

Jul-89 44° 30.25 109° 39.02 5400.00 121.80 

Ju1-90 44° 30.25 109° 39.02 5860.00 113.40 

less important in total volume of gas released from Yellowstone seeps and fumaroles, is ubiquitous. Methane 

concentration ranged from 10.8 ppm-vat Huckleberry Hot 

Springs to about 4 percent at two separate locations: 

Witch Creek and Rainbow Springs. Rainbow Springs is a 

known locality of petroleum seepage and was described 

by Love and Good (1970), and the oil has been analyzed 

by Clifton and others ( 1990). Higher molecular weight 

hydrocarbon gases can also be found in relative abundance throughout the park. Maximum concentrations were 

found at Rainbow Springs. 

The isotopic composition of gases from the park are 

plotted in figures 7 and 8. It is interesting to note (fig. 7) 
A COMPARISON OF HYDROCARBON GASES FROM THE NORTHWESTERN UNITED STATES 459 

Ethene Propane Propene 

(ppm-v) (ppm-v) (ppm-v) 

National 

nd 8.74 

nd 448.63 

nd 10.22 

nd 7.78 

nd 14.57 

nd 80.38 

nd 13.78 

nd 658.90 

nd 471.40 

nd 1.32 

nd 7.28 

0.01 0.76 

1.00 11.00 

nd 26.10 

nd 18.45 

nd 8.18 

nd 8.96 

0.20 16.00 

nd 14.45 

nd 0.50 

nd 0.00 

nd 21.53 

0.08 0.00 

0.41 0.00 

nd 51.02 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

0.06 

nd 

0.90 

nd 

nd 

Area 

0.81 

0.88 

0.71 

0.91 

0.64 

0.71 

0.36 

2.06 

0.02 

63.00 

67.37 

91.36 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

2.10 

nd 

2.02 

nd 

nd 

nd 

nd 

0.06 

nd 

0.14 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

Isobutane 

(ppm-v) 

Park 

0.74 

93.40 

0.30 

0.28 

0.66 

10.74 

0.73 

59.80 

94.17 

0.00 

0.74 

nd 

1.70 

3.20 

1.33 

0.85 

0.84 

1.90 

1.23 

nd 

nd 

2.99 

nd 

nd 

5.86 

0.87 

0.94 

0.68 

0.84 

0.51 

0.57 

0.33 

0.30 

nd 

17.00 

15.50 

25.06 

n-butane 

(ppm-v) 

1.45 

146.90 

0.40 

0.12 

0.60 

14.22 

0.52 

119.70 

124.85 

0.15 

1.43 

nd 

2.80 

5.55 

2.91 

1.23 

1.14 

3.20 

2.31 

nd 

nd 

4.34 

nd 

nd 

26.31 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

0.51 

nd 

32.00 

41.28 

47.36 

Pentanes 

(ppm-v) 

yes 

yes 

yes 

yes 

yes 

yes 

yes 

yes 

yes 

yes 

yes 

yes 

nd 

yes 

yes 

yes 

yes 

nd 

yes 

nd 

nd 

yes 

yes 

nd 

yes 

nd 

yes 

nd 

yes 

nd 

yes 

yes 

yes 

nd 

nd 

yes 

yes 

that the carbon isotopic composition of C02 in Yellowstone 

seeps is relatively consistent, with values ranging from -5 

to +0.5 permil. The carbon isotopic composition of methane is more variable and ranges from -23.8 to -59.2 permil, indicating more variable sources. The preponderance 

of values plotted in figure 7 reflect a high temperature of 

formation for C1 and C02 as indicated by the low fractionation factor of carbon between C02 and methane ( ac clusters at about 1.02). Such values are considered typical of 

geothermal monocarbon gases (Lyon and Hulston, 1984). 

Wahb Springs (sample site 1-1, fig. 2), in the northeast 

comer of the park, however, widely departs from this pattern. The carbon isotopic composition of this seep plots on 

Methane/Ethane 

(C1/C2) 

49 

24 

60 

103 

61 

37 

92 

18 

24 

40 

31 

161 

4 

32 

104 

105 

58 

55 

204 

11333 

353 

573 

144 

27 

30 

26 

27 

23 

24 

23 

86 

53 

44 

52 

bl3C(CH4) 

(permil) 

-59.2 

-32.4 

-30.3 

-39.8 

-26.0 

-32.5 

-47.0 

-47.0 

-32.0 

-31.9 

-28.8 

-24.9 

-41.0 

-30.7 

-23.8 

-34.0 

-43.6 

-43.5 

bD(CH4) 

(permil) 

-200.0 

-186.0 

bl3C(C0z) 

(permil) 

-3.1 

-1.0 

-3.1 

-3.8 

-5.8 

-0.5 

-0.5 

-0.5 

-1.6 

-2.2 

-0.4 

-2.3 

0.5 

-2.1 

-0.9 

-5.0 

-1.9 

-10.7 

-4.9 

-3.1 

-12.0 

-2.1 

-1.5 

b 13C(C2H6 ) 

(permil) 

-20.3 

-22.2 

-26.1 

Table continued on next page. 

the border of the carbonate reduction and methyl (acetate) 

fermentation fields, indicating a bacterial source for the 

methane. This result is very surprising because this seep is 

near a hydrothermal area named Death Gulch, so christened 

by early explorers for the suffocating and deadly fumes 

primarily of C02. 

The isotopic compositions of methane carbon and hydrogen from two sites, Calcite Springs and Rainbow 

Springs, are plotted as open circles in figure 8 and fall in 

the geothermal-hydrothermal range. These values, in conjunction with the inclusion of low C1/C2 values and the 

presence of liquid hydrocarbons, indicate a mixture of geothermal-hydrothermal methane and thermogenic methane. 
460 THE FUTURE OF ENERGY GASES 

Table 1. Composition of hydrocarbon gas from northwestern Wyoming-Continued. 

Figure Sample No. Name of sample site 

2 21 Halfmoon Lake pond 

2 21 Halfmoon Lake pond 

2 22 Teton Valley Warm Springs, west vent 

2 22 Teton Valley Warm Springs, center vent 

2 22 Teton Valley Warm Springs, east vent 

2 23 Kelly Warm Spring 

2 23 Kelly Warm Spring 

2 23 Kelly Warm Spring 

2 23 Kelly Warm Spring 

2 23 Kelly Warm Spring 

2 23 Kelly Warm Spring 

2 23 Kelly Warm Spring 

2 24 Jackson Lake Hot Spring, seep 2 

2 24 Jackson Lake Hot Spring, seep I 

2 24 Jackson Lake Hot Spring, seep 3 

2 24 Jackson Lake Hot Spring, spring site 

2 24 Jackson Lake Hot Spring. seep 4 

2 25 Fish Hatchery Spring 

2 26 Abercrombie Warm Springs 

2 27 Soda Springs, seep 2 

2 28 Junction Springs. south seep 

2 28 Junction Springs, north seep 

2 29 Tom Spring 

2 30 Whetstone gas seep 

2 31 Little Warm Springs 

2 32 Warm Springs Creek Springs 

2 33 Kendall Warm Springs 

2 34 Johnson Hot Springs 

2 35 Auburn Hot Springs 

The thermogenic methane and other hydrocarbons likely 

result from pyrolysis of buried sedimentary organic matter. 

Upward circulation of groundwater carry these products to 

the vent sites. 

CODY, WYOMING, AREA 

RATTLESNAKE MOUNTAIN ANTICLINE 

(SAMPLE SITES 1-17, 1-18) 

Gas seeps at De Maris Hot Springs provide a good 

example of systematic areal changes in concentrations of 

hydrocarbon gases as well as other gases. From east to 

west, corresponding to an increase in depth within the 

Phosphoria Formation, the following increases in concentrations were noted by Lorenson and others (1991): C02 

from 65.2 to 80.0 percent, 613C of C02 from -9.2 permil 

Sample date Latitude Longitude Methane Ethane 

(N.) (W.) (ppm-v) (ppm-v) 

Grand Teton National 

Jun-88 43° 49.53 110° 25.75 945000.00 185.00 

Jul-90 43° 49.53 110° 25.75 949200.00 32.00 

Jun-89 43° 37.45 110° 36.29 65.00 nd 

Jun-89 43° 37.45 110° 36.30 23.00 nd 

Jun-89 43° 37.45 110° 36.30 40.00 nd 

Jul-88 43° 38.35 110° 36.90 600.00 4.00 

Jun-89 43° 38.35 110° 36.90 1170.00 nd 

Jul-90 43° 38.35 110° 36.90 3.20 nd 

Oct-90 43° 38.35 110" 36.90 13.67 nd 

Oct-90 43° 38.35 110° 36.90 1.96 nd 

Oct-90 43° 38.35 110° 36.90 2950.00 nd 

Oct-90 43° 38.35 110° 36.90 14.92 nd 

Jul-88 43° 57.68 110° 41.68 837000.00 16.00 

Jul-88 43° 57.53 110° 41.70 205000.00 37.00 

Jul-88 43° 57.72 110° 41.70 186000.00 34.00 

Jun-89 43° 57.72 110" 41.70 138000.00 45.13 

Jul-88 43° 57.75 110° 41.70 76000.00 12.00 

Jul-90 43° 32.45 110° 43.50 2.30 nd 

Jul-90 43° 32.60 110° 44.50 37050.00 0.13 

Teton Bridger 

Jun-89 43° 54.57 110° 10.68 240.00 nd 

Jun-89 43° 54.07 110° 12.27 4570.00 0.46 

Jun-89 43° 54.07 110° 12.28 3010.00 0.54 

Jul-89 43° 53.90 110° 12.32 21.00 nd 

Jul-90 43° 56.65 110° 25.68 690500.00 39.80 

Wind 

Jul-90 43° 31.19 109° 40.12 21.10 0.09 

Jul-90 43° 33.62 109° 43.88 11.60 nd 

Jul-90 43° 16.9.3 110° 01.16 2.55 nd 

Wyoming 

Aug-90 42° 49.00 110° 59.80 3320.00 11.89 

Aug-90 42° 49.70 110° 59.90 51960.00 244.00 

to -5.7 permil, and temperature from 27°C to 36°C. The 

following decreases were observed: N 2+Ar+02 from 28.7 

to 9 percent, cl from 2,690 to 1,357 ppm-v, c2 from 

100.8 to 58.5 ppm-v, c 3 from 0.81 to 0.64 ppm-v, C3:1 

from trace amounts to not detected, and i-C4 from 0.87 to 

0.51 ppm-v. Water analysis by others (Wyoming State Lab 

No. 7-1571 and 1572 (1976)), reported in Breckenridge 

and Hinckley (1978), also showed increases in common 

cations and anions from east to west. The sharp increase in 

water temperature from 2rc to 36°C over about 20 m of 

stratigraphic section is difficult to explain. However, the 

temperature increase with a concomitant increase in solubility of ionic species accounts for most of the previously 

noted changes in chemistry. 

The highest concentrations of hydrocarbon gases were 

found at the easternmost spring, which has the lowest temperature and C02 concentrations. The ratios of C 1/C2 are 

nearly equal at each seep (ranging from 23 to 30), supporting 
A COMPARISON OF HYDROCARBON GASES FROM THE NORTHWESTERN UNITED STATES 461 

Ethene Propane Propene 

(ppm-v) (ppm-v) (ppm-v) 

3.10 

1.70 

nd 

nd 

nd 

0.40 

nd 

nd 

nd 

nd 

nd 

nd 

4.50 

1.20 

1.10 

nd 

0.70 

nd 

0.13 

0.24 

nd 

0.12 

nd 

2.70 

nd 

nd 

nd 

Park 

1.70 

nd 

nd 

nd 

nd 

2.70 

nd 

nd 

nd 

nd 

nd 

nd 

4.50 

1.20 

l.JO 

nd 

0.70 

nd 

nd 

Wilderness 

nd 

0.13 

nd 

nd 

0.74 

and 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

River Range 

nd 

nd 

nd 

nd 

nd 

nd 

Isobutane 

(ppm-v) 

n-butane 

(ppm-v) 

vicinity 

0.40 

nd 

nd 

nd 

nd 

0.60 

nd 

nd 

nd 

nd 

nd 

nd 

1.80 

0.40 

0.40 

nd 

0.20 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

0.60 

nd 

nd 

nd 

nd 

0.90 

nd 

nd 

nd 

nd 

nd 

nd 

0.90 

0.40 

0.30 

nd 

0.20 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

overthrust belt 

nd 

0.09 

0.99 

27.98 

nd 

nd 

nd 

2.00 

0.05 

2.82 

Pentanes 

(ppm-v) 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

yes 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

nd 

yes 

nd 

nd 

nd 

nd 

nd 

nd 

yes 

nd 

yes 

yes 

the notion of a common, finite hydrocarbon gas source; 

different sources would likely produce distinct C1/C2 ratios. 

The western spring contains C02 at the highest concentrations and hydrocarbons at the lowest concentrations. This 

observation suggests that the hydrocarbon gas fractions are 

increasingly diluted by C02 released from the parent hydrothermal water. The b13C values for C02 of -9.2 permil (west 

spring) and -5.7 permil (middle spring) can be explained as 

mixing of C02 derived from carbonate (b13C=0 permil) and 

C02 derived from the oxidation of oil (b13C=-28 permil) 

(Faure, 1977). 

Heasler (1982) modeled the Cody hydrothermal system 

and determined that the groundwater flow was from west to 

east and that fluids in the Phosphoria Formation reached a 

maximum temperature of 46°C at a depth of 1.7 km. The 

maximum temperature occurs in a synform southwest of 

the Rattlesnake Mountain Anticline with an associated 

northeast groundwater flow toward the springs. This model 

Methane/Ethane 

(C1tc2) 

5108 

29663 

150 

52313 

5541 

5471 

3058 

6333 

285000 

9935 

5574 

17349 

234 

279 

213 

1)13C(CH4) 

(permi1) 

-49.7 

-50.1 

-50.4 

-61.2 

-61.9 

-59.8 

-59.8 

-59.2 

-55.6 

-41.9 

-70.8 

-58.7 

-30.5 

liD(CH4) 

(permil) 

-318.0 

-263.0 

-309.0 

-169.0 

-299.0 

1)13C(C02) 

(permi1) 

-6.1 

-5.1 

-17.9 

-18.6 

-11.3 

-10.8 

-9.4 

-8.1 

-6.6 

-17.9 

-10.4 

-8.8 

-9.0 

-9.4 

-2.2 

1)13C(C2H6) 

(permil) 

-10.0 

supports the possibility that the warm waters leach the oilrich Phosphoria Formation and so carry previously generated thermogenic hydrocarbons regionally from west to east, 

occasionally surfacing at springs. 

On the western side of the anticline, more hydrocarbonrich springs exist. John Colter's "boiling tar spring," described by Love and Good (1970), is now submerged under 

Buffalo Bill reservoir. When the water levels are low in 

winter, an ice-free region remains above the springs (approximately 20 m below the water surface) with gas bubbles 

smelling of hydrogen sulfide and sometimes leaving an oil 

slick where they burst (Doug Lumis, Bureau of Reclamation, 

oral commun., 1990). The springs appear to emerge from the 

Phosphoria Formation, as do De Maris Hot Springs, and 

presumably represent a more petroleum-rich source than do 

De Maris Hot Springs. We were able to locate a COz-rich 

gas vent alongside the reservoir in July I 990. Unfortunately, we were unable to get an uncontaminated gas sample, 
462 THE FUTURE OF ENERGY GASES 

Table 2. Composition of hydrocarbon gas from Idaho, eastern Oregon, and northern California. 

fnd, none detected~ ppm-v, parts per million by volume;---, not delermined] 

Figure Sample No. Name of sample site Sample date 

I Wi1dhorse Hot Springs, lD May-92 

2 Scintillation Hot Spring, OR Sep-89 

3 Snively Hot Spring, OR Sep-89 

4 Medical Hot Spring, OR Sep-89 

5 Hot Lake, OR Sep-89 

6 Island, Malhuer River, OR Aug-92 

7 Alvord Hot Springs, OR May-92 

8 Mid Borax Hot Spring, OR May-92 

Latitude 

(N.) 

44° 51.38 

43° 44.32 

43° 43.80 

45° 00.10 

45° 14.63 

43° 46.60 

42° 32.64 

42° 19.77 

Longitude 

(W.) 

Basin 

116° 49.80 

11r o9.95 

117° 12.30 

11r 30.78 

117° 52.50 

118° 02.80 

118° 32.03 

118° 36.26 

Methane 

(ppm-v) 

and 

21.00 

4100.00 

2100.00 

4800.00 

11900.00 

311.00 

760.00 

1680.00 

3 

3 

3 

3 

3 

3 

3 

3 

4 

4 

9 Benmac Hot Spring, CA (Surprise Valley) Sep-89 41°31.77 120° 04.82 51800.00 

10 Barry Ranch Hot Spring, OR Sep-89 42° 10.18 120° 20.01 473000.00 

Cascade 

4 

4 

4 

4 

II 

II 

12 

13 

Sulphur Springs, Mt. Shasta summit, CA 

Sulphur Springs, Mt. Shasta summit, CA 

Little Hot Springs Valley, Mt. Lassen, CA 

Sulphur Works, Mt. Lassen, CA 

May-92 

June-93 

Sep-89 

Feb-93 

41° 24.53 

41° 24.53 

40° 27.98 

40° 27.40 

121° 11.69 

121°11.69 

121° 31.78 

121° 32.50 

11870 

11490 

100.00 

120.00 

,.-., 

'§ 

<1.) 

8 

<1.) 

:'S! 

>< 

0 

'6 

c: 

0 

.D 

'-"' (.) 

u 

~ 

00 

20 

10 

0 

· 10 

·20 

-30 

-40 

-50 

· 100 -90 -80 -70 ·60 -50 

o13C methane (permil) 

EXPLANATION 

o Yellowstone National Park, Wyo. 

• Cody, Wyo. , area 

.o. Grand Teton National Park area, Wyo. 

-40 

• Spring ponds, Grand Teton National Park area, Wyo. 

• Overthrust belt, Wyo. 

-30 

+ Halfmoon Lake and spring, Grand Teton National Park, Wyo. 

·20 

Figure 7. Plot of carbon isotopic composition of methane versus 

carbon isotopic composition of carbon dioxide in samples from 

northwestern Wyoming. Compositional fields are adapted from 

Whiticar ( 1990). The values and the degree of isotopic separation, ac (C02:CH4 , defined as (o 13C<co2

J+l03)/(o13C<cH4l+l03), 

can be diagnostic of methanogenic microbial pathways, gas 

types, and temperatures of formation for geothermal gases. The 

large arrows labeled "Production" and "Oxidation" refer to methane. Values for selected areas referred to in text are plotted as 

separate symbols shown in explanation. Cluster of values from 

Yellowstone National Park near boundary of methane oxidation 

field is characteristic of geothermal gases. The cluster of values 

not included within a shaded field and with ac values greater 

than about 1.02 can be interpreted as thermogenic. 

-120 -.--------,..--or-------, 

-100 

;::::;--

'§ -80 ..... 

<l) 

0.. 

'---' 

<l) 

s:: 

ro -60 

.c 

.... 

<l) 

E 

u -40 <:<) 

C-0 

-20 

Abiogenic? 

0 Mantle? 

-450 -350 -250 -150 -50 

oD methane (permil) 

EXPLANATION 

0 Yellowstone National Park,Wyo. 

A. Grand Teton National Park area, Wyo. 

+ Spring ponds, Grand Teton National Park, Wyo. 

* Olympic Peninsula, Wash. 

Figure 8. Plot of carbon isotopic composition of methane versus 

hydrogen isotopic composition of methane from selected areas in 

Wyoming and Washington. Values for selected areas referred to 

in text are plotted as separate symbols shown in explanation. 

Compositional fields are adapted from Whiticar (1990). Field labeled "Artificial" refers to methane generated during drilling of 

hard crystalline rock. 
A COMPARISON OF HYDROCARBON GASES FROM THE NORTHWESTERN UNITED STATES 463 

Ethane Ethene Propane Propene lsobutane 

(ppm-v) (ppm-v) (ppm-v) (ppm-v) (ppm-v) 

Range and vicinity 

0.00 nd nd nd nd 

72.40 nd 33.60 nd 11.50 

0.76 nd nd nd nd 

3.79 nd 0.39 0.13 nd 

1429.00 nd 90.60 nd 52.50 

0.00 0.63 nd nd nd 

9.15 nd 1.81 nd 0.41 

20.97 nd 4.27 0.22 0.50 

367.00 nd 187.00 nd 36.80 

3142.00 nd 845.00 nd 520.00 

volcanoes 

nd nd nd nd nd 

nd nd nd nd nd 

0.64 nd 0.29 nd nd 

0.59 nd 0.02 nd nd 

because the vent was not under water. Analysis of the gas 

from this source revealed methane and higher molecular 

weight hydrocarbon gases, and indicates that this gas is 

similar to the gas from De Maris Hot Springs. 

ABSAROKA RANGE 

(SAMPLE SITES 1-19, 1-20) 

The seep gases of Sulphur Lake and those of Sweetwater Mineral Springs appear to have little in common. Sulphur Lake gas contains mainly nitrogen (83.7 percent), 

reflecting a meteoric water source, and a small amount of 

methane ( 1,100 ppm-v), most likely from microbial sources. 

The methane is probably generated by bacteria using fermentative pathways to digest organic matter in the lake bed. 

In contrast, the gases present at Sweetwater Mineral Springs 

are COz-rich (94.2 percent) and contain significant hydrocarbon gases. cl to at least c6 gases are present with concentrations of 5,860 ppm-v C1, 113 ppm-v C2, 91 ppm-v C3, 

25 ppm-v i-C4, and 47 ppm-v n-C4 to 41 ppm-v n-C4 (C5 

and C6 gases were not quantified). The values are similar to 

those observed in 1988 and 1989, suggesting that the source 

of these gases is not ephemeral in the scale of years. The 

()13C values of -43.5 permil for methane and -26.1 permil 

for ethane indicate that these gases are thermogenic. The 

613C values of -1.5 and -2.1 permil indicate that the C02 is 

most likely derived from the dissolution of carbonate rock. 

The sustained presence of higher molecular weight gases, 

coupled with C02 derived from carbonate dissolution, suggests that there is a nearby sedimentary source rock underlying the volcanic cover. It cannot be determined from the 

present data if the subsurface processes taking place here 

are similar to those operating at Calcite Springs and Rainbow Springs in Yellowstone National Park. 

n-butane 

(ppm-v) 

nd 

13.20 

nd 

nd 

3.08 

nd 

0.77 

1.61 

50.00 

161.00 

nd 

nd 

0.05 

nd 

Pentanes Methane/Ethane oi3qcf4) 

(ppm-v) (CJIC2) (permil) 

nd 

yes 57 

nd 2763 

yes 1266 

yes 8 -31.2 

nd 

nd 83 

yes 80 

yes 141 -47.7 

yes 151 -47.9 

nd 

nd 

yes 156 

nd 203 

GRAND TETON NATIONAL PARK AND VICINITY 

(SAMPLE SITES 1-21 THROUGH 1-26) 

The springs in and near the Grand Teton National Park 

are nearly all dominated by N2 gas, with a range in concentration from about 80 to 90 percent (Kvenvolden and 

others, 1989b; Lorenson and others, 1991). 0 2, C02, N2, 

and Ar are present in amounts characteristic of groundwater in recent contact with the atmosphere. Jackson Lake 

Hot Springs gas contained a notable amount of C02 (3.28 

percent). These waters are the warmest of the three sites 

(37°C measured at a nearby underwater vent having no 

apparent gas). Previously, temperatures of 72°C have been 

reported in this area by Love (Breckenridge and Hinckley, 

1978), and the seeps emerge from the Madison Limestone, 

a possible source for C02. C1 and C2 were the only hydrocarbon gases detected. The concentrations of these hydrocarbons were significant only at Jackson Lake Hot Springs 

(C1, 83.7 percent; C2, 45 ppm-v). Kelly Warm Spring and 

Teton Valley Warm Springs contained only C 1 ( 1, 172 and 

65 ppm-v, respectively). Three seeps were analyzed at 

Teton Valley Warm Springs, and C1 increased from 23 

ppm-v at the western seep, to 40 ppm-v in the main pond, 

to 65 ppm-v at the eastern seep. The increase in C1 corresponds to the flow direction of the spring's surface runoff. 

The carbon isotopic data from this area offer some 

potential insight into the generation processes of the hydrocarbon gases. The carbon isotopic composition of C 1 ranges 

from -49.7 permil at Halfmoon Lake to -61.9 permil at 

Jackson Lake Hot Springs seep 2, and the carbon isotopic 

composition of C02 ranges from -20.4 permil at Halfmoon 

Lake to -6.6 permil at Jackson Lake Hot Springs seep 4. The 

C1 isotopic values lie in a region of source ambiguity according to the criteria established by previous work (Claypool 
464 THE FUTURE OF ENERGY GASES 

Table 3. Composition of hydrocarbon gas from southwestern Oregon. 

[nd, none detected; ppm-v, parts per million by volume; ---. not determined] 

Figure Sample 

No. 

Name of sample site Sample 

date 

Southwestern 

5 Well gas in Sixes River melange and broken formation near Clarks Branch Creek, OR 

5 2 Gas sample from joint, Sixes River melange and broken formation near Clarks Branch Creek, OR 

5 2 Carboneceous mudstone in can, Sixes River melange and broken formation, near Clarks Branch Creek, OR 

5 3 Limestone in can from Sigfredon Quarry, Sixes River melange and broken formation, near Clarks Branch 

Creek, OR 

5 4 Well gas in Sixes River melange and broken formation, 1546 Clarks Branch Road, OR 

5 5 Joint in the Umpqua Group I, in the Bonanza thrust fault, near Umpqua, OR 

5 6 Well gas in the White Tail Ridge Formation2, 737 Nob Hill Rd., near Melrose, OR 

5 6 Well gas in the White Tail Ridge Formation2, 737 Nob Hill Rd., near Melrose, OR 

5 7 Well gas in the White Tail Ridge Formation2, 429 Elgarose Rd., near Melrose, OR 

5 8 Well gas in the Umpqua Group 1, Coles Valley, OR 

5 9 Well gas in the White Tail Ridge Formation2, 3591 Elgarose Rd., Melrose,OR 

5 10 Well gas in the White Tail Ridge Formation2, 17039 Hwy 42, Camas Valley, OR 

5 10 Well gas in the White Tail Ridge Formation 2, 17039 Hwy 42, Camas Valley, OR 

5 11 Joint in coal, White Tail Ridge Formation2, Hwy. 42, near Remote, OR 

5 12 Joint in coal, Coquille River Member3 of Whitetail Ridge Formation2, Hwy. 42, near Camas Valley, OR 

5 13 Well gas in Coaledo Formation, well 1, near Coquille, OR 

5 14 Well gas in Coaledo Formation, well 2, near Coquille, OR 

I Of Niem and Niem (1990). 

2White Tail Ridge Formation of Umpqua Group of Niem and Niem (1990). 

30f Ryu and others (1992). 

Table 4. Composition of hydrocarbon gas from northwestern Washington. 

Feb-93 

Feb-93 

Feb-93 

Feb-93 

Feb-93 

Jan-93 

Feb-93 

Mar-83 

Feb-93 

Feb-93 

Jan-93 

Feb-93 

Feb-93 

Feb-93 

Feb-93 

Feb-93 

Feb-93 

Latitude 

(N.) 

43° 05:88 

43° 06.36 

43° 06.36 

43° 06.82 

43° 05.12 

43° 19.76 

43° 15.43 

43° 15.43 

43° 15.82 

43° 21.94 

43° 15.93 

43° 02.86 

43° 02.97 

43° 00.16 

43° 00.50 

43° 09.40 

43° 09.28 

[Gas concentrations are normalized to methane, and isobutane and n-butane are combined. nd, none detected; ppm-v, parts per 

Figure Sample 

No. 

Name of sample site Sample date Latitude Longitude 

(W.) 

Methane 

(N.) (ppm-v) 

Olympic 

6 Sol Due Hot Springs. W A May-84. 47° 57.4 123° 43.8 999000 

6 2 Huelsdonk Ranch gas seep, W A May-85 47"48.0 124° 10.5 999000 

6 3 Pysht gas seep, W A I pre-74 48° 09.2 124° 27.3 943300 

6 4 Garfield gas mounds, W A May-85 47° 21.0 124° 35.1 999000 

6 5 Taholah gas seep. W A 2 77? 47° 21.1 124° 35.2 975500 

6 6 Wilson Ranch well, W A Jun-86 47" 54.6 124° 59.4 958000 

I Snavely (1987). 

2Rau and Grocock (1974). 

and Kaplan, 1974; Stahl, 1974; Fuex, 1977; Rice and Claypool, 1981; Schoen, 1983). Traditionally values of -60 permil and lighter are considered good evidence of microbially 

generated c1, whereas those values heavier than -50 permit 

indicate a thermogenic source (Schoell, 1983). Values in 

between are commonly interpreted as indicating mixtures 

from different sources. Recently several workers have focused on environments where o13C values of C1 are in this 

zone of ambiguity (Jenden and Kaplan, 1986; Whiticar and 

others, 1986; Woltemate and others, 1984). These studies 

have demonstrated the existence of microbially generated cl 

within this range of values. The differences in isotopic composition are attributed to differing contributions from the 

methanogenic pathways of C02 reduction and acetate (methyl) fermentation (Whiticar and others, 1986). A cross plot of 

o13C of C1 and 6D of C1 for Jackson Lake Hot Springs seep 

4, (fig. 7) indicates that the methane is generated by microbial acetate (methyl) fermentation processes. 
A COMPARISON OF HYDROCARBON GASES FROM THE NORTHWESTERN UNITED STATES 465 

Longitude Methane Ethane Ethene Propane Propene 

(W.) (ppm-v) (ppm-v) (ppm-v) (ppm-v) (ppm-v) 

Oregon 

123° 17.14 4380.00 0.61 nd 1.02 nd 

123° 17.23 23.13 

123° 17.23 8.68 1.37 nd 8.37 nd 

123° 18.90 30.14 0.79 nd 14.70 nd 

123° 20.25 502000.00 18.71 1.54 11.41 nd 

123° 26.39 2.41 

123° 28.74 761000.00 55.22 nd 12.43 nd 

123° 28.74 940000.00 32.00 

123° 29.10 21.93 0.00 nd 0.19 nd 

123° 29.54 27.44 nd nd nd nd 

123° 30.43 111200.00 119.40 nd 6.21 nd 

123° 39.66 87.00 

123° 39.68 5.72 

123° 42.70 480.00 0.43 nd 0.05 nd 

123° 53.99 300.00 0.27 nd 0.01 0.01 

124° 13.58 589600.00 275.49 nd 20.00 nd 

124° 13.66 11900.00 4.55 nd 0.18 nd 

million by volume; ---, not determined] 

Ethane Ethene Propane Propene Isobutane n-butane Pentanes 

(ppm-v) (ppm-v) (ppm-v) (ppm-v) (ppm-v) (ppm-v) (ppm-v) 

Peninsula 

510 nd nd nd nd nd nd 

5 nd nd nd nd nd nd 

35000 nd 15400 nd nd 4300 nd 

57 nd nd nd nd nd yes 

14800 nd 3700 nd nd 2200 yes 

27000 nd 9000 nd 120 180 yes 

The Halfmoon Lake spring area is underlain by subbituminous coal beds in the Bacon Ridge Sandstone (for detailed 

stratigraphy see Love and others, 1951, and for<} description 

of the seep, see Love and Love, 1983, and Antweiler and others, 1989). Blackstone (1989) has suggested that coal in the 

Bacon Ridge Sandstone may produce methane. Methane at 

the Halfmoon Lake gas seep has a concentration of 94.5 percent and may be derived in part from coal. At the Halfmoon 

Lake gas seep the carbon isotopic composition of C02 of -20 

Isobutane n-butane Pentanes Methane/Ethane oi3qcH4l I\D(CH4) 

(ppm-v) (ppm-v) (ppm-v) tc,.cz> (permil) (permil) 

nd nd yes 7228 

0.06 0.10 yes 6 

9.34 13.01 yes 38 

0.58 1.13 yes 26831 

0.56 0.01 yes 13780 -64.8 -245 

29375 -64.3 

0.65 0.01 yes 

nd nd nd 

3.79 0.02 yes 931 -46.3 -129 

0.04 0.01 yes 1106 

0.21 0.08 yes 1128 

0.25 0.10 yes 2140 

0.00 nd yes 2616 

Methane/Ethane l)l3C(CH4) l\D(CH4) 

(C1/C2) (penni!) (permil) 

1959 -36.5 -174 

199800 -51.6 -212 

27 -31.5 

17526 -34.5 -177 

66 

35 -34.7 -135 

penni! is light, much lighter than that of any other sample. 

This composition can be explained by the aerobk decomposition of organic matter such as algae and terrestrial plants by 

microbes, and the degassing of coal. The b13C of these substances falls within the isotopic range of -12 to -34 penni!; 

the b13C of coal averages about -25 permil (Faure, 1977). 

Dilution of near-surface groundwater by geothermal fluids possessing distinct carbon isotopic signatures is important for interpretation of the b13Ccco2

) values. Geothermal 
466 THE FUTURE OF ENERGY GASES 

waters in the Yellowstone region carry a characteristic carbon isotopic signature for C02 of roughly -2 to +2 permil, 

indicating that the carbon is derived principally from the 

dissolution of limestone in the area (dissolved atmospheric 

C02 with a &13C of -7 permil is also a possible source, but 

this source is effectively diluted by much greater amounts of 

geothermal C02 in most cases). Dilution of sampled gases 

by geothermally derived C02 is observed in the Jackson 

Lake Hot Springs gases, for which the &13C values of the 

C02 are intermediate between those from Yellowstone Park 

and those from Halfmoon Lake. This conclusion is supported by the fact that the Jackson Lake Hot Springs are the 

warmest of the seeps in the vicinity of the Grand Teton 

National Park and the Teton-Bridger Wilderness, and their 

overall C02 volumes are the highest, suggesting an important geothermal source. Addition of C02 from fermentation 

and respiration of organic matter by microbes to C02 from 

geothermal sources would likely result in &13C values intermediate between two end members, as are the isotopic values obtained at Jackson Lake Hot Springs. Numerous 

studies, including those of Jenden and Kaplan (1986), Whiticar and others (1986), and Woltemate and others (1984 ), 

have noted that the characteristic &D(cH4

) of <-250 permil is 

characteristic of C1 derived from fermentation. Finally, the 

molecular compositions of the hydrocarbon gases indicate 

microbial activity. C2:1 and C3:

1 are known to be produced 

by microbes (Davis and Squires, 1954; Vogel and others, 

1982), and the C/C2 ratios (3,400 to 41,000) are well above 

1 ,000, the guideline commonly used in denoting microbially 

generated cl. 

TETON-BRIDGER WILDERNESS 

(SAMPLE SITES 1-27 THROUGH 1-30) 

Compositions of gas from the springs of the TetonBridger Wilderness are quite diverse. Tom Spring is characterized by a very high concentration of C02 (98.5 percent) 

and only 20 ppm-v methane. The balance gases are N2, 0 2, 

and Ar (Lorenson and others, 1991). The N2/Ar ratio of 33 

and the N2/02 ratio of 2 suggest that dissolved air gases 

have been stripped by C02 (Bill Evans, oral commun., 

1990). The &13C value from C02 of -9.36 permil implies a 

mixed source of C02 from limestone and oxidized organic 

matter. The two sample sites at Junction Springs contain 

methane ranging in concentration from about 3,000 to 

4,600 ppm-v. The gas is very dry and most likely is derived 

from anaerobic microbial acetate (methyl) fermentation 

(fig. 7). 

The Whetstone gas seep lies near the crest of the Whetstone anticline. A substantial concentration of methane (69 

percent) is emitted from a series of small vents located in 

Pacific Creek. The coal-bearing Bacon Ridge Sandstone 

underlies this location and is considered to be a likely 

source for the gas. The isotopic composition of methane 

from this seep (&13C = -58.7 permil, &D = -299 permil) 

plots in the methyl fermentation field (fig. 7). 

WIND RIVER RANGE 

(SAMPLE SITES 1-31 THROUGH 1-33) 

We sampled three warm springs along the flanks of 

the Wind River Range. Each of the springs issues from 

inclined late Paleozoic strata. Little Warm Springs and 

Warm Springs Creek Springs are on the north side of the 

Wind River Range; Kendall Warm Springs lies on the 

south side of the range. The gases are composed mainly of 

N2 (Lorenson and others, 1991), and the C1 concentrations 

are very low, ranging from 2.55 to 21.1 ppm-v. The high 

N2 concentrations imply that the gases were recently in 

contact with the atmosphere. The lack of hydrocarbons indicates that the waters have not been in contact with thermogenic hydrocarbon sources and (or) the waters were not 

hot enough to leach and alter buried organic matter in 

rocks. 

OVERTHRUST BELT IN WYOMING 

(SAMPLE SITES 1-34, 1-35) 

We visited two sites near Afton, Wyoming: Auburn 

Hot Springs and Johnson Hot Springs. Both hot springs are 

fault-controlled and have built travertine mounds. The primary gas from both sites is C02. At Auburn Hot Springs 

cl concentration is about 5.2 percent, whereas at Johnson 

Hot Springs the concentration is 3,320 ppm-v. Higher molecular weight hydrocarbon gases are present at both sites; 

however, the concentrations are roughly 20 times greater at 

Auburn Hot Springs. The isotopic composition of C1 from 

Auburn Hot Springs (fig. 7) is similar to the isotopic compositions of geothermal C1 from Yellowstone National 

Park. Given the presence of thermogenic sources in this 

general vicinity, and the thermogenic nature of the hydrocarbon-gas composition, we consider the methane to be a 

mixture of thermogenic methane derived from previously 

generated hydrocarbons and geothermal methane derived 

from deep-seated crustal processes and carried to the surface by hydrothermal water. 

THE NORTHWESTERN GREAT BASIN AND THE 

OLYMPIC-WALLOWA LINEAMENT 

(SAMPLE SITES 2-1 THROUGH 2-10) 

The northwest boundary of the Great Basin is host to 

numerous thermal springs with gas discharge (figs. 3, 4; 

table 2). Deeply circulating, hot groundwater can leach or 

carry organic and inorganic components, including hydrocarbon gases, from the country rock. In the eastern Oregon 

study area (fig. 3), the basement rocks are part of exotic 
A COMPARISON OF HYDROCARBON GASES FROM THE NORTHWESTERN UNITED STATES 467 

Mesozoic accreted terranes and early Cenozoic sedimentary 

units that often lie beneath a late Cenozoic volcanic seal. 

The Surprise Valley graben in northeastern California 

and the Goose Lake graben in southeastern Oregon (fig. 4) 

have spring gases of probable thermogenic sources. The 

gases are composed of mainly N2 with significant quantities of C1 (up to 47 percent). The presence of higher molecular weight hydrocarbon gases (at least through the 

pentanes), C1/C2 ratios of about 150, and methane o13C 

values of -48 permil suggest a thermal origin. 

Locations in eastern Oregon with relatively diminished amounts of C1 are Alvord Hot Springs and Mid 

Borax Hot Spring (sample sites 2-7, 2-8; fig. 3; table 2). 

Methane concentrations are 760 and 1,680 ppm-v, respectively; the C1/C2 ratios of about 80 suggest a thermal origin for the methane. 

Microbial methane occurs at Wildhorse Hot Springs, 

Idaho, and at an unnamed hot spring located on an island 

in the Malhuer River, Oregon. At both these locations no 

significant amounts of higher molecular weight hydrocarbon gases were found, and the concentration of C1 is low. 

Results similar to those from relatively methane-rich 

sources in the northern Great Basin were found at Hot Lake 

in the Grande Ronde graben of northeastern Oregon, a pullapart basin along the Olympic-Wallowa Lineament. Here 

the gas has a C 1 content of 11.5 percent, contains higher 

molecular weight hydrocarbon gases, and has a C 1/C2 ratio 

of 8 and a o13cl value of -31 permil. 

Less diagnostic results for thermogenic hydrocarbon 

gases were obtained along the southwestern flank of the 

Snake River Plain. Fault-controlled springs have C1 concentrations of 0.20 to 0.40 percent and small concentrations of higher molecular weight hydrocarbon gases at an 

unnamed hot spring we refer to as Scintillation Hot Spring 

(sample site 2-2, fig. 3). It appears that many basins have 

thermal spring gases with thermogenic signatures, suggesting that thermal processes are altering organic matter in 

rocks beneath a late Cenozoic volcanic seal. 

THE CASCADE VOLCANOES OF 

NORTHERN CALIFORNIA 

(SAMPLE SITES 2-11 THROUGH 2-13) 

Mount Lassen's latest eruption was in 1915, and this 

area continues to be a hydrothermally active region today. 

We sampled gas from two separate hydrothermal areas, 

Little Hot Springs Valley and Sulphur Works (fig. 4; 

table 2). The gases there are composed mainly of C02, as 

expected from volcanic fumaroles; however, low concentrations of c) (100 to 120 ppm-v) and higher molecular 

weight hydrocarbon gases were found, indicating entrainment and subsequent thermal alteration of organic matter. 

Organic matter may have come from a variety of sources, 

including burial of vegetation by volcanic debris or hydrothermal alteration of country rock containing organic matter. Des Marais and others (1981) reported similar results 

for samples taken at Mount Lassen. 

Just below the summit of Mount Shasta, at an elevation 

of about 4,300 meters, lies Sulphur Springs, a sulfataric 

fumarole. Gas from this source is composed mainly of C02 

and a surprisingly large amount of C1 (1.18 percent), atypical of volcanic gases. Higher molecular weight hydrocarbon 

gases are not present. Entrainment of organic matter as suggested above may contribute to the methane source. The 

lack of higher molecular weight hydrocarbon gases may be 

attributed to extreme heat, which could break down higher 

molecular weight hydrocarbon gases into methane. 

SOUTHWESTERN OREGON 

(SAMPLE SITES 3-1 THROUGH 3-14) 

Our preliminary study of this area was focused in the 

southern Tyee Basin, near Roseburg, Oreg., where a variety of source rocks and associated gas leakage is found 

(fig. 5; table 3). Convergence between the Pacific and 

North American plates during late Eocene resulted in the 

accretion of the lower Eocene Umpqua Group of Niem 

and Niem ( 1990) and the Siletz River Volcanics to the accreted terranes of the Klamath Mountains, then to the margin of North America (Blake and Jayko, 1986; Niem and 

Niem, 1990). Most of this terrane subsided in Eocene time 

and became the Tyee Basin, which in turn was filled by 

the sediments of the middle Eocene Tyee Formation. 

Near the town of Umpqua, gas was sampled from the 

outcrop of the Umpqua Group (sample site 3-5, fig. 5) an 

early Eocene sequence of stacked, deep-marine fan and 

turbidite sandstone and mudstone deposited in a trench or 

marginal basin setting (Heller and Ryberg, 1983 ). The sequence is exposed in a roadcut where a series of imbricate 

thrusts of the Bonanza thrust fault has cut a portion of the 

unit. The Bonanza thrust fault may be a conduit for gas 

migrating upward from thermally mature sediments of the 

Umpqua Group which have been thrust under the Klamath 

Mountains to the east (Ryu and others, 1992). A minor 

amount of C1, no more than 1 ppm-v above atmospheric 

methane concentration (about 1.8 ppm-v) was detected 

leaking from joints in this outcrop. About 5 km to the 

northwest (sample site 3-8), the headspace gas was collected over an open water well completed in the Umpqua 

Group but away form the Bonanza thrust fault. A methane 

concentration of about 30 ppm-v was observed. 

About 15 km northwest of Roseburg, near the town of 

Melrose, we sampled gas in the headspace of three shallow 

water wells completed in the White Tail Ridge Formation 

(Niem and Niem, 1990) of the Umpqua Group (sample 

sites 3-6, 3-7, 3-9; fig. 5). The White Tail Ridge Formation 

is of early Eocene age and is composed of deltaic sandstones with interbedded carbonaceous shale and low-rank 
468 THE FUTURE OF ENERGY GASES 

coal (Niem and Niem, 1 990). In this location, the White 

Tail Ridge Formation overlies the Bonanza thrust. The gas 

from these wells contains up to 76 percent methane, and 

the o13C1 from sample site 3-6 measured -64.8 permil. 

Gas from sample site 3-6 was also analyzed in 1983 (unpublished data of Kvenvolden). At that time the concentration of cl was 94 percent and the o13cl was -64.3 permil. 

The gas at all wells is dry with C1/C2 ratios ranging from 

120 to 11,250 (table 3, samples 6, 7 and 9). Given the 

presence of coal, the molecular composition of the gas, and 

the isotopic composition of the C1, we consider this gas to 

have come from microbial gas generation during coalification within shallow coal-bearing strata. The headspace of 

two water wells near Camas Valley, about 20 km to the 

southwest, were sampled (sample site 3-10). These wells 

were also completed in the White Tail Ridge Formation. 

Here we found methane concentrations ranging from 35 to 

87 ppm-v, and we suspect that the methane is derived from 

coal, solely on the basis of the presence of the coal-bearing 

White Tail Ridge Formation at this location. 

On the opposite side of the Tyee Basin, near Coquille, 

we sampled gases from two exploratory wells drilled in the 

1920's (sample sites 3-13, 3-14; fig. 5). Both wells were 

completed in the late Eocene Coaledo Formation, which 

consists of deltaic sandstone, siltstones, and thick coalbeds 

(Ryu and others, 1992). In addition, the wells are located 

along the axis of the Fat Elk anticline. One of these wells 

was capped with a rubber seal and valve system that allowed gas to flow out, and the other well was open to the 

atmosphere. The capped well had headspace gas that contained 59 percent C1 and a small amount of higher molecular weight hydrocarbon gases; the gas is dry (C1/C2 ratio of 

2,000). The open well had a methane concentration of 12 

percent and a C/C2 ratio of 2,500. Given the similarity in 

C1tc2 ratios and the proximity of the open well to the 

capped well, the gases from both wells are probably very 

similar in origin, likely derived from coal. 

Ten miles south of Roseburg, we sampled the headspace of two wells completed in the Sixes River terrane of 

the Klamath Mountains (sample sites 3-1, 3-4; fig. 5). 

Blake (1984) considers the Sixes River terrane to be 

Upper Jurassic melange and broken formations. Nearby 

outcrops are composed of interbedded limestone, carbonaceous mudstone, and sandstone. Some limestone and mudstone had a petroliferous odor when broken open. Methane 

was found in concentrations up to 62 ppm-v. Gas sampled 

from the headspace of a sealed well contained nearly 14 

percent C1 with some higher molecular weight hydrocarbon gases. A methane concentration of about 0.5 percent 

with lesser amounts of higher molecular weight hydrocarbon gases was measured from a capped well missing a 

vent cap. C1/C2 ratios were high, ranging from 4,600 to 

13,500. Residents told us that the groundwater in this area 

is brackish; this brackishness may reflect an association 

with deeper formation water. 

NORTHWESTERN WASHINGTON 

(SAMPLE SITES 4-1 THROUGH 4-6) 

Convergence between the Pacific and North American 

plates during late Eocene and late Miocene times produced 

two principal terranes on the continental margin of Washington and Oregon. On the west side of the Olympic Peninsula 

of Washington (fig. 6), the melanges are exposed where they 

have been transported eastward during subduction-accretion 

tectonics (Snavely and K venvolden, 1989). Melanges and 

broken formations of two ages are present in the area: the 

middle and upper Eocene Ozette melange and broken formation, and the upper Oligocene and middle Miocene Hoh 

melange. Gases from the Wilson Ranch well and the Pysht 

and Taholah seeps contain measurable quantities of higher 

molecular weight hydrocarbon gases, in contrast to gases 

from the Garfield gas mounds, the Huelsdonk Ranch seep, 

and the Sol Due Hot Springs seep, which are composed 

primarily of C1 (table 4) (Kvenvolden and others, 1989a). 

The o13c values of gases from the wells and seeps range 

from -31.5 to -36.5 permil, with the exception of o13c for 

the Huelsdonk Ranch gas seep, which has a more negative 

value of -51.6 permil. 6D values of methane are more variable and range from -135 to -212 permil. With the exception of that from the Huelsdonk Ranch gas seep, the gas 

samples have compositions within the range attributed to 

thermogenic gas (Schoell 1980, 1983; Jenden and Kaplan, 

1986). The isotopic composition of C1 plots in the thermogenic field shown in figure 8. It is uncertain whether or not 

the gases were generated from the same source rocks, but the 

similar isotopic composition of the methane suggests that 

they may have been. The more negative bD value from the 

Huelsdonk Ranch gas seep of -212 permil in combination 

with the carbon isotopic composition of -51.6 perrnil suggests the C 1 is a mixture of thermogenic and microbial gas. 

The geologic settings of the well and seep sites provide 

some constraints on the source or sources of the gas. Either 

the middle and upper Eocene Ozette melange and broken 

formation or the upper Oligocene and middle Miocene Hoh 

melange and broken formation could serve as source rock 

for these gases (Snavely and Kvenvolden, 1989); however, 

because the Ozette melange and broken formation is 

present in the sections at the well and seep sites, it is a 

primary candidate for the source of the gas. 

Gas at the Huelsdonk Ranch seep is presumed to have 

migrated through a thick section of glacial till in the Hoh 

River valley underlain by the Ozette melange and broken 

formation. The unique methane isotopic composition at 

this site may reflect a gas derived in part from organic 

matter within these glacial deposits. In general, methane in 

glacial deposits is microbial in origin and has more negative carbon and hydrogen isotopic compositions than does 

methane from a thermogenic source (Schoell, 1980). A 

mixture of these two sources of gas could produce methane with the observed isotopic composition. 
A COMPARISON OF HYDROCARBON GASES FROM THE NORTHWESTERN UNITED STA~ES 469 

SUMMARY 

This report provides a catalogue of the molecular 

compositions of gases and the isotopic compositions of 

methane and carbon dioxide in natural-gas samples from 

various tectonic provinces in the northwestern United 

States. Gases from seeps, springs, thermal springs, wells, 

and outcrops have been sampled, and methane is present 

in all samples in concentrations ranging over five orders of 

magnitude, from about I ppm-v to almost 100 percent. 

The amount and source of methane depend on the processes taking place within the tectonic province. Both thermogenic and microbial methane is present, as well as 

mixtures of hydrocarbon gases from both sources. Carbon 

and hydrogen isotopic compositions of methane refine 

source determination and show that fermentation, C02 reductions, and thermal processes are involved in the origin 

of methane. The compositions of the gases that reach the 

surface reflect the subsurface conditions and processes. 

Where volcanic rocks overlie deeply buried sedimentary 

sections, the surface gas seeps may provide the most substantial clues to the presence of deeply buried potential energy resources. Our survey has demonstrated the variable 

composition of natural methane discharge. More detailed 

studies of these discharges are required in order to understand their significance relative to atmospheric gas composition and to subsurface energy resource potential. 

REFERENCES CITED 

Antweiler, J.C., Love, J.D., Prostka, H.J., Kulik, D.M., Lennart, 

A.A., Williams, F.E., Jinks, I.E., and Light, T.D., 1989, Mineral resources of the Teton Wilderness and adjacent areas, 

Teton, Fremont, and Park Counties, Wyoming: U.S. Geological Survey Bulletin 1781, 105 p. 

Blackstone, D.L., Jr., 1989, Spread Creek Anticline: Teton County, Wyoming-A study in structural form and petroleum exploration: The Mountain Geologist. v. 26, no. 2, p. 43-51. 

Blake, M.C., Jr., 1984, Tectonostratigraphic terranes in southwestern Oregon, in Nilsen, T.H., ed., Geology of the Upper 

Cretaceous Hornbrook Formation, Oregon and California: 

Pacific Section, Society of Economic Paleontologists and 

Mineralogists, v. 42, p. 159-165. 

Blake, M.C., Jr., and Jayko, A.S., 1986, Tectonic evolution of 

northwest California and southwest Oregon, in Basin and 

Range et metamorphic core complexes; Coast Ranges; ophiolites et series ·d'arc; Mexique. (United States; Basin and 

Range and metamorphic core complexes; Coast Ranges; 

ophiolites and arc series; Mexico): Bulletin de Ia Societe 

Geologique de France, Huitieme Serie, v. 2, no. 6, p. 921-

930. 

Breckenridge, R.M., and Hinckley, B.S., 1978, Thermal springs 

of Wyoming: Geological Survey of Wyoming Bulletin 60, 

104 p. 

Claypool, G.E., and Kaplan, l.R., 1974, The origin and distribution of methane in marine sediments, in Kaplan, I.R., ed., 

Natural Gases in Marine Sediments: New York, Plenum, 

p. 99-139. 

Clifton, C.G., Walters, C.F., and Simoneit, B.R.T., 1990, Hydrothermal petroleums from Yellowstone National Park, Wyoming, U.S.A.: Applied Geochemistry, v. 5, p. 169-191. 

Davis, J.B., and Squires, R.M., 1954, Detection of microbially 

produced gaseous hydrocarbons other than methane: Science, v. 119, p. 381-382. 

Des Marais, D.J, Donchin, J.H., Nehring, N.L., and Truesdell, 

A. H., 1981, Molecular carbon evidence for the origin of 

geothermal hydrocarbons: Nature, v. 292, p. 826-828. 

Faure, G., 1977, Principles of isotope geology: New York, John 

Wiley and Sons, 464 p. 

Fuex, A.N., 1977, The use of stable carbon isotopes in hydrocarbon exploration: Journal of Geochemical Exploration, v. 7, 

p. 155-188. 

Gunter, B.D., 1978, Cl-C4 hydrocarbons in hydrothermal gases: 

Geochimica et Cosmochimica Acta, v. 42, p. 137-139. 

Gunter, B.D., and Musgrave, B.C., 1966, Gas chromatographic 

measurements of hydrothermal emanations at Yellowstone 

National Park: Geochimica et Cosmochimica Acta, v. 30 

p. 1175-1189. 

---1971, New evidence on the origin of methane in hydrothermal gases: Geochimica et Cosmochimica Acta, v. 35, 

p. 113-118. 

Heasler, H.P., 1982, The Cody hydrothermal system: Wyoming 

Geological Association Guidebook, Thirty-third Annual 

Field Conference, p. 163-174. 

Heller, P.L., and Ryberg, P.T., 1983, Sedimentary record of subduction to forearc transition in the rotated Eocene basin of 

western Oregon: Geology, v. II, no. 7, p. 380-383. 

Jenden, P.D., and Kaplan, l.R., 1986, Comparison of microbial 

gases from the Middle America Trench and Scripps Submarine Canyon-Implications for the origin of natural gas: Applied Geochemistry, v. 1, p. 631-646. 

Kvenvolden, K.A., Golan-Bac, M., and Snavely P.D., Jr., 1989a, 

Preliminary evaluation of the petroleum potential of the Tertiary accretionary terrane, west side of the Olympic Peninsula, Washington-C. Composition of natural gases in seeps, 

outcrops, and a test well: U.S. Geological Survey Bulletin 

1892, p. 39-45. 

Kvenvolden, K.A., and Pettinga, J.R., 1989, Hydrocarbon gas 

seeps of the convergent Hikurangi margin, New Zealand: 

Marine and Petroleum Geology, v. 6 p. 2-8. 

Kvenvolden, K.A., Simoneit, B.R.T., and Love, J.D., 1989b, 

Chemical and isotopic compositions of natural gas from 

seeps in Yellowstone and Grand Teton National Parks, Wyoming: Wyoming Geological Association Guidebook, Fortieth 

Annual Field Conference, p. 241-246. 

Lehman, J.A., Smith, R.B., and Schilly, M.N., 1986, Upper crustal structure of the Yellowstone caldera from seismic delay 

time analyses and gravity correlations: Journal of Geophysical Research, v. 87, p. 2713-2730. 

Lorenson, T.D., Kvenvolden, K.A., Simoneit, B.R.G., Lief, R.A., 

1991, Composition of springs and seeps of northwestern 

Wyoming: U.S. Geological Survey Open File Report 91-

121, 26 p. 

Love, J.D., and Christiansen, A.C., 1985, Geologic map of Wyoming: U.S. Geological Survey and Geological Survey of 

Wyoming, G85135, scale 1:500,000, 3 sheets. 
470 THE FUTURE OF ENERGY GASES 

Love, J.D., and Good, J.M., 1970, Hydrocarbons in thermal 

areas, northwestern Wyoming: U.S. Geological Survey Professional Paper 644-B, p. B1-B23. 

Love, J.D., Hose, R.K., Weitz, J.L., Duncan, D.C., and Bergquist, 

H.R., 1951, Stratigraphic sections of Cretaceous rocks in 

northeastern Teton County, Wyoming: U.S. Geological Survey Oil and Gas Investigations Chart OC-43, 2 sheets. 

Love, J.D., and Love, J.M., 1983, Road log, Jackson to Dinwoody and return: Geological Survey of Wyoming, public 

information circular no. 20., p. 34. 

Lyon, G.L., and Hulston, J.R., 1984, Carbon and hydrogen isotopic compositions of New Zealand geothermal gases: 

Geochimica et Cosmochimica Acta, v. 48, p. 1161-1171. 

Nehring, N.L., and Truesdell, A.H., 1978, Hydrocarbon gases in 

some volcanic and geothermal systems: Geothermal Resources Council Transactions, v. 2, p. 483-486. 

Niem, A.R., and Niem, W.A., 1990, Geology and oil, gas, and 

coal resources, southern Tyee Basin, southern Coast Range, 

Oregon: Oregon Department of Geology and Mineral Industries Open-File Report 0-89-3, 44 p. 

Prostka, H.J., Blank, H.R., Jr., Christiansen, R.L., and Ruppel, 

E.T., 1975, Geologic map of the Tower Junction Quadrangle, 

Yellowstone National Park, Wyoming and Montana: U.S. 

Geological Survey Geologic Quadrangle Map GQ-1247. 

Rau, W.W., and Grocock, G.R., 1974, Piercement structure outcrops along the Washington coast: Washington Division of 

Geology and Earth Resources Information Circular 51, 7 p. 

Rice, D.D., and Claypool, G.E., 1981,-Generation, accumulation, 

and resource potential of biogenic gas: American Association of Petroleum Geologists Bulletin, v. 85, p. 5-25. 

Ryu, In-Chang, Niem, A.R., and Niem, W.A. (text by Niem, 

A.R., Ryu, In-Chang, and Niem, W.A.), 1992, Schematic 

fence diagram of the southern Tyee basin, Oregon Coast 

Range, showing stratigraphic relationships of exploration 

wells to surface measured sections: Oregon Department of 

Geology and Mineral Industries Oil and Gas Investigation 

18, 48 p., 1 plate. 

Schoell, M., 1980, The hydrogen and carbon isotopic composition of methane from natural gases of various origins: 

Geochimica et Cosmochimica Acta, v. 44, p. 649-661 

---1983, Genetic characterization of natural gases: American 

Association of Petroleum Geologists Bulletin, v. 67, p. 2225-

2237. 

Smith, R.B., and Braile, L.W., 1982, Crustal structure and evolution of an explosive silicic volcanic system at Yellowstone 

• 

National Park: Wyoming Geological Association Guidebook, 

Thirty-third Annual Field Conference, p. 233-250. 

Smith, R.B., and Christiansen, R.L., 1980, Yellowstone Park as a 

window to the Earth's interior: Scientific American, v. 242, 

no. 2, p. 104-117. 

Snavely, P.D., Jr., 1987, Tertiary geologic framework, neotectonics, and petroleum potential of the Oregon-Washington continental margin, in Scholl, D.W., Grantz, A., and Vedder, 

J.G., eds., Geology and resource potential of the continental 

margin of western North America and adjacent ocean basins-Beaufort Sea to Baja California: Houston, Texas, Circum-Pacific Council for Energy and Mineral Resources, 

Earth Science Series, v. 6, p. 305-335. 

Snavely, P.D., Jr., and Kvenvolden, K.A., 1989, Preliminary evaluation of the petroleum potential of the Tertiary accretionary 

terrane, west side of the Olympic Peninsula, WashingtonA. Geology and hydrocarbon potential: U.S. Geological Survey Bulletin 1892, p. 1-17. 

Stahl, W., 1974, Carbon isotope fractionations in natural gases: 

Nature, v. 251, p. 134-135. 

Tonnsen, J.J., 1982, Petroleum geology of the northern part of 

Yellowstone National Park: Wyoming Geological Association Guidebook, Thirty-third Annual Field Conference, 

p. 289-295. 

Truesdell, A.H., and Thompson, J. M., 1982, The geochemistry 

of the Shoshone geyser basin, Yellowstone National Park: 

Wyoming Geological Association Guidebook, Thirty-third 

Annual Field Conference, p. 153-160. 

Vogel, T.M., Oremland, R.S., and Kvenvolden, K.A., 1982, Lowtemperature formation of hydrocarbon gases in San Francisco Bay sediment (California, U.S.A.): Chemical Geology, 

v. 37, p. 289-298. 

White, D.E., 1957, Thermal waters of volcanic origin: Geological Society of America Bulletin, v. 68, p. 1637-1658. 

Whiticar, M.J., 1990, A geochemical perspective of natural gas 

and atmospheric methane: Organic Geochemistry, v. 16, 

nos. 1-3, p. 531-547. 

Whiticar, M.J., Faber, E., and Schoen, M., 1986, Biogenic methane formation in marine and freshwater environments-C02 

reduction vs. acetate fermentation-Isotope evidence: 

Geochimica et Cosmochimica Acta, v. 50, p. 693-709. 

Woltemate, I., Whiticar, M.J., and Schoell, M., 1984, Carbon and 

hydrogen isotopic composition of bacterial methane in a 

shallow freshwater lake: .Limnology and Oceanography, 

v. 29, p. 985-992. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Atmospheric Methane Flux from CoalsPreliminary Investigation of Coal Mines and 

Geologic Structures in the Black Warrior Basin, Alabama 

By Jerry L. Clayton1

, Joel S. Leventhal1

, Dudley D. Rice 1

, Jack C. Pashin2, Byard Mosher3, 

and Peter Czepiel3 

CONTENTS 

Abstract ......................................................................... 471 

Introduction ................................................................... 472 

Global Methane Budget ............................................... 472 

Chemistry and Physics of Methane in the Atmosphere .. 4 73 

Geologic Setting ........................................................... 473 

Regional Setting ..................................................... 473 

Stratigraphy ............................................................ 474 

Structure ................................................................. 474 

Coal Rank .............................................................. 478 

Composition and Origins of Black Warrior Coalbed 

Gases ............................................................................. 479 

Storage of Gas in Coals ................................................ 479 

Gas Content and Resources ....... .. . .. ... .... .. . .. ...... .... ... ... .. 480 

Methane Associated with Coal Mining and 

Utilization ..................................................................... 480 

Underground Mining ............................................. 480 

Surface Mining ...................................................... 481 

Post-mining Processes ........................................... 481 

Coal Combustion .......... .. .... ... ....... ...... ..... ....... ....... 482 

Analytical and Field Methods ...................................... 482 

Results and Discussion ................................................. 483 

Bankhead Fault ...................................................... 483 

1

U.S. Geological Survey, P.O. Box 25046, Denver Federal Center, 

Denver, CO 80225. 2Geological Survey of Alabama, P.O. Box 0, 420 Hackberry Lane, 

Tuscaloosa, AL 35486-9780. 3

University of New Hampshire, Complex Systems Research Center, 

Morse Hall, Durham, NH 03824. 

Results and Discussion-Continued 

Gwin Coal Exploration Core .................................. 486 

Surface Coal Mine .................................................. 487 

Jim Walter Resources, Inc., Blue Creek #5 Mine ..... 489 

Conclusions ................................................................... 490 

Acknowledgments ......................................................... 490 

References Cited ........................................................... "491 

ABSTRACT 

Methane is an important greenhouse gas whose concentration in the atmosphere is increasing. Although this 

increase in atmospheric methane is correlative with growth 

in human population and activities, the exact causes for the 

increase are not fully understood. The increase is probably 

caused mainly by enhanced flux, but it may also be related 

to changes in residence time of methane in the atmosphere, 

or both. Even though coalbeds are known sources of atmospheric methane, it is not known how much methane is 

escaping into the atmosphere. 

Because of increasing energy demand, particularly in 

developing countries where population is increasing, coal 

production is likely to increase over the next few decades 

and this could further increase the flux of atmospheric 

methane. In addition, no data are currently available on 

methane flux from coalbeds as a result of natural processes 

such as leakage at outcrops, or along faults and fractures 

that could provide avenues for methane migration upward 

from coal at depth. To better understand the global methane 

cycle and the role of fossil fuels in methane emissions, field 

471 
472 THE FUTURE OF ENERGY GASES 

measurements of methane emissions are needed from coalbeds, from areas of active mining, from coalbed gas production, and from undisturbed coals. 

In this paper, we report results of field measurements 

of CH4 emissions from surface and underground mines, 

fault zones, and coreholes in the Black Warrior Basin, Alabama. Ventilation of underground mines in Mary Lee 

group coals (of economic usage) gave the highest methane 

emissions rates-about 71,480,000 m3/yr (2.5 Bcf or billion 

cubic feet) from one ventilation shaft. In contrast, very low 

emissions occurred from active or abandoned coreholes and 

from Brookwood group coals (of economic usage) exposed 

by surface mining (about 81 m3

/yr (2.9 Mcf or thousand 

cubic feet)). The low methane emission rate from surface 

mines is due to low present-day methane content of the 

coal caused by degassing during shallow burial since late 

Paleozoic time. Black Warrior Basin coals at present-day 

depths of about 1,000 ft (305 m) or more still retain a 

high methane content; their high methane content results 

in much greater methane emissions from ventilation of deep 

underground mines. 

Methane flux of as much as about 500 m3/yr occurs 

from a small section of a normal fault and associated joints 

exposed at Bankhead Lock and Dam. The carbon isotopic 

composition of CH4 collected at the Bankhead Fault (b13C 

-49.3 permil) indicates a coalbed origin. This finding suggests that faults and fractures associated with coalbeds may 

be important sources of atmospheric methane. 

INTRODUCTION 

The objective of this study is to provide quantitative 

data on methane flux from coals resulting both from human 

activities and from natural geologic processes. Herein, we 

report the results of a reconnaissance field study of methane 

emissions associated with coals in the Black Warrior Basin, 

Alabama. The Black Warrior Basin was chosen because it 

is a geologically diverse area where it is possible to investigate the importance of a number of anthropogenic and natural variables in controlling CH4 flux. In addition to both 

surface and underground mines, the Black Warrior Basin 

has been a major target for coalbed gas drilling in recent 

years. There are a number of geologic features in the basin 

that could affect the rate of methane emissions. For example, the basin contains a number of coalbeds, both in the 

subsurface and outcrops, and a large number of structural 

elements, such as faults and fractures, that could facilitate 

natural leakage of methane into the atmosphere. 

GLOBAL METHANE BUDGET 

Methane is the most abundant hydrocarbon in the atmosphere. Its current atmospheric concentration is about 

1.7 ppmv (parts per million by volume) (Tyler, 1991). More 

importantly, evidence from analysis of gases trapped as 

bubbles in ice cores indicates that the atmospheric concentration of methane has more than doubled over the past 200 

to 300 years, from a preindustrial range of about 0.6 to 0. 7 

ppmv, and has been increasing at a rate of about 1 percent 

per year over the past 15 years (Rasmussen and Khalil, 

1981; Craig and Chou, 1982; Enhalt and others, 1983; 

Stauffer and others, 1988; Pearman and others, 1986; Chappellaz and others, 1990; Khalil and Rasmussen, 1990). 

Analyses of ice cores dating as early as 160,000 years B.P. 

suggest that the current rate of increase and methane content of the atmosphere is unprecedented in recent earth history (Raynaud and others, 1988; Stauffer and others, 1988). 

The principal anthropogenic methane sources are rice 

paddies, domestic livestock, landfills, biomass burning, 

venting of natural gas, losses of natural gas during transmission of gas and liquid petroleum, and coal mining 

(table 1) according to Quay and others (1991). Biogenic 

methane, formed by microorganisms assigned to the 

Archae domain, is estimated to account for more than 70 

percent of the total methane emission rate; it is common in 

rice paddies, ruminant animals, natural wetlands, and landfills (Seiler and Conrad, 1987; Cicerone and Oremland, 

1988; Stevens and Englekemeir, 1988). 

Methane leaking from fossil fuels is estimated to 

account for a significant proportion (approximately 15 

percent) of the total annual methane flux between the geoTable 1. Annual methane flux, in teragrams (Tg or 

1012 g), from various sources. 

[Data from Cicerone and Orem1and, 1988; Boyer and others, 1990) 

Source Annual release Range 

Enteric fermentation 80 65-100 

(animals). 

Natural wetlands---------- 115 100-200 

Rice paddies --------------- 110 60-170 

Biomass burning---------- 55 50-100 

Termites -------------------- 40 10-100 

Landfills -------------------- 40 30-70 

Oceans---------------------- 10 5-20 

Fresh waters---------------- 5 1-25 

Methane hydrate 5 0-1001 

destabilization. 

Coal mining---------------- 35 25--64 

Gas drilling, venting, 45 .. 25-50 

transmission. 

Total------------------- 5402 400--640 

1

The figure of 5 Tg of methane from hydrates is merely 

a "placeholder" (Cicerone and Oremland, 1988) and the upper 

range of 100 Tg is speculative on the basis of future projections (from Kvenvolden, 1988). 2Estimates by various workers for total methane release 

range from about 355 to 870 Tg (Tyler, 1991). 
ATMOSPHERIC METHANE FLUX FROM COALS, BLACK WARRIOR BASIN, ALABAMA 473 

sphere and atmosphere although considerable uncertainty 

exists with regard to the actual amount. Annual atmospheric methane flux from all sources is estimated at 540 

Tg (teragrams, 1012 g), whereas coal mining, natural-gas 

venting, and gas transmission losses are estimated at between 50 and 114 Tg (Khalil and Rasmussen, 1985; 

Stevens and Englekemeir, 1988; Cicerone and Oremland, 

1988; Hogan and others, 1991). Although coal is an important source of atmospheric methane, current global estimates of methane fluxes from coalbeds are uncertain 

(Boyer and others, 1990). Recently, Kirchgessner and others (1993a) estimated methane flux from a surface mine 

in the Powder River Basin, Wyoming, to be 1,735,000 

m3/year (about 61 million cubic feet per year (MMcf/yr) 

or 2xlo-5 Tg). The preliminary study by Kirchgessner and 

others (1993a) is the only previously published attempt to 

provide quantitative data on surface coal mine emissions. 

Release of methane from coalbeds into the atmosphere 

occurs both as a natural process and as a consequence of 

surface and underground mining. Estimates for countries 

other than the United States contain even greater uncertainty because fewer data are available. In some cases, global 

estimates of methane flux from coals are based solely on 

mine data from the United States, which are extrapolated to 

a global scale (Boyer and others, 1990). Furthermore, naturally occurring methane emissions from coals have not 

been taken' into account. Significant amounts of methane 

from buried coalbeds may move upward along naturally 

occurring faults and fractures, or may leak from coalbeds 

exposed in outcrops. 

CHEMISTRY AND PHYSICS OF 

METHANE IN THE ATMOSPHERE 

Methane plays an important role in several processes 

that affect the chemical composition and radiation budget 

of the atmosphere. First, methane strongly absorbs infrared 

radiation and, therefore, is an important greenhouse gas. 

On an atomic basis, methane has about 25 to 30 times 

more warming effect than carbon dioxide, and 70 times 

more on a weight basis (Kiehl and Dickinson,_ 1987). 

According to calculations by Donner and Ramanathan 

(1980), an atmospheric methane concentration increase of 

1.3 ppmv causes an elevation in the average global surface 

temperature of approximately l.3°C. Because methane has 

a relatively short atmospheric residence time of about 10 

years (Fung and others, 1991) and has a strong greenhouse 

effect, an estimated 10-percent reduction of the annual 

emission rate would probably stabilize atmospheric concentrations (Hogan and others, 1991) and could reduce the 

rate of increase in atmospheric greenhouse effect. 

Methane in the atmosphere reacts with hydroxyl radicals (OH-) in an initial reaction step of a series of reactions involving water, ozone (03), hydrogen oxides (HOx), 

nitrous oxides, formaldehyde, hydrogen, chlorine, and 

other species that affect the water budget, ozone concentration, and overall oxidizing power of the atmosphere 

(Tyler, 1991). Methane reaction with chlorine produces 

hydrochloric acid (HCl). This reaction is important in 

stratospheric chemistry because unlike free chlorine, HCl 

does not destroy ozone. Methane oxidation in the stratosphere may increase water vapor concentration as much as 

50 percent over levels for zero methane concentration and 

water is also a greenhouse gas (Ramanathan and others, 

1987). Other atmospheric gases, such as CH3Cl, CH3Br, 

CHC1F2, CH2Cl2, CHCC13, and S02, are affected directly 

or indirectly by the concentration of hydroxyl radicals 

(Tyler, 1991). These gases play important direct or indirect 

roles in the radiative budget and overall physics and 

chemistry of the atmosphere. 

GEOLOGIC SETTING 

REGIONAL SETTING 

To begin gathering data on CH4 fluxes associated with 

coals, we conducted a number of experiments in the Black 

Warrior Basin. The basin is a triangular-shaped structural 

depression in east-central Mississippi and west-central Alabama that is bounded on the southeast by the Appalachian 

orogenic belt, on the. southwest by the Ouachita orogenic 

belt, and on the north by the Nashville Dome (fig. 1 ). The 

Black Warrior Basin borders the Appalachian Basin on the 

northeast and is separated from the Arkoma Basin to the 

west by the Mississippi Valley graben (Thomas, 1988). 

Tectonically, the Black Warrior Basin is a late Paleozoic 

foreland basin that formed in response to crustal loading of 

the Appalachian and Ouachita orogenic belts during the 

continental collisions of North and South America, Europe, 

and Africa (Beaumont and others, 1988). The study area is 

restricted to the southeastern part of the basin in Alabama 

(southwestern Jefferson and southeastern Tuscaloosa Counties) along the Appalachian orogenic belt where coalbeds of 

Pennsylvanian age are actively mined both on the surface 

and underground; additionally, this is an area of coalbed 

gas exploration and production (fig. 2). The basin leads the 

Nation in coalbed gas completions, and much of this development is a consequence of enhancing the safety of underground coal mining. 

The northern margin of the Black Warrior Basin is 

mapped as the outcrop limit of the Lower Pennsylvanian 

part of the Pottsville Formation, which contains the principal coalbeds and associated coalbed-gas resources of the 

basin. About two-thirds of the basin is covered by Cretaceous and younger strata of the Mississippi Embayment 

and Gulf Coastal Plain (fig. 1), which unconformably overlie the Pottsville. In most of the study area, coal-bearing 

strata of the Pottsville Formation are exposed at the surface. 
474 THE FUTURE OF ENERGY GASES 

STRATIGRAPHY 

The upper part of the Pottsville Formation contains 

economically important coalbeds, which are assigned to 

several widespread coal groups (Metzger, 1965) (fig. 3). 

The coal groups form the upper part of regressive sequences that coarsen upward from marine mudstone to terrestrial 

sandstone. The cycles thicken to the south and southeast 

reflecting the subsidence history and evolution of the foreland basin during Pennsylvanian time (Pashin, 1991a). The 

Mary Lee group coals are the most important for underground mining. The interval from the Black Creek group 

coals through Cobb group coals (both of economic usage) 

(fig. 3) contains the most important targets for coalbed gas 

exploration and production (Hewitt, 1984; McFall and others, 1986). The younger and shallower groups, however, are 

also possible sources of atmospheric CH4. 

Individual coal beds are generally thin ( <1 m) throughout the basin, although the Blue Creek bed of the Mary 

Lee group is locally thicker than 3 m (Pashin, 1991a, b). 

Pennsylvanian foreland basin strata 

In each depositional cycle, coalbeds are most abundant in 

the eastern part of the basin where fluvial-deltaic platforms · 

favored peat accumulation during Pennsylvanian time (Pashin, 1991 b). In the study area, more than 20 and locally 

as many as 40 coalbeds are present in the Black Creek 

through Cobb interval, whereas less than five coalbeds are 

present in this interval in most of the basin. Even more 

coalbeds are present in the younger depositional cycles. 

STRUCTURE 

Folds and thrust faults, resulting from compressional 

forces of the Alleghanian orogeny, are present along the 

southeastern part of the basin and strike approximately 

N 40° E (Thomas, 1985) (fig. 4). The basin is bounded on 

the southeast by the Birmingham Anticlinorium. The anticlinorium is part of the Valley and Ridge Province, and 

Cambrian and Ordovician carbonate rocks and discontinuous thrust faults are present in its core. Among the main 

0 

_____ _,.., 

TENNESSEE,-> 

/'/' 

,-/ 

SCALE 

50 100 MILES 

~ ~ 

D . 

. Mesozoic and Cenozoic coastal plain strata-Dotted 

where approximately located 0 50 100 KILOMETERS ~ Thrust fault-Sawteeth on upper plate 

Figure 1. Index map of southeastern United States showing geologic setting of the Black Warrior Basin. From 

Pashin (l99la). 
ATMOSPHERIC METHANE FLUX FROM COALS, BLACK WARRIOR BASIN, ALABAMA 475 

folds in the study area are the Blue Creek Anticline and 

Syncline. Strata in the Blue Creek Anticline are intensely 

fractured compared with those in the rest of the basin. Normal faults, which generally strike northwest-southeast, are 

also abundant in the Black Warrior Basin (fig. 4). These 

faults are related to extensional tectonics and form a series 

of linear to arcuate horst and graben systems (Pashin, 

1991 a). Syndepositional movement of these faults and folds 

88ow srw 

- ___ _I __ ----....--- _T ____ ----------1- __ j_----------- -~~ 

i MARION \ WINSTON :. CULLMAN r ~--

1 / ~ I I 

I

I --- _,."" .. ;~ I II ;; ~ - ~· STUDY AREA ,.. ~ 

I ( ---- V : I ' 

I - I I I ~~ 

1------ m \ I II /,..' ~ \ I I 

I LAMAR 1_1 (f) I 1-- ---------..~-,1 BLOUNT 

i 1 fi\ I 1 WALKER I I "lJ \ I 

I ~----z-1--l 

I I I I 

I I r- < 

34°N-I I ~ ......... \ 

' L_, 

i ~ ... / 

I 

I 

I 

I 

I ' i 

I 0 I 

1 ~I 

I I 

I () \ 

I "lJ \ ~------~-'--

1 ~ ~- I 

I ~ 1

, I 

1----- -----~--~--(')-,. \ 

i PICKENS 1 ~ \ " 

I I C:: \ I ,,.. '. 

I I v• ' 

I I rut J 

I I t.tG(-\ 

I I I 

I I I 

I I \ 

I -

1 : D 

I __ -~ 

FAYETTE\ 

I I 

I r.,...,..l 

I 

I 

33°N_j I I 

I_--- -f 

I 1 

I ':; 

I ( 

/ 

....... --...) 

GREENE 

TUSCALOOSA 

.I 

I HALE 

1 LIMIT', OF STUDY( AREA 

/ 

I 

BIBB 

.1 

I r 

r 

r 

jJ 

r J 

SHELBY 

\. /r 

L- -· 

~-~; I 

J 

I 

_j 

' 

EXPLANATION 

COALBED GAS FIELDS 

A PLEASANT GROVE 

B OAK GROVE 

C BROOKWOOD 

D HOLT 

E CEDAR COVE 

F DEERLICK CREEK 

G PETERSON 

PERRY H CAR-ROLLS CREEK 

I BLUE CREEK 

I r v \ 

:SUMTER ~~~ I 

_ _.. 

0 10 MILES I I I I I I I I I 1 I 

0 10 KILOMETERS 

UNDERGROUND COAL MINES (•) 

1 OAK GROVE MINE 

2 JIM WALTER NO.5 MINE 

3 KELLERMAN 1570-2 

SURFACE MINE (e) 

4 GWIN COAL COREHOLE FAULTS 

5 BANKHEAD FAULT 

Figure 2. Alabama portion of Black Warrior Basin showing location of underground coal mines and coalbed gas fields. The 

study area is in southeastern part of the basin (area labeled A through I). Modified from Pashin (199la). 
476 THE FUTURE OF ENERGY GASES 

GROUPS COAL BEDS 

Brookwood~ Guide Brookwood 

Milldale 

Upper Carter 

Lower Carter 

Johnson 

Utley~ Utley 

Clements 

G · _-Gwin 

Win----- Thompson Mill 

Cobb _-Cobb Upper 

------- Cobb Lower 

----------Thomas 

Pratt { Pratt 

C Nickel Plate 

(Fire Clay) 

American 

. ---------- Curry G1lles~ Gillespy 

Curry 

Mary Lee 

/

NewCastle 

Mary Lee Blue Creek 

~ Jagger 

~Ream 

Black Creek~:::----._ Lick Creek 

Jefferson 

Murphy 

Black Creek 

ili(ilttii~ 

r7"l 

L:..:.:..:.J 

l:::::::::::=l 

~ 

Coal zone 

Sandstone 

Mudstone 

10" 

38" 

18" 

26" 

27" 

~24" 024" 

~23" c:::J 16" 

-

17" 

17" 

14" 

36" 

16" 

30" 

10" 

13" 

·-· 36" ·-·28" ·-·25" 9" 

8 9" 

27' 

3' 

27" 

Figure 3. Coals in the upper part of the Lower Pennsylvanian part of the Pottsville Formation showing major coal-bearing groups. Stratigraphic names of economic usage. Modified from Pashin (1991a). Thickness of individual coalbeds, 

where known, is shown. 1 inch equals 2.54 centimeters. 

(Pashin, 1991 b) affected patterns of sedimentation, which 

in turn influence coalification, hydrology, producibility of 

coalbed gas, and emissions of coalbed gas. Our detailed 

study of CH4 emission focused on the normal fault exposed 

at the Bankhead Lock and Dam (discussed in the "Results 

and Discussion" section). 

In addition to the normal fault system (fig. 4), the 

coalbeds have a distinct set of fractures referred to as 
LAMAR 

4 Alabama Figure · 

TUSCALOOSA 

GREENE 

ATION 

EXPLAN NTICUNE 

LEYA ESVAL FAULT MURPHR~ VALLEY UNE 

B OPO~~~EEK ~-rn~UNE C BLU CREEK CLINE 

D BLUtsuRG SY:NTICUNE 

E ~~~UATC~~ ANTICLINE F \LEY D UMTER 

G ~ICKENS-S Anticline H t 

oashed mal Fault--: hachures Nor e interred, block 

wner thrown 

On down Dashed F ult- Thrust 0 a rred 

here lnte Arrows 

w ° Fault- ent Strike-shp. movem relat•ve shOW 

Syncline 

+ oome 

hon (l99la). rom Pas I d faults. F 0 of folds an . 0 g location 0 howm 0 Basm s k Warnor 0 n of B\ac PortiO 
478 THE FUTURE OF ENERGY GASES 

cleats. The cleats are more closely spaced than joints and 

fractures in the adjacent rocks. Cleats make up a roughly 

orthogonal set of fractures. Face cleats are fairly continuous, whereas butt cleats are subordinate and commonly 

terminate at face cleats. Cleats are important because they 

provide pathways for the migration of gas in the coalbeds, 

which generally lack matrix permeability. In the Black 

Warrior Basin, the main orientation of the face cleats is 

generally perpendicular to the normal faults (N 6r E). In 

the area of the Blue Creek Anticline, however, the face 

cleats are locally superimposed on the regional face cleat 

set and trend perpendicular to the axis of the anticline 

(N 36° W) (Ward and others, 1984). 

COAL RANK 

The stqdy area is located in a "bull's-eye" pattern of 

increasing vitrinite reflectance along the Tuscaloosa and 

Jefferson County border where the highest coal rank is 

present (Winston, 1990) (fig. 5). In this area, vitrinite reflectance (R0 ) values are greater than 1.0 percent and 

locally greater than 1.4 percent, corresponding to high-volatile bituminous A to medium-volatile bituminous ranks. 

The present-day depth of burial in this area is less than 

3,000 ft (914 m). The higher rank in this part of the basin 

is attributed to a combination of burial and higher paleoheat flow. Maximum depth of burial probably occurred in 

88°W arw 

• 

I I r-- -- --- -- -- ------ -~---- --- -- -- --- -- ___:~ -- ---- --- -- --- --- ·, 

l ~ r ,-' 

I \. 

1. --- (---- - _··.i_ ."'-·~ --- ~ • ... ...- I 

...... ·-4' .., ...... 

-- _ I I 

\ 

I 

_ / I __ _ r 

/ l' 

\ ' / ........ \' . 

) ;.···· r .. ·· 

. /- .. .( .... 

~ .. ···· .. ···~ ----

';~ 

- ; ' 

r, 

EXPLANATION 

Contour interval = 0.1% Romax 

Structural trace-Bar and ball on 

downthrown side of fault; see figure 4 

for explanation of other symbol s 

/ 

1 ·~-~·Pi:~~-~1 0~==~~? MILES 

10 0 10 20 30 KILOMETERS 

Figure 5. Alabama portion of Black Warrior Basin showing iso-vitrinite reflectance (R0 ) lines for Mary Lee coal group of 

Lower Pennsylvanian part of the Pottsville Formation. Modified from Winston (1990). Dots show locations of vitrinite reflectance, R0 , data used to construct contours. See figure 2 for names of counties. 
ATMOSPHERIC METHANE FLUX FROM COALS, BLACK WARRIOR BASIN, ALABAMA 479 

this area of rapid subsidence and deposition during late 

Paleozoic time and as much as 2,439 m of erosion may 

have occurred since (Tell and others, 1987). In addition, 

Pashin (1991a) postulated that higher paleoheat flow may 

be the result of hydrologic activity in fractured strata adjacent to the Blue Creek Anticline. 

COMPOSITION AND ORIGINS OF 

BLACK WARRIOR COALBED GASES 

The produced coalbed gases from the Brookwood, 

Deerlick Creek, and Oak Grove Fields (fig. 2) are generally 

dry in molecular composition: wetness [(LC2+/}:C1+)xl00] 

values are generally about 0.1 percent. In addition, the 

coalbed gases are characterized by variable methane o13c 

values of -51.0 to -41.9 permil (Rice and others, 1989). 

Carbon dioxide contents are low ( <1 percent). 

The gases are interpreted to be mostly thermogenic in 

origin, but altered by relatively recent secondary processes, such as mixing with biogenic gas (Rice, in press). If 

unaltered, these coalbed gases would plot near the regression lines of Dai and others (1987) and Whiticar (1992) as 

shown on figure 6. On the methane 613C versus rank (R0 ) 

plot (fig. 6), the coalbed gases from the Black Warrior 

Basin form a relatively small group with methane 613C 

values that are isotopically lighter (more 13C depleted) 

than the values predicted for generation from any of the 

types of kerogen. 

Thermogenic gas generation from Pottsville Formation 

coal probably occurred in Late Pennsylvanian or early 

Mesozoic time, approximately coincident with the time of 

maximum burial and (or) highest geothermal gradient. 

Following uplift and erosion, however, some of the original thermogenic gas, particularly at shallow depths, was 

probably released. Alteration of the remaining thermogenic 

gas, perhaps by mixing with isotopically lighter biogenic 

methane and (or) by oxidation of the heavier hydrocarbons, 

if present, was favored by active groundwater flow along 

the southeastern part of the basin. For example, plumes of 

fresh water have been mapped by Pashin ( 1991 a) and are 

the result of recharge within the Mary Lee group coals 

where it is exposed along the Blue Creek Anticline. Mixing of biogenic gas has probably taken place in the shallower coal zones, which are not targets for coalbed gas 

exploration and production, but which are a possible 

source of methane emissions. 

STORAGE OF GAS IN COALS 

Although some free and dissolved gas may be present 

in coalbeds, most of the gas is absorbed within the coal. 

The free and dissolved gas in the coal occurs within the 

-60 

....J 

~ ·50 a: 

w 

c.. 

z 

u' 

M 

~ 

(,Q 

w 

z 

<! 

I 

f- -40 w 

~ 

-30 

0.3 

VITRINITE REFLECTANCE, IN PERCENT 

Figure 6. Methane o 13C versus vitrinite reflectance (R0 ) for coalbed gases and associated 

coals from Alabama portion of Black Warrior 

Basin. Regression line I is for gases generated 

from types II and III kerogen (Faber, 1987), 

line 2 is for coalbed and coal pyrolysis gases 

in China (Dai and others, 1987), line 3 is for 

coal-derived gases in China (Shen and others, 

1988), and stippled area is for coal-derived and 

coal pyrolysis gases from several authors as 

summarized by Whiticar (1992). Modified 

from Rice (in press). 

fractures (cleats) and pores, and the absorbed gas is 

present as a monomolecular layer on the internal surfaces 

of the coal (Kim, 1977). Coal has the ability to absorb 

very large amounts of gas because it is a microporous 

solid with large internal surface areas. 

Gas content generally increases with increasing rank 

(generally equivalent to increasing burial) (Kim, 1987), although there is a wide range of gas content within each 

coal rank. A large increase in gas content at a rank of 

about high-volatile bituminous C (R0 , approximately 0.6 

percent) is due mainly to a shift from predominantly thermal processes during high-rank coalification with generation of large amounts of methane to predominantly microbial 

generation of smaller amounts of gas at lower ranks. 

Pressure and temperature are also important controls 

on the gas content of coal (Juntgen and Karweil, 1966). 

For a given rank and at constant temperature, absorbed gas 
480 THE FUTURE OF ENERGY GASES 

content increases with increasing pressure, which usually 

results from increasing depth of burial. In contrast, storage 

capacity of coals is inversely related to temperature for a 

constant pressure; increasing temperature results in decreased gas content of the coal. Because high pressure is 

associated with high-rank coal rather than low-rank coal, 

higher methane content is commonly associated with highrank coal. However, natural desorption resulting from uplift and erosion may result in lower gas contents. 

GAS CONTENT AND RESOURCES 

Gas content data compiled by McFall and others 

(1986) show the relation between gas content, rank, and 

present-day depth of burial in the study area (fig. 7). Although considerable scatter exists in the data base, the plot 

shows that gas content as high as 700 scf/ton (scf, standard cubic feet; 3.1 cm3

/g) may be present in low-volatile 

bituminous coals at depths of 1,037 m. The gas content 

drops off dramatically for shallow and (or) low-rank coals, 

which are also possible sources of CH4 emissions. Gas 

content for Pottsville Formation coal in the Black Warrior 

Basin is relatively high despite the shallow depth of burial 

and natural degassing that probably took place during uplift and erosion, which has taken place after the Alleghanian orogeny (since 260 Ma). High gas content 

indicates that relatively recent biogenic gas has probably 

replaced some of the original thermogenic gas, which natmall y desorbed. 

On the basis of gas-content data, in addition to information on coal rank and distribution, McFall and others 

(1986) estimated coalbed-gas resources of approximately 

700 

600 

500 

"00 I 

:::1 I 

I 

I 

( 

100 l 

o..,.- 1,000 2,000 3,000 

DEPTH, IN FEET 

Figure 7. Gas content versus rank and depth of burial for coals from 

Lower Pennsylvanian part of the Pottsville Formation, Alabama portion of Black Warrior Basin. Dashed lines denote projected trends 

beyond Black Warrior Basin data. Modified from McFall and others 

( 1986). 1 foot equals .3048 meter. 

20 Tcf (trillion cubic feet) for the Black Creek through 

Cobb interval (fig. 3) in the Alabama portion of the Black 

Warrior Basin. As expected, the largest resources occur in 

the deepest, highest rank coal group, the Black Creek. The 

resource potential decreases stratigraphically upward. In 

addition, the largest resources for each interval occur in 

the "bull's-eye" area where the thickest and highest rank 

coalbeds are present. Smaller, but significant resources of 

coalbed gas are also present in the shallower coal zones, 

which have not been formally assessed. 

METHANE ASSOCIATED WITH 

COAL MINING AND UTILIZATION 

UNDERGROUND MINING 

. Coal is recovered by both surface and underground 

mining techniques. Underground mining operations account for the majority of CH4 emissions associated with the 

recovery and use of coal. Most underground mines are ventilated for safety. Methane concentrations in the range of 5 

to 15 percent (v/v) are explosive; mine air should contain 

less than 1 percent CH4 to be safe. Degasification systems 

are frequently used prior to, during, and after mining operations to maintain safe CH4 concentrations. Subsurface mining causes pressure decreases in the coal, which allows 

release of the coalbed CH4 into the mine tunnels. Methane 

is released not only from the coal, but also from adjacent 

rocks and coals above and below the main coalbed. 

Large quantities of CH4 are emitted during both common types of subsurface mining, Iongwall and room/pillar, 

necessitate high ventilation rates to ensure that mine CH4 

levels remain below 1 percent. Methane emissions continue after mining operations cease and ventilation of abandoned mines may be necessary to insure that explosive 

levels of CH4 do not build up underground. In both 

room/pillar and longwall mining techniques, CH4 is emitted from the coalbed and enclosing strata as the coal is 

extracted. In both mining techniques, the overlying strata 

fractures and may collapse after the coal is removed. Typically, the roof structure collapses and the mine floor buckles upward as mine support systems are removed. This 

fractured and collapsed region that has been mined out is 

known as a "gob" area. 

Gob areas may typically extend 100 m above and perhaps 30 m below the mined-out coalbed. In coals and surrounding rocks containing high gas content, CH4 released 

from gob areas may overwhelm the ventilation system's 

capacity for removal of the CH4. Wells referred to as "gob 

wells" can be drilled from the surface down into the gob 

fracture region to provide ,additional ventilation (fig. 8). 

Gob wells are usually drilled to a depth that is 2 to 25 

meters above the coalbed to be mined. Thus, as the region 
ATMOSPHERIC METHANE FLUX FROM COALS, BLACK WARRIOR BASIN, ALABAMA 481 

A 

B 

Mined 

area 

Gob well 

Mined 

area 

Unmined 

area 

Unmined 

area 

Figure 8. Schematic diagrams showing (A) horizontal, crossmeasure, and (B) gob wells used to vent gas from coal mines 

(Modified from Boyer and others, 1990). 

above the mined-out area fractures and collapses, CH4 

flows into the gob well, which is under a vacuum. Hydrostatic pressures are generally low in gob areas, and methane recovered from gob wells is often quite pure 

("pipeline quality") especially immediately following the 

fracturing of the roof strata. With careful well monitoring, 

production of nearly pure CH4 may continue for many 

years. At the present time, however, most gob well CH4 is 

vented to the atmosphere. A notable exception is that Jim 

Walter Resources, Inc., is recovering much of its gob gas; 

as much as 83 percent of· the produced gas from their underground mining operations is from gob wells. 

Several other methods are currently used to control 

methane emissions into the mine proper. Horizontal and 

cross-measure boreholes may be drilled to release CH4 

from the coal and rock strata prior to mining (fig. 8). Horizontal drilling into the coalbed will help to release CH4 

from the coal itself while cross-measure drilling is used to 

degasify the coal and surrounding rock strata. Rather than 

vent borehole CH4 directly into the mine it is usually 

ducted into an in-mine vacuum system, which directs the 

released CH4 out of the mine. 

Methane may also be rather effectively removed from 

coalbeds several years prior to mining by the use of vertical wells. The coalbed methane recovered from these 

wells is also typically of pipeline quality. Accordingly, 

coalbed methane wells are now drilled both to degasify 

coalbeds prior to mining and also to recover CH4 from 

one or more coalbeds, which may be uneconomical or too 

difficult to mine. The life expectancy of a coalbed methane well is anywhere from 10 to 20 years, and in 1991 

there were more than 2,800 wells in the Alabama portion 

of the Black Warrior Basin that produced about 68 Bcf/yr 

(Bcf, billion cubic feet) of high-grade gas from coalbeds 

(D. Lathem, Coalbed Methane Association, oral commun., 

1992). There may also be atmospheric CH4 emissions 

from these wells. 

SURFACE MINING 

Where coalbeds are present near the surface (usually 

< 60 m) and the economics of removing the overburden 

are favorable, surface mining techniques are used. As is 

the case in underground mining, CH4 is released from 

both the coalbed and the surrounding strata during mining. 

The CH4 content of surface mined coal is typically much 

lower than deeper underground mine deposits (fig. 7) and 

thus emissions are estimated to be substantially less from 

surface mining operations. In 1985, about 55 percent of 

world coal production was from surface mines. Methane 

from surface mines escapes directly to the atmosphere. 

Presently, little reliable data exist to estimate global emissions of CH4 from surface mining. 

POST-MINING PROCESSES 

All of the CH4 contained in coal is not released immediately upon mining and thus emissions are also associated 

with procedures such as processing and transportation 

which may occur after the coal has left the mine. CH4 

emissions may be high during the mechanical breaking, 

crushing, separating, drying and sizing steps which follow 

mining. These emissions and those which take place during 

further coal processing and transportation go directly into 
482 THE FUTURE OF ENERGY GASES 

the atmosphere. There may also be CH4 emissions from 

mine spoil and tailing piles that are produced during both 

surface and underground mining. At the present time, however, there are no emission measurements available for 

these sources. 

COAL COMBUSTION 

Roughly 80 percent of world's produced coal is either 

burned for heat or to generate electricity. Because the combustion of coal takes place in a closed system, it has previously been assumed that CH4 emissions are very minor. A 

recent preliminary report, however, suggests there may be 

significant CH4 emissions resulting from the low-temperature combustion of coal such as is typical in home heating 

and cooking applications in countries such as China (Khalil 

and others, 1993). These authors measured CH4 emissions 

from coal burning which were roughly an order of magnitude larger than those typically reported for low-temperature 

biomass combustion. They calculated that global emissions 

of CH4 are perhaps as much as 16 Tg/yr (0. 79 Tcf) owing to 

low-temperature coal combustion. Coal combustion is clearly an area where more data are required to more accurately 

assess the importance of this source. 

ANALYTICAL AND FIELD METHODS 

Real-time CH4 flux measurements were made using an 

Aerodyne Research, Inc., Mobile Methane Monitor. This 

monitor consists of a truck-mounted system for determining methane flux on the basis of absorption of infrared laser 

radiation (McManus and others, 1991 ). Methane is detected 

by passing an atmospheric (sampled) air stream through a 

He-Ne laser that is rapidly tuned on and off of the methane 

infrared absorption line of 3.39 microns (2947.91 cm- 1

). 

Changes in the cell transmission resulting from varying 

CH4 concentrations in the sampled air stream are used to 

determine real-time methane concentrations and changes. 

The instrument is sensitive to changes of 0.3 percent of the 

ambient atmospheric methane level, or about 5 ppbv, and 

response time is about 1 second. 

Carbon dioxide is detected using a separate truckmounted instrument that measures infrared absorption 

(LiCor, Inc.) with an accuracy of ±1 part per million. The 

purpose of measuring C02 is to correct for any methane 

from automobiles or other combustion sources that might 

mask CH4 from coalbeds. For example, a correction factor 

of CH4:C02 of 1:1000 is used to account for methane from 

automobile exhaust (McManus and others, 1991). 

To determine CH4 fluxes from point sources, such as 

faults or mine vents, sulfur hexafluoride (SF6) is released 

at a measured rate and is detected simultaneously along 

with the methane by the truck-mounted system. Sulfur 

hexafluoride is an inert gas not typically found in the atmosphere. The SF6 is measured with a rapid-response SF6 

analyzer using an electron-capture detector (Benner and 

Lamb, 1985) with a detection limit of about 10 parts per 

trillion. Because the source and rate of release of the SF6 

are known, coincidence of a methane peak and the SF6 

tracer peak identifies source of the CH4 peak and allows 

calculation of the CH4 flux. 

Determination of CH4 fluxes using 10- to 36-liter plastic static chambers was accomplished using the method described by Leventhal (1992). For collecting samples, a 

chamber was placed on the ground or coalbed by fitting the 

edges of the open end of the chamber into an approximately 

1 em by 1 em channel dug into the coal or ground surface 

(fig. 9). To minimize leakage around the edges of the chamber, mud was packed around the outside perimeter of the 

chamber. For coal piles, the collectors were pushed about 3 

to 5 em into the loose coal, but a tight seal was not possible. In this case, some leakage of methane may have occurred and the values reported herein represent minimum 

fluxes. Methane concentrations inside the static chambers 

and ambient CH4 concentrations were measured by two 

methods. On-site flux measurements were accomplished 

Figure 9. Aluminum static chamber used to collect samples 

to determine methane flux on coalbeds and coal piles. Samples are withdrawn using a gas-tight syringe and injected 

into glass sample vials for subsequent laboratory analysis 

using gas chromatography. Photograph by Jerry L. Clayton. 
ATMOSPHERIC METHANE FLUX FROM COALS, BLACK WARRIOR BASIN, ALABAMA 483 

using a portable flame-ionization detector (FID) (Leventhal, 1992) to measure CH4 concentrations inside the 

chambers in the field. The FID measurements were made at 

6- to I 0-minute intervals over 30 to 50 minutes. The data 

were recorded in the field and later plotted (CH4 concentration versus time) to determine fluxes. 

For comparison of methods, a second type of static 

chamber was used (aluminum, 51 x51 x26 em) to collect 

samples at most sites. Air samples of 60 ml were withdrawn from the chamber at 2-minute intervals (up to a 

total of 10 minutes) and stored in previous! y evacuated 

glass vials for subsequent analysis by gas chromatography 

at the University of New Hampshire. Twelve control vials 

containing CH4 standards indicated that no detectable loss 

of methane occurred during transport and storage (maximum of 21 days) of the glass sample vials prior to laboratory analysis. 

Methane samples were collected for stable isotope ratio 

measurement using a procedure modified from Quay and 

others ( 1991 ). A portable pump (KNF Neuberger Model 

NOS, Princeton, NJ), powered with a rechargeable 12-volt 

DC lead acid battery (Yasua), was connected with tubing 

(nylon, teflon, or copper) to an 8 L propane-type tank that 

was pre-evacuated to a pressure of 635 mm (25 inches) Hg. 

Methane samples were collected from along faults or collectors placed over open coreholes through the open end of 

the tubing with the other end connected through the pump 

to the evacuated tank (fig. 10). The tank valve was opened 

and methane flowed into the tank at atmospheric pressure 

for 1 to 2 minutes. Then, using the pump described above, 

additional methane was pumped into the collector tank to a 

pressure of about 1.5 atmospheres for 3 minutes. 

RESULTS AND DISCUSSION 

BANKHEAD FAULT 

The outcrop of the Bankhead Fault (fig. 11A, B) at 

Bankhead Lock and Dam along the Black Warrior River is 

one of the best exposures of a normal fault in the Black 

Warrior Basin. The Bankhead Fault is exposed near the 

western Oak Grove coalbed-gas field (fig. 2) and is part of a 

horst-and-graben system where displacement of individual 

faults locally approaches 400ft or 122 m (fig. 12). Stratigraphic displacement along the Bankhead Fault is approximately 200 feet (61 m), and the fault strikes N 25° W and 

dips 80° NE (Rheams and Benson, 1982). Prodeltaic mudstone of the Brookwood cycle forms the hanging wall and 

delta-froqt sandstone of the Utley cycle forms the footwall. 

Figure 10. Method used to collect methane for determination of stable carbon isotope ratio. 

Shown here is a joint in a sandstone on the downthrown (footwall) side of the Bankhead Fault. 

Methane leaking from the joint is pumped through a tube into a pre-evacuated cylinder to a 

pressure of about 1.5 atm. Photograph by Dudley D. Rice. 
484 THE FUTURE OF ENERGY GASES 

B 

Figure 11. A, Normal fault at Bankhead Lock and Dam showing fault gouge and related fracture. 

Photograph by Jack C. Pashin. B, Schematic diagram of the Bankhead Fault showing distribution 

of fractures (Modified from Pashin, 1991 ). 

Distinctive fracture systems are associated with the 

Bankhead Fault. The fault plane is a gouge zone 2 to 3 ft 

(.6 to .9 m) wide containing intensely sheared mudstone 

and fractured sandstone. Fractures related to the fault include synthetic joints, or joints parallel to the fault plane, 

and antithetic joints, or joints oblique to the fault plane. In 

mudstone of the footwall, these joints are discontinuous 

and have irregular spacing. By contrast, joints in sandstone 

of the hanging wall are continuous and increase in spacing 

away from the fault. 

Three faults in the Black Warrior Basin were tested 

during this study, but gas emissions were detected only 

from the Bankhead Fault Zone. Using an SF6 tracer gas 

release next to the fault, an overall CH4 emission rate of 

0.94 L/min (table 2) was measured using the truck-mounted laser spectrophotometer while driving along the road 

about 30 ft (9 m) from the surface exposure of the fault. 

On an annual basis, 0.94 L/min would be 19 Mcf/year 

(3.8xl0-4 Tg), not considering possible diurnal or annual 

variations. Use of the static chamber method to measure 

CH4 flux from one of the antithetic joints yielded a similar 

flux (1.0 Llmin, table 2). 

Testing with a hand-held gas chromatograph (FID) revealed that gas was diffusing out of the fault gouge as 

• 
ATMOSPHERIC METHANE FLUX FROM COALS, BLACK WARRIOR BASIN, ALABAMA 

Bankhead 

fault 

-1200:: 

--"'1'--=~- EXPLANATION 

Normal fault-Dashed where 

approximately located ; square on 

downthrown block 

Anticline )( Syncline * Bankhead outcrop 

Contour interval =20 It 

..... -sao 

0 

I -1300 0 

3 MILES 

I I 

5 KILOMETERS 

Figure 12. Structural contour map of Oak Grove Field (thick black outline) showing location of Bankhead Fault (Modified 

from Pashin, 199lb). Intermediate contours shown by dashed lines. See figure 2 for geographic location of Oak Creek Field. 

Table 2. Methane fluxes from point sources measured at various locations in the Black 

Warrior Basin, Alabama, using static chamber and truck-mounted laser-based spectrophotometric methods. 

[Mcf, thousand cubic feet; Mcfd, thousand cubic feet per day] 

Location description Lim in g/min m3/yr Mcfd Mcf/yr 

Bankhead Fault 

1

Contact of mudstone and 0.94 0.67 494 47.8xlo-3 17 

sandstone, base of fault. 2 Antithetic joint in 1.0 0.71 526 50.8xlo·3 19 

sandstone. 

Jim Walter Resources, Inc., Mine #5 

3Ventilation shaft-------------- 136,000 97,144 71,481,600 6,915 2,524,015 

1

Static chamber method using aluminum chamber and sample analysis at the University of New 

Hampshire. 2

Static chamber method using plastic chambers and on-site flame-ionization detection measurement of methane concentrations. 3Fiux determinations using truck-mounted laser-based spectrophometic method with SF6 tracer 

gas. See Analytical Methods section for full discussion of techniques used. 

485 

well as the joint systems. To assess the degree of variability in gas emissions from one joint, we measured gas concentrations at l-in. (2.54 em) intervals along an antithetic 

JOint (fig. 13). Gas concentration generally decreases upward along the fracture from approximately 200 ppm to 

approximately I ppm above background. From 17 to 
486 THE FUTURE OF ENERGY GASES 

1 oo90 

80 

c 70 ~ 

Q) 

> 

!11 

"0 60 c 

:::J 

Q 

0'> 

Q) 50 

> 0 

.D 

ell 

c 40 0 

·.;::::; 

"(ii 

0 

0... 30 

20 

10 

0 0 C> 0 0 

ci 0 0 6 0 0 

0 

Gas above background (ppm) 

Figure 13. Plot of methane emiSSion 

along an antithetic joint in the hanging 

wall of the Bankhead Fault, Black Warrior 

Basin, Alabama. 

23 in. (43 to 58 em) above ground level, however, gas 

readings exceeded full-scale detection maximum of about 

623 ppm above background. Similar off-scale readings 

were observed along parts of other joints as well; these 

readings suggest that permeability, or openness, varies 

considerably along fracture traces. 

Coal is the probable source for gas coming out of the 

Bankhead Fault and its assodated fractures. Two CH4 

samples collected at the Bankhead location had o13C values of -49.3 and -52.8 permil (table 3), similar to the values for coalbed methane in the Black Warrior Basin 

(fig. 6). Nearby coalbed CH4 exploration wells indicate 

that coalbeds of the Gwin and Utley groups (both of economic usage) are generally less than 61 m from the surface throughout this area. Additionally, wells drilled into 

other coalbeds that have been completed for CH4 production in this area range in depth from 229 m to 610 m. 

Whether coalbed gas is migrating to the surface in reTable 3. Stable carbon isotope ratios of methane samples collected from sites of methane flux measurements, Black Warrior 

Basin, Alabama. 

Sample location 

Bankhead Fault (CH4 collected 

from joint in sandstone). 

Bankhead Fault (CH4 collected 

from joint with large open 

cavity having highest CH4 

concentration measured by 

FID). 

Jim Walter Resources, Inc., 

coal evaluation open 

corehole (Gwin coal, 

approximately 275 feet 

(84 m) depth; drilling 

completed approximately 

24 h before sampling). 

Coalbed methane from Black 

Warrior Basin wells (Rice 

and others, 1989). 

b13C (permit versus PDB standard) 

-49.3 

-52.8 

-32.7 

-51.0 to -41.9 

sponse to continued unroofing of the Pottsville Formation 

or to dewatering by coalbed methane wells is unclear. Furthermore, it is not possible to determine precisely which 

coal the CH4 is derived from based on the limited isotopic 

and geologic data of the present study. However, our data 

show that gas is migrating along some fractures in the 

Black Warrior Basin. Quantification of the atmospheric 

CH4 flux in the basin requires a more comprehensive 

study of emissions from faults and fractures to obtain 

more quantitative data and to evaluate geologic factors 

that affect gas movement through faults and fractures. 

GWIN COAL EXPLORATION CORE 

We sampled a new corehole drilled by Jim Walter 

Resources, Inc. to a depth of about 270 ft (82 m) for evaluation of the Gwin coalbed (fig. 3). Over a period of two 

days, we measured methane concentrations at the top of 

the hole when the hole was open during drilling breaks. 

Methane concentrations were relatively low and no obvious 

increase above ambient levels was measured while the 

borehole penetrated the overburden. An increase to about 

6 ppm above ambient concentrations was measured when · 

the drill entered the Gwin coalbed. Upon completion of 

drilling, the corehole was covered with a plastic collector 

and left for approximately 24 h. Although it was not possible to determine a flux by this method, we did observe a 

CH4 concentration of about 100 ppm in the chamber before 

and after withdrawing a sample for isotopic analysis. 

The isotopic composition of the methane collected at 

the Gwin coal drilling site is unusually heavy (13C enriched, b13C=-32.7 permil) compared to coalbed CH4 sam-
ATMOSPHERIC METHANE FLUX FROM COALS, BLACK WARRIOR BASIN, ALABAMA 487 

pies from the Black Warrior Basin ( -42 to -52 penni!, 

fig. 6) and the other two methane samples collected during 

this study (table 4), which have fPC values of -49.3 and 

-52.8 permil. The thermal maturity of the Gwin coal at the 

corehole site is not high enough to account for an isotopic 

fractionation of about 10 penni! or more when compared 

to typical Black Warrior Basin coalbed methane values 

(figs. 5, 6). A possible explanation is that oxidation of 

CH4 catalyzed by methane-oxidizing bacteria (Coleman 

and others, 1981) may occur either in water associated 

with a free gas phase present in the coal or in the overlying water-containing rocks as CH4 leaks out of the coal 

and moves upward. Bacterial oxidation preferentially removes isotopically light ( 13C depleted) methane, which 

can cause a positive shift in b13c values in the residual 

methane. 

The methane sample collected at the Gwin coal corehole site contained insufficient concentration of C02 to 1

determine the carbon isotope ratio as a test for the presence 

of methane-oxidizing bacteria. Therefore, we cannot assess 

the extent, if any, to which biogenic processes might affect 

the CH4 flux at this site, although higher C02 concentrations might be expected if biogenic oxidation were occurring to any significant extent. Moreover, at both the Gwin 

and Bankhead sites, isotopic evidence give no indication 

of enhanced flux owing to biogenic generation of CH4 in 

the shallow subsurface. 

SURFACE COAL MINE 

We measured CH4 fluxes from the Pennsylvanian 

Carter and Milldale coalbeds (Brookwood group) (fig. 3) 

at several sites within the Drummond Coal Co., Inc., Kellerman 1570-2 surface mine. A comparison of CH4 concentrations versus time for static collection chambers placed 

Table 4. Methane fluxes measured at various locations in surface coal mines and coal storage in the Black Warrior 

Basin, Alabama, using static chambers. 

[Mcf, thousand cubic feet; Mcfd, thousand cubic feet per day; --, methane flux below detection limit] 

Location description Llm2

/min g/m2/min m3/m2/yr Mcfd/m2 

Mcf/m2/yr (xi0-3) (xi0-3) (xi0-4) Mcf/acre/yr 

Jim Walter Resources, Inc., Mine #5 

1 Unprocessed coal pile 5.3 3.8 3 2.7 0.10 401.6 

(4.5 m above ground). 1

Unprocessed coal pile (10m 10.5 7.5 6 5.3 0.19 788.6 

above ground). 1

Processed coal pile (10m 31.2 22.3 16 15.9 0.58 2343.9 

above ground). 1

Tailing pile--------------------- <0.1 <0.1 <.01 <.01 <.01 0.7 1 Vegetated surface of 

reclaimed surface mine. 

Drummond Coal Co., Inc., Kellerman Mine 1570-2 

Carter coal 

2

Undisturbed coal surface ---- 0.04 0.032 0.02 0.023 <.01 3.4 1

Undisturbed coal surface---- 0.01 0.007 0.005 0.005 <.01 0.7 1 Crushed coal pile ------------- 0.49 0.35 0.26 0.25 <.01 36.5 1 Crushed coal pile ------------- 0.46 0.33 0.24 0.23 <.01 34.3 2

Crushed coal pile ------------- 0.10 0.07 0.05 0.05 <.01 0.7 2·

3Roughened coal surface---- 0.06 0.04 0.03 0.03 <.01 4.3 

Milldale coal 

2Undisturbed coal surface---- 0.05 0.04 0.03 0.03 <.01 4.1 2

·

3Roughened coal surface---- 0.19 0.13 0.10 0.09 <.01 14.1 

1

Static chamber method using aluminum chamber and sample analysis at the University of New Hampshire. 2Static chamber method using plastic chambers and on-site flame-ionization detection measurement of methane concentrations. 3

Fiux measurements of "roughened" surfaces were made by digging in the upper few centimeters of the coal surface to expose 

fresh, small pieces of coal prior to placement of the collection chamber. 
488 THE FUTURE OF ENERGY GASES 

-.; 

"E 

8 " 

Oi 

E 

"' <="' -:5 

"' ::; 

at three locations within the Kellerman Mine is shown in 

figure 14. Methane flux was quite low at all sites tested 

within the mine, including piles of freshly uncovered, broken pieces of coal (<0.5 m3/m2

/yr, table 4). No significant 

differences in emissions were evident between the Carter 

and Milldale coals. 

Using the FID, we monitored CH4 levels along a 

cross-sectional traverse of the Carter coal at a freshly exposed surface, but we did not observe a detectable increase above the ambient level in other areas of the mine 

pit. Moreover, we collected two canned samples of freshly 

mined Carter coal for headspace analysis. After a 1-week 

period only very low amounts of gas accumulated in the 

cans, and it was not possible to determine the in-situ gas 

content to compare with other field data. 

The low CH4 flux from coalbeds of the Kellerman 

Mine is not unexpected considering the geologic history 

and present-day shallow burial depth of the coal. Coals of 

the Brookwood group (includes Milldale and Carter coalbeds) were deposited during Pennsylvanian time and 

reached maximum burial depths during the development 

of the Appalachian Basin (Alleghanian orogeny). As much 

as 2,439 m of strata may have been eroded above the 

coals by the end of Paleozoic time. Presently, mined coals 

of the Brookwood group are buried by less than 30 m of 

overburden in the Black Warrior Basin. At the Kellerman 

1570-2 Mine, only about 9 to 30 m of Pennsylvanian 

through Cretaceous age overburden is present. Coals of 

the Brookwood group reached maximum burial and thermal maturation during Pennsylvanian time. The coals were 

300 

250.1 

20J 

150 

100 

50 

Fresh Coal Pile 21 ..... _/-

/ 

d 

/ 

0---------

___ ::::J 

..... --· 

Roughened Swface 

0~----------.-----.-----.-----.-----.-----~ 

0 1 0 20 30 40 50 60 70 

Time (minutes) 

Figure 14. Plot of methane (net counts) versus time (minutes) for 

methane emissions from the Carter coal at the Kellerman surface 

mine using static chambers and portable flame-ionization detection 

(FID) method. Sixteen net counts on the FID integration is equivalent to 1 ppm methane. Methane fluxes calculated from these data, 

given table 4, were determined by regression analysis of the methane concentration data collected over the first 20 minutes only. 

After about 20 minutes, the rate of increase in methane concentration within the chambers decreased, which suggest leakage was 

occurring. 

uplifted by the end of Paleozoic time and have remained 

near the surface throughout Mesozoic and Cenozoic time. 

It is likely, therefore, that most of the CH4 escaped 

through natural desorption over geologic time. Consequently, removal of the relatively thin present-day overburden during surface mining operations does not result in 

significantly enhanced fluxes. 

The importance of overburden in controlling the gas 

content of coal in the Black Warrior Basin is indicated by 

the relation between depth and CH4 content (fig. 7). 

Shallowly buried coal (less than a few hundred feet) contains generally less than about 6 cm3

/g (about 200 scf/ton) 

CH4, whereas coals at present-day burial depths greater 

than about 457 m contain as much as about 10 to 16 

cm3/g (322 to 516 scf/ton). It is noteworthy that, on a normalized basis, the methane flux measured at the Kellerman 

1570-2 Mine is significantly less than in the Bankhead 

Fault. Our interpretation of the higher methane flux from 

the Bankhead Fault is that the fault must provide a migration conduit deep enough to connect with coalbeds that are 

deeply buried enough to retain a high gas content. As 

noted above, coals are present at burial depths of as much 

as about 610 m in the vicinity of the Bankhead Fault exposure, and coalbed methane production occurs from 

depths of 229 to 610 m. 

At any given time, as much as about 10 acres 

(4,047 m2) of coal are exposed at the Kellerman 1570-2 

Mine. A range of methane flux from the mining of 0.005 

to 0.26 m3/m2/yr (table 4) yields between about 7 and 370 

Mcf of methane emitted per year from the entire mine; 

additional methane losses might also occur during transportation or storage of the mined coal. This range of methane emissions for the Kellerman 1570-2 Mine is notably 

lower than that reported by Kirchgessner and others 

(1993a) for the Tertiary Smith coal (low rank--less than 

0.6 percent R0 ) at the Caballo Mine in the Powder River 

Basin, northeastern Wyoming (61,300 Mcf/yr; 1,735,000 

m3/yr), despite the fact that coals from both mines have 

very low methane content. On the basis of recent annual 

production data (Caballo--14.3 million metric ton~ in 

1989; Kellerman-about 0.83 million metric tons), these 

emission rates are equivalent to about 0.12 and <0.01 m3 

(4.2 and <0.4 cf) gas per metric ton of coal mined from 

the Caballo and Kellermine Mines, respectively. Both of 

these emission rates are low compared to the estimated average for U.S. surface coal mines of 2.5 m3 (88.3 cf)/metric ton (Boyer and others, 1990). 

The dramatically different methane emission rates we 

observed compared with those of Kirchgessner and others 

(1993a) illustrate the risks inherent in extrapolating local 

data to regional or global scales. Clearly, more data are 

needed from mines worldwide, in varying geologic settings and with differing coal geochemistry, to determine 

the scale of surface mine emissions and to assess the importance of various natural factors and mining procedures 
ATMOSPHERIC METHANE FLUX FROM COALS, BLACK WARRIOR BASIN, ALABAMA 489 

in controlling the global CH4 flux. Moreover, as suggested 

by Kirchgessner and others (1993a), carefully controlled 

studies of analytical methodologies are needed to determine the best approach and to adequately assess the level 

of uncertainty in these field studies. 

JIM WALTER RESOURCES, INC., 

BLUE CREEK #5 MINE 

Using an SF6 tracer gas release, we measured a methane flux of 136,000 L/min (6.9 MMcfd) for one of the two 

ventilation shafts for the Blue Creek #5 Mine (Jim Walter 

Resources, Inc,) (table 2). Assuming a similar flux from 

the other vent yields a total flux for the mine of about 14 

MMcfd, which is in general agreement with the daily average per mine of 16 MMcfd determined from the mining 

company monitoring (D. Hagood, oral commun., 1993). 

Recently, it has been estimated that cumulative CH4 

emission from all underground mines in Alabama is about 

300,000 metric tons/year (14 Bcf) (Boyer and others, 

1990). According to our calculations, the Blue Creek #5 

Mine emits about 102,400 metric tons (5 Bcf) from two 

shafts [(71,481,600 m3)(7.16xi0-5 ton/m3) per shaft], 

which is 34 percent of the total estimated for the State by 

Boyer and others (1990). In 1991, the Blue Creek #5 Mine 

produced I ,753,594 metric tons of coal (Carroll and Tolson, 199 I). The CH4 emissions rate, then, would be about 

81.5 m3 (2,877 cf)/metric ton of coal mined, assuming 

similar production rates today as in 1991. The CH4 associated with underground coal mining can constitute a significant recoverable resource. In fact, Jim Walter Resources, 

Inc., a world leader in recovery of CH4 associated with 

underground mining, currently captures about 35 percent 

of the CH4 released from their underground mining operations in the Black Warrior Basin. 

Boyer and others ( 1990) plotted CH4 emissions versus 

metric ton of coal mined for 59 U.S. coal mines and determined a least-squares linear regression equation to relate 

emissions to tons of coal mined: 

CH4 emissions (m3 /metric ton mined) =[2.04x(CH4)]+8.16 

where (CH4)=in-situ CH4 content of the coal and 

1.0 m3=35.31 cf 

Boyer and others (1990) noted that this approach contains 

a great deal of uncertainty, mainly because the correlation 

between coalbed gas content and emissions measurements 

shows almost no correlation (r2

=0.35). For example, in the 

case of the Jim Walter Resources, Inc., Blue Creek #5 

Mine, this equation requires an in-situ gas content of about 

31.8 m3 (1 ,222 cf)/ton (or 31.8 cm3 /g), at least two times 

that reported for Black Warrior Basin coals (fig. 7). The 

high emissions rate for the Blue Creek #5 Mine, compared 

to gas content of Black Warrior coals and to the equation 

above, probably indicates that the gas is emitted not only 

from the beds being mined, but also from adjacent rocks 

including coalbed leaks. 

To be a possible source of emissions, coalbed gas 

must desorb and migrate by diffusion out of the coal matrix via cleats, joints, or faults to the surface or to a well 

bore. The sorbed gas is held in the microstructure of the 

coal by pore pressure, and gas migration takes place when 

the pressure is reduced. This desorption process probably 

took place naturally in the Black Warrior Basin following 

uplift and erosion about 250 Ma. Because most coals are 

characterized by high water saturations, depressurization 

also results from dewatering of the coalbeds. This depressurization by dewatering has probably taken place over the 

southeastern part of the Black Warrior Basin because of 

widespread mining and coalbed gas production (fig. 2). 

This mining and production activity has resulted in lowering of the water table and pressure of the coalbeds as illustrated by figure 15. In the Oak Grove Field (fig. 15A), 

600 

=- 500 wen _,,e: 

~ w 400 

:E~ o en 300 

l-en 1-w 

0 a: 200 !Do. 

100t 

• • 

Depth of Blue Creek coal-1150 ft 

• 0+---~~~----~--~----~--~----+ 

A 400 600 800 1000 1200 1400 1600 1800 

TOTAL WELL DEPTH (ft) 

900 

Vertical pressure gradient= 

. J.. • 

800 8.06 psi/It; r=0.43 

• t• • ·- 700 0.433 psi/It • :··:· 

w en •• _,,e: 600 (hydrostatic pressure) ,, 0 •it • :I:W 500 

~· •a: ::::J • 

Oen 400 • • l-en ..... 1-w 300 Depth of Blue Creek coal ..... Oa: -2100 ft .. 1·· 0 . ID o. 200 • ~-:~ .. • : j"• •• 100 • • • .'{,._,:-.,... • • 

0 • .. ., . 1000 1200 1400 1600 1800 2000 2200 2400 2600 

B TOTAL WELL DEPTH (ft) 

Figure 15. Pressure versus depth plots for Oak Grove (A) and 

Brookwood (B) coalbed gas fields, southeastern Black Warrior 

Basin, Alabama. From Pashin ( 1991 a). 1 foot equals .3048 meter. 
490 THE FUTURE OF ENERGY GASES 

reservoir pressure data were collected shortly after the 

wells began production and the data points generally plot 

along the line of hydrostatic pressure (0.433 psi!ft or 

2.98 kPa). In contrast, pressure data collected after 3 

months of coalbed gas production from the Brookwood 

Field (fig. 15B), which contains three closely spaced deep 

underground mines, indicate that the deeper coals are significantly underpressured because of dewatering. The magnitude of the depressurization process is significant 

considering that more than 2,800 wells were producing 

coalbed gas, mainly in Tuscaloosa and Jefferson Counties, 

at the end of 1991. These wells produced more than 96 

million barrels of water during the year. Also, significant 

amounts of water are produced from both the surface and 

underground mines prior to and during mining. In some 

cases, the water table is lowered by as much as 61 m near 

mines in the Black Warrior Basin (Pashin, 1991a). As a 

consequence, widespread desorption of coalbed gas may 

have taken place in the study area as a result of anthropogenic activity during the last 20 years. 

CONCLUSIONS 

We report field measurements of CH4 emissions from 

Pennsylvanian-age coalbeds in surface and underground 

coal mines, fault zones, and coreholes in the Black Warrior Basin. Not surprisingly, ventilation of underground 

mines is the greatest single source of atmospheric CH4 

observed. In contrast, surface mining of the Pennsylvanian 

Carter and Milldale coals of the Pottsville Formation at 

the Kellerman 1570-2 surface mine results in very little 

CH4 emission (less than about 748 metric tons or 37 Mcf 

annually per acre of coal exposed). From the data of the 

present study, it is not possible to estimate the amount of 

methane lost during transport and utilization of the coal, 

although the low initial methane content inferred for these 

coals suggests that the amounts are not significantly greater than those associated with the mining itself. 

Considering the thermal and geologic history of the 

Black Warrior Basin, high CH4 emissions would not be 

expected during surface mining of the Pottsville Formation 

coals, even if CH4 from adjacent rocks and coalbeds (beds 

below the one being mined) were mixing with the Carter 

and Milldale coal gas. All of the Brookwood group coals 

reached maximum burial depths and, hence, thermal maturation, during Pennsylvanian time and were uplifted by the 

end of Paleozoic time. This resulted in loss of most of the 

previously generated methane during Mesozoic and Tertiary time. This example illustrates the importance of considering the geologic history of coalbeds for understanding 

the role of various anthropogenic factors in influencing 

methane emissions. Moreover, attempts to develop a general equation for predicting emissions based solely on the 

amount of coal mined are unlikely to succeed without inclusion of factors that take into account the geochemistry 

of the coal and its geologic setting and history. 

This study demonstrates, for the first time, that faults 

associated with coals may be significant sources of CH4 

emissions. Methane emissions from the Bankhead normal 

fault and associated joints are quite high compared to those 

of the Kellerman surface mine, especially considering that 

only point sources were measured at the fault outcrop and 

no attempt was made to integrate the flux over the entire 

length of exposed fault and joint lines. Carbon isotope data 

confirm that the Bankhead fault methane is derived from 

coalbeds and the relatively high CH4 flux, compared to the 

Kellerman 1570-2 Mine, suggests that the methane may be 

derived from more deeply buried coals (as deep as 2,000 ft 

or 610 m). Methane concentrations, and presumably fluxes, 

determined at l-in. intervals along a single joint exposure at 

the Bankhead Fault outcrop were quite variable, presumably owing to permeability variation along the joint. The 

reason for the uneven permeability along the joint is unknown, but may be due to occlusion of parts of the joint by 

secondary fracture filling or fault gouge. 

In contrast to the Bankhead Fault, one other fault tested contained obvious fault gouge and no CH4 was detected. Because we tested only three faults, it is impossible to 

speculate about how representative these three are of the 

large number of faults in the basin (fig. 4). Moreover, it is 

possible that fractures associated with the folds in the 

basin (fig. 4) may also serve as migration conduits for 

coalbed CH4 to reach the surface. To estimate the importance of faults on a basin-wide scale, many more measurements are needed along with an evaluation of the relation 

between flux and fault geology (type and age of fault, rock 

type, presence or absence of fracture filling, fault orientation and depth, and other parameters). 

ACKNOWLEDGMENTS 

We gratefully acknowledge Gary Owen, Jim Walter 

Resources, Inc., for his help in selecting sampling sites, 

and particularly for help with logistics and assistance in 

the field. Steven Sides, Drummond Coal Co., is thanked 

for allowing access to the Kellerman #1570-2 surface 

mine and driving us through the mud. We thank Dennis 

Lathem, Alabama Coalbed Methane Association, for helpful discussions about the project. Brian Lamb, Washington 

State University, is gratefully acknowledged for help with 

the truck-mounted methane flux measurements. Professor 

Drury Caine, Department of Chemistry, University of Alabama, kindly allowed access to the department to recharge 

our hydrogen storage units. Dave Wilbur, University of 

Washington, is thanked for advice on pumps for isotope 

sample collection. 
ATMOSPHERIC METHANE FLUX FROM COALS, BLACK WARRIOR BASIN, ALABAMA 491 

REFERENCES CITED 

Beaumont, C., Quinlan, G., and Hamilton, J., 1988, Orogeny and 

stratigraphy-Numerical models of the Paleozoic in the 

eastern interior of North America: Tectonics, v. 7, p. 389-

416. 

Benner, R.L., and Lamb, B., 1985, A fast response continuous 

analyzer for halogenated atmospheric tracers: Journal of Atmospheric and Oceanic Technology, v. 2, p. 582. 

Boyer, C.M., Kelafant, J.R., Kuuskraa, V.A., Manger, K.C., and 

Kruger, D., 1990, Methane emissions from coal miningIssues and opportunities for reduction: U.S. Environmental 

Protection Agency EPN400/9-90-008, 131 p. 

Carroll, R.E., and Tolson, J .S., 1991, Alabama coal data for 

1991: Alabama Geological Survey Information Series 58M, 

137 p. 

Chappellaz, J., Barnola, J.M., Raynaud, D.G., Korotkevich, Y.S., 

and Lorns, C., 1990, Ice core record of atmospheric methane 

over the past 160,000 years: Nature, v. 345, p. 127-131. 

Cicerone, R.J., and Oremland, R.S., 1988, Biogeochemical aspects of atmospheric methane: Global Biogeochemical Cycles, v. 2, p. 299-327. 

Coleman, D.O., Risatti, J.B., and Schoell, M., 1981, Fractionation of carbon and hydrogen isotopes by methane-oxidizing bacteria: Geochimica et Cosmochimica Acta., v. 45, 

p. 1033-1037. 

Craig, H., and Chou, C. C., 1982, Methane-The record in polar 

ice cores: Geophysical Research Letters, v. 9, p. 1221-1224. 

Dai, J., Qi, H., Song, Y., and Guan, D., 1987, Composition, carbon isotope characteristics, and the origin of coal-bed gases 

in China and their implications: Scientia Sinica (Series B), 

v. 30, p. 1324-1337. 

Donner, L., and Ramanathan, V., 1980, Methane and nitrous 

oxide-Their effects on the terrestrial climate: Journal of 

Atmospheric Science, v. 3 7, p. 119-124. 

Enhalt, D.H., Zander, R.J., and Lamontague, R.A., 1983, On the 

temporal increase of tropospheric CH4: Journal of Geophysical Research, v. 88, p. 8442-8446. 

Faber, E., 1987, Zur isotopengeochemie gasformiger Kohlenwasserstoffe: Erdol Erdgas Kahle, v. I 03, p. 21 Q-218. 

Fung, I., John, J., Lerner, J., Matthews, E., Prather, M., Steele, 

L.P., and Fraser, P.J., 1991, Three-dimensional model synthesis of the global methane cycle: Journal of Geophysical 

Research, v. 96, p. 13033-13065. 

Hewitt, J.L., 1984, Geologic overview, coal, and coalbed methane resources of the Warrior Basin-Alabama and Mississippi, in Rightmire, C.T., Eddy, G.E., and Kirr, J.N., eds., 

Coalbed methane resources of the United States: American 

Association of Petroleum Geologists Studies in Geology 17, 

p. 73-104. 

Hogan, K.B., Hoffman, J.S., and Thompson, A.M., 1991, Methane on the greenhouse agenda: Nature, v. 354, p. 181-182. 

Juntgen, H., and Karweil, J., 1966, Gasbildung und Gasspeicherung in Steinkohlenftozen, Part I and II: Erdol Kahle, 

Erdgas, Petrochem, v. 19, p. 251-258 and 339-344. 

Khalil, M.A.K., and Rasmussen, K.A., 1985, Causes of increasing atmospheric methane-Depletion of hydroxyl radicals 

and the rise of emissions: Atmosphere and Environment, 

v. 19, p. 397-407. 

---1990, Atmospheric methane-Recent global trends: Environmental Science Technology, v. 24, p. 549-553. 

Khalil, M.A.K., Rasmussen, R.A., Shearer, M.J., Ge, S., and 

Rau, J.A., 1993, Methane from coal burning: Chemosphere, 

v. 26, p. 473-477. 

Kiehl, J.T., and Dickinson, R.E., 1987, A study of the radiative 

effects of enhanced atmospheric C02 and CH4 on early 

earth temperatures: Journal of Geophysical Research, v. 92, 

p. 2991-2998. 

Kim, A.G., 1977, Estimating methane content of bituminous coal 

from adsorption data: U.S. Bureau of Mines Report of Investigations 8245, 22 p. 

Kirchgessner, D.A., Piccot, S.D., and Chadha, A., 1993a, Estimation of methane emissions from a surface coal mine using 

open-path FTIR spectroscopy and modeling techniques: 

Chemosphere, v. 26, p. 23-44. 

Kirchgessner, D.A, Piccot, S.D., and Winkler, J.D., 1993b, Estimate of global methane emissions from coal mines: Chemosphere, v. 26, p. 453-4 71. 

K venvolden, K.A., 1988, Methane hydrates and global climate: 

Global Biogeochemical Cycles, v. 2, p. 221-229. 

Leventhal, J.S., 1992, Modern mobile methane measurements in 

marshes: U.S. Geological Survey Open-File Report 92-445, 

24 p. 

McFall, K.S., Wicks, D.E., and Kuuskraa, V.A., 1986, A geological assessment of natural gas from coalbeds in the Warrior 

Basin, Alabama: Gas Research Institute Topical Report, 

Final Geologic Report (September 1985-September 1986), 

GRI 86/0272, 80 p. 

McManus, J.B., Crill, P.M., Harriss, R.C., Mosher, B., Lamb, B., 

Mass, K., and Ryddock, J., 1991, Measuring urban fluxes of 

methane: World Resource Review, v. 3, p. 162-183. 

Metzger, W.J., 1965, Pennsylvanian stratigraphy of the Warrior 

Basin, Alabama: Alabama Geological Survey Circular 30, 

80p. 

Pashin, J.C., 199la, Regional analysis of the Black Creek-Cobb 

coalbed methane target interval, Black Warrior Basin, Alabama: Geological Survey of Alabama Bulletin 145, 127 p. 

Pashin, J.C., 1991 b, Subsurface models of coal occurrence, Oak 

Grove Field, Black Warrior Basin, Alabama: Tuscaloosa, Alabama, The University of Alabama, 1991 Coalbed Methane 

Symposium Proceedings, p. 275-291. 

Pearman, G.I., Etheridge, D., de Silva, F., and Fraser, P.J., 1986, 

Evidence of changing concentrations of atmospheric C02, 

N20, and CH4 from air bubbles in Antarctic ice: Nature 

(London), v. 320, p. 248-250. 

Quay, P.O., King, S.L., Stutsman, J., Wilbur, D.O., Steele, L.P., 

Fung, I., Gammon, R.H., Brown, T.A., Farwell, G. W., 

Grootes, P.M., and Schmidt, F.H., 1991, Carbon isotopic 

composition of atmospheric CH4: fos~il and biomass burning source strengths: Global Biogeochemical Cycles, v. 5, 

p. 25-47. 

Ramanathan, V., Callis, L., Cess, R., Hansen, J., Isaksen, I., 

Kuhn, W., Lacis, A., Luther, F., Mahlman, J., Reck, R., and 

Schlesinger, M., 1987, Climate-chemical interactions and effects of changing atmospheric trace gases: Review of Geophysics, v. 25, p. 1441-1482. 

Rasmussen, R.A., and Khalil, M.A.K., 1981, Global production 

of methane by termites: Nature (London), v. 301, p. 700-

702. 
492 THE FUTURE OF ENERGY GASES 

Raynaud, D., Chappellaz, J., Bamola, J.M., Korotkevich, Y.S., 

and Lorius, C., 1988, Climatic and CH4 cycle implications 

of glacial-interglacial CH4 change in the Vostok ice core: 

Nature, v. 333, p. 655-657. 

Rheams, L.G., and Benson, D.J., 1982, Depositional setting of 

the Pottsville Formation in the Black Warrior Basin: Alabama Geological Society 19th Annual Field Trip Guidebook, 

94 p. 

Rice, D.O., in press, Composition and origins of coalbed gas, in 

Law, B.E., and Rice, D.O., eds., Hydrocarbons from coal: 

American Association of Petroleum Geologists Studies in 

Geology. 

Rice, D.O., Epsman, M.L., and Mancini, E.A., 1989, Origin of 

conventional and coalbed gases in the Black Warrior Region, Alabama [abs]: Proceedings of 1989 Coalbed Methane 

Symposium, p. 321. 

Seiler, W., and Conrad, R., 1987, Contribution of tropical ecosystems to the global budgets of trace gases, especially CH4, 

H2, CO and N20, in Dickinson, R.E., ed., Geophysiology of 

Amazonia: New York, John Wiley, p. 133-162. 

Shen, P., Shen, Q., Wang, X., and Xu, Y., 1988, Characteristics 

of isotope composition of gasiform hydrocarbon and identification of coal-type gas: Scientia Sinica (Series B), v. 31, 

no. 6, p. 735-774. 

Stauffer, B., Fischer, A._, N_eftel, A., and Oeschger, H., 1988, Increase of atmospheric methane recorded in Antarctic ice 

core: Science, v. 229, p. 1386-1388. 

Stevens, C.M., and Englekemeir, A., 1988, Stable carbon isotopic 

composition of methane from some natural and anthropogenic sources: Journal of Geophysical Research, v. 93, 

p. 725-733. 

Taylor, J.A., Brasseur, G.P., Zimmerman, P.R., and Cicerone, 

R.J ., 1991, A study of the sources and sinks of methane and 

methyl chloroform using a global three-dimensional Lagrangian tropospheric tracer transport model: Journal of Geophysical Research, v. 96, no. 02, p. 3013-3044. 

Telle, W.R., Thompson, D.A., Lottman, L.K., and Malone, P.G., 

1987, Preliminary burial-thermal history of the Black Warrior Basin-Implications for coalbed methane and conventional hydrocarbon development: Tuscaloosa, Alabama, The 

University of Alabama, 1987 Coalbed Methane Symposium 

Proceedings, p. 37-50. 

Thomas, W.A., 1985, The Appalachian-Ouachita connectionPaleozoic orogenic belt at the southern margin of North 

America: Annual Review of Earth and Planetary Sciences, 

v. 13, p. 175-199. 

Thomas, W.A., 1988, The Black Warrior Basin, in Sloss, L.L., 

ed., Sedimentary cover; North American craton: Geological 

Society of America, The Geology of North America, v. D-2, 

p. 471--492. 

Tyler, S.C., 1991, The global methane budget, in Rogers, J.E., 

and Whitman, W.B., eds., Microbial production and consumption of greenhouse gases: methane, nitrogen oxides, 

and halomethanes, Washington, D.C., American Society for 

Microbiology, p. 7-38. 

Ward, W.E., II, Drahovzal, J.A., and Evans, F.E., Jr., 1984, Fracture analyses in a selected area of the Warrior coal basin, 

Alabama: Alabama Geological Survey Circular 111, 78 p. 

Whiticar, M.J., 1992, Stable isotope geochemistry of coals, 

humic kerogens, and related natural gases: Proceedings of 

the Canadian Coal and Coalbed Methane Geoscience Forum, 

B.C., Geological Survey Branch, Alberta Geological Survey, 

and Geological Survey of Canada, p. 149-172. 

Winston, R.B., 1990, Vitrinite reflectance of Alabama's bituminous coal: Geological Survey of Alabama Circular 139, 

54 p. 
The U.S. Geological Survey and other Government and 

private agencies provide official gas-resource estimates, 

and some discussions of the methods used in the gasresource evaluations are provided herein. The future of 

natural gas depends on the quantity, quality, and location 

of the gas. Unlike other energy resources such as coal, heavy 

oil, and some uranium, which are present near the Earth's 

surface and which are visible in outcrops and readily outlined by shallow drilling, natural gas is a highly mobile substance that occurs in a variety of geologic settings. Because 

potential natural-gas resources lie below the Earth's surface, 

estimating the quantity of natural gas that remains to be 

discovered involves considerable uncertainty. Reports in this 

section provide a broad overview of the resource potential of 

natural gas, which depends on the economics of drilling and 

production as well as technologic considerations for some 

habitats in which gas is found. 

GAS-RESOURCE ESTIMATES 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

U.S. Geological Survey Estimates of 

Natural-Gas Energy Resources 

By Gordon L. Dolton1, Donald L. Gautier1

, Richard F. Mast1, and David H. Root2 

CONTENTS 

Abstract ......................................................................... 495 

Resource Classification ................................................ 495 

Assessment Concepts ...... ...... .. .. .... .... ................ ........... 497 

Principles of Resource Assessment ...... ...... ...... .... ........ 497 

Assessment Methodologies .......................................... 498 

Discovery Process and Finding Rates .... .. ...... .. ............ 499 

Deposit Simulation ....... ........... ...... .. .. ......... .... .. .. .. .. ...... 499 

Reservoir Performance ................................................. 501 

Mass Balance ................................................................ 501 

History of U.S. Geological Survey Estimates of 

Natural-Gas Resources ................................................. 502 

References Cited .. . ........... .......... ......... .... .. . ... ... .. . .. .... ... . 504 

ABSTRACT 

In recent years, the U.S. Geological Survey (USGS) 

has classified oil and gas resources as a function of geologic certainty and economic feasibility. Amounts of undiscovered resources have been estimated using a variety 

of techniques, each of which has strengths and weaknesses. Almost all techniques rely on the two basic concepts of 

analogy and exhaustion (historical information). Although 

no method, short of drilling, is certain in its determination 

of undiscovered resources, several reasonable methods are 

possible, including volumetric- or areal-yield models and 

1

U.S. Geological Survey, Denver Federal Center, Box 25046, Denver, CO 80225-0046. 2U.S. Geological Survey, National Center, 12201 Sunrise Valley Dr., 

Reston, VA 22092-0001. 

historical-performance models. Other basic methods include discovery process and finding-rate models, which 

are essentially specialized types of historical performance 

models, and deposit-simulation and reservoir-performance 

models, which use basic petroleum engineering equations 

to make predictions. Mass-balance models are designed to 

predict oil and gas volumes on the basis of geologic principles. Many estimates of natural-gas resources have been 

made by the USGS, beginning with the work of Eugene 

Shaw in 1919. Various techniques have been employed 

over the years in a series of natural-gas assessments that 

have continued episodically almost to the present day. Like 

previous assessments, the one currently underway is intended to reflect the situation, needs, and understanding of 

oil and gas resources most relevant to the needs of the 

United States at the present time. 

RESOURCE CLASSIFICATION 

Experience has shown that most disagreements concerning oil and gas resource evaluation originate in misunderstandings of terminology or classification. When 

classification schemes and terminologies are discussed and 

well understood, however, genuine differences in data and 

interpretation can be identified and addressed.· 

Recently at the U.S. Geological Survey (USGS), oil 

and gas resources have been classified according to the 

"McKelvey Box," conceived by and named for the late 

Director of U.S. Geological Survey, Vincent McKelvey, a 

man passionately interested in resources and their evaluation. The McKelvey box (fig. 1) bas two axes and two 

variables: (1) degree of geologic certainty or assurance and 

(2) economic feasibility or technical producibility. The degree of geologic certainty or assurance, which is plotted 

495 
496 THE FUTURE OF ENERGY GASES 

Figure 1. Diagrammatic representation of petroleum resource 

classification. Figure represents conventional oil and gas resources. Area within heavy frame on upper right represents undiscovered resources. Hachured area indicates quantities of undiscovered 

resources that are estimated to be economically recoverable. Modified from U.S. Geological Survey and U.S. Bureau of Mines 

( 1976, 1980). 

along the X axis, is a continuum, ranging from those resources that are known with great certainty such as oil 

being pumped up a wellbore and into a waiting tank at this 

very moment to wildly speculative occurrences of petroleum that might exist in hypothetical traps in distant, inaccessible, and unexplored regions. At the left end of the X 

axis, the most certainly known resources are the measured 

reserves. Measured reserves include all those resources 

that have been shown to exist from reliable geologic and 

engineering data in known reservoirs and which are expected to be produced in the near future using existing 

technology and infrastructure under current economic conditions. Measured reserves are generally equivalent to the 

commonly used term proved reserves and includes only 

those resources that are actually accessible through technology that is currently in use. 

Indicated reserves are those resources in known reservoirs that are expected to be added to measured reserves 

and produced through the application of improved recovery techniques. The additions to measured reserves that are 

expected as a result of the implementation of a planned 

new waterflood engineering project on an old reservoir 

with declining production in a field, part of which has already been successfully waterflooded, is a typical example 

of indicated reserves. 

Inferred reserves are identified resources that can be 

expected to be added to reserves by additional drilling in 

extensions of known fields and by discovery of new pay 

zones, as well as by net upward revisions of previous reserve estimates. 

Taken together, indicated reserves and inferred reserves 

account for most reserve growth (also known as reserve 

appreciation) in the United States. Additions to U.S. reserves in recent years have come more from reserve appreciation (indicated and inferred reserves) than from new field 

discoveries. Reserve appreciation has increasingly become 

a topic of great interest to the United States because of the 

magnitude of the reserves being added in this category. 

The vertical axis of the McKelvey Box (fig. 1) reflects 

economic feasibility or cost versus value for the resource. 

Virtually any of the resource classifications discussed 

above can be economic, marginally economic, or noneconomic depending on a variety of factors. For example, a 

heavy oil accumulation can be well understood and thoroughly delineated such that volume of oil within the deposit is known with great certainty. The resource may not, 

however, be economic because the cost of extracting the 

oil using specialized techniques such as steam flooding and 

closer well spacing may exceed the expected value of the 

oil to be recovered. At the other extreme of the scale of 

geologic certainty might be undiscovered resources that, 

even if found, would be noneconomic. An example might 

be a small prospect for oil or gas in deep water or under 

thick ice in northern Alaska. Only the largest of U.S. oil 

fields would be economically developable under these circumstances because of the large reserves and high production levels required to justify the necessary investments to 

develop and produce oil from these regions. 

There are a number of potentially confusing and contentious issues surrounding the McKelvey Box classification. In particular, the resources accounted for on the 

McKelvey Box are essentially unbounded. The limits of 

economic viability or geologic certainty must be provided 

by the user. In the extreme, methane gas in the atmosphere 

of Jupiter could be classified and shown on the McKelvey 

Box as an identified but subeconomic resource. In principle, the entire crustal abundance of any resource could be 

placed in the framework of the McKelvey classification, 

even though such a broad definition of resources is not 

relevant to human activity in the foreseeable future. 

Measured, indicated, and inferred reserves are collectively classified as identified resources. Undiscovered resources, conversely, are those resources postulated to exist 

on the basis of geologic knowledge and theory. Such resources belong outside "the bounds of identified resources 

on the McKelvey Box. Undiscovered resources may range 

from accumulations that can be inferred to exist from seismic records to rather vaguely defined accumulations that 

have only postulated existence based on conceptual or 

conjectural evidence. For example, well defined but ondrilled structural traps in areas of known discoveries might 

be considered to contain undiscovered resources at a high 

level of confidence. The important thing about undiscovered resources is that they have not yet been sufficiently 

delineated with geologic or engineering data to constitute 

a body of proof to which one can refer. 

Certain commonly used terms and categories are not 

explicitly illustrated on the McKelvey Box. For example, 

conventional resources are those that exist in more or 
U.S. GEOLOGICAL SURVEY ESTIMATES OF NATURAL-GAS ENERGY RESOURCES 497 

less discrete accumulations and that are amenable to extraction using traditional development practices. Conventional resources can be either identified or undiscovered. 

Those categories of resources not included with the conventional resources are lumped together as unconventional resources. This rather diverse and poorly defined 

category includes, among other varieties, gas resources in 

low-permeability reservoirs such as tight-gas sands, gas 

bound up with ice in hydrates, coalbed gas, gas in fractured shale reservoirs and gas in geopressured brines. Unconventional resources can be either identified or 

undiscovered and can range across the entire spectrum of 

the economic assurance axis. 

Resources may change their position or classification 

on the McKelvey Box through advances in technology or 

changing economics. Indicated and inferred reserves are 

defined as being transitional, as they are fully expected to 

become proved reserves in the future if they .are economic. 

Undiscovered resources, if predicted correctly, should one 

day be discovered, although some probably will not be. 

Today's unconventional resource could be tomorrow's conventional resource. The changing classification of resources, economic conditions, and technology make comparisons 

between resource assessments conducted at different times 

extremely difficult. The 1909 oil assessment of David Day 

(1909) now seems rather like an attempt to qualitatively 

estimate remaining reserves in well-known anticlinal structures. All assessments must be considered in the context of 

their time and their purpose. At their best, resource assessments constitute scientifically based hypotheses that incorporate available information about resources and future 

additions to reserves. Each assessment should build on previous ones and on information gathered by the exploration 

and production process. As such, each assessment should 

constitute a refinement of previous work, becoming ever 

closer to the "correct" answer. The correct answer will only 

be known with certainty when the last well is drilled and 

the last resources are extracted. 

ASSESSMENT CONCEPTS 

The assessment of unknown quantities of natural resources such as oil and gas must be viewed as the development of hypotheses and not as inventories of some 

clearly known but as yet unmeasured commodity. Undiscovered resources are not really analogous to cans of uncounted green beans on a grocery store shelf. A better 

analogy might be the attempt to estimate the amounts of 

canned green beans from high-altitude imaging of grocery 

stores and delivery trucks. 

Resources have been estimated using many methods, 

each of which has enthusiastic proponents and incisive critics. Each methodology requires different kinds and amounts 

of information and each area or commodity being assessed 

is best approached using a specific methodology type. Every 

method has inherent power as well as limitations. No single 

method can be applied successfully in all situations. 

PRINCIPLES OF RESOURCE 

ASSESSMENT 

Nearly all assessments are based on two basic concepts-analogy and exhaustion. According to the concept 

of analogy, resources are distributed as a consequence of 

the operation of natural processes that can, in principle, be 

understood and predicted. An area selected for assessment 

is defined in terms of its geologic properties, and geologically similar areas (the analogs) are identified in which 

sufficient drilling has occurred to effectively define the resource. The number, size, and distribution of resource accumulations within the analogs are then assumed to be 

similar to the number, size, and distribution of undiscovered resources within the area selected for assessment. For 

example, if an area to be assessed is identified in which 

undiscovered resources are thought to be entrapped within 

as yet untested diapiric salt structures, the analyst might 

examine other areas in which salt dome structures have 

been demonstrated to include significant oil or gas accumulations. Success in predicting properties of unknown resources depends on the adequacy and applicability of the 

analog and on the ability of the analyst to apply it. If, for 

example, two blocks of land within a single area such as 

the Louisiana-Mississippi salt province differ only in that 

one has been intensively explored through drilling and the 

other remains untested, then the size, number, and distribution of resources in the intensely explored block can be 

used to predict undiscovered resources in the untested 

block. If, however, a salt dome area is identified within the 

Basin and Range Province of southern Arizona, the salt 

dome region of the Louisiana gulf coast may or may not 

serve very well as an analog. In this case, the areas might 

have salt diapirs in common but little else, and selection 

of a different analog might be necessary. 

In almost every case geologic analogs differ from the 

subject area in some way and to some degree. If the analog is valid, but some variation is expected, then evaluations of the unknown resources in the area of interest can 

be modified to reflect the expected departures from the analog. For example, in the case of the two blocks in the 

Louisiana-Mississippi salt province, if the untested block 

seems identical to the analog except that the structures are 

slightly larger or smaller, the expected resources should be 

adjusted accordingly. 

Exhaustion is the concept that within any specified 

area, given sufficient exploration activity, part or all of the 

resource will be discovered. Discoveries within the area are 

thought to be made from a natural population of accumulations and without replacement. The concept of exhaustion 
498 THE FUTURE OF ENERGY GASES 

is expressed using various types of historical information. 

This information may include the fraction of surface area or 

rock volume drilled, the rates or volumes of resources 

found as a function of time or drilling, the size and number 

of fields discovered in historical sequence, or various other 

extrapolation techniques based on historical performance. 

The past performance of the area is thought to be a reliable 

basis for predicting the future. Historical data are fitted into 

some sort of mathematical functional form that permits extrapolation of past performance into the future. 

Crucial to many methods of resource evaluation and 

corollary to the concept of exhaustion is the premise that 

the largest accumulations tend to be found earlier in the 

exploration history of any specific area. We emphasize that 

the operational concept in the preceding sentence is "earlier." The average size of discovered fields within any particular basin or play tends to decrease systematically with 

time and (or) with exploratory effort. For example, figure 2 

illustrates the shifting size-frequency histograms of fields 

found within the Frio Strandplain play of the Texas gulf 

coast (Schuenmeyer and Drew, 1991 ). By extension, within 

even broad areas accessible to drilling, the largest accumulations tend to be found first. The early discovery of the 

largest fields occurs because the larger fields occupy the 

most prominent and easily identified features and because 

the large fields generally occupy larger areas than small 

fields. In the lower 48 United States the average size of the 

oil and gas fields found has been declining systematically 

through time. For example, the largest gas field found in 

the United States prior to 1955 contained about 70 trillion 

"0 

£' 

Q) 

> 0 

u 

(/) 

i5 

(/) 

"0 

a; 

'<= 

0 

(i) 

.0 

E 

::J 

z 

80 

70 

60 

50 

40 

30 

20 

4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 

Fi eld-size class 

Figure 2. Example of observed field-size distribution for oil and 

gas plays from the Frio Strandplain play, Texas, showing that 

sizes of fields decrease with time and the typical three segments 

that represent cumulative number of fields discovered through 

the specified year. Modified from Schuenmeyer and Drew 

(1991). 

cubic feet (Tcf), whereas the largest field found since 1955 

has not exceeded 6 Tcf. 

ASSESSMENT METHODOLOGIES 

In spite of the advanced state of knowledge of the origin, migration, and entrapment of oil and gas, there is no 

certain way, short of drilling, to directly measure how 

much oil or gas will be discovered in a sedimentary basin. 

The amount of oil or gas must be determined by drilling 

and production, by extrapolation of historical information, 

or by analogy with geologically similar areas of oil and 

gas production. Within this framework several methods 

are possible. 

Resource assessments can be done at a variety of geographic and geologic scales. The purpose of the assessment, 

the availability of data, and the constraints of time dictate 

the method by which an assessment is performed. Credible 

assessments have been conducted over broad regions 

(countries or continents) using historical extrapolation techniques (for example, Hubbert, 1967) Basin-wide assessments usually depend on basin or volumetric analogs, but 

basins also can be analyzed by extrapolating cumulative 

volumes discovered versus cumulative exploratory effort. 

Some recent assessments have been done using play-modeling techniques. Plays are groups of discovered accumulations and (or) prospects that are grouped together on the 

basis of geographic proximity and geologic similarity. A 

wide variety of assessment methods have been developed 

and applied at the play level. To construct assessments for 

larger areas or volumes of sedimentary rock, these lower 

level (play) assessments can be aggregated. The oil and gas 

industry commonly evaluates areas at the prospect level 

and then aggregates prospects into plays and plays into regional assessments. This approach normally requires extensive seismic data coverage to identify prospects and 

estimate accumulation size. Many assessments, however, 

are conducted by organizations (for example, the USGS) 

that do not normally have access to extensive seismic data. 

When this is the case, other types of information and other 

techniques must be used for assessment. 

Volumetric- or areal-yield models are based on the notion that the amount of oil or gas per unit volume of rock 

can be extrapolated from an area of known oil or gas occurrence to some unexplored but analogous volume of 

rock. This method depends entirely on the validity of the 

analog and on the degree of application of the analog to 

an appropriate rock volume. The concept of volumetrics, 

beginning with the innovative studies of Weeks ( 1950) and 

Zapp (1961, 1962) has been applied to local areas, basins, 

regions, countries, continents, and the entire planet. The 

concept of volumetrics was well stated by V.E. McKelvey 

( 1961 ): "Thus, oil occurs in sedimentary rocks and the 

range in quantity of oil and gas contained in certain large 
U.S. GEOLOGICAL SURVEY ESTIMATES OF NATURAL-GAS ENERGY RESOURCES 499 

and well explored sedimentary basins has been estimated; 

the total volume of sedimentary rocks in the United States 

and the world has also been estimated, and the combination of these two values, plus an estimate of how much oil 

can be recovered from the ground, make it possible to estimate potential recoverable reserves of oil and gas." 

Most assessment methods probably employ volumetric 

considerations to some degree. The direct and exclusive use 

of analog volumetrics is especially useful in those areas 

where little or no drilling information is available and 

where a small staff must evaluate a large area. In this case, 

the arialog may provide the only available way of evaluating undiscovered resources. Volumetrics overestimate undiscovered resources in many cases. The view that the 

unexplored volume of rock contains the same proportion of 

resources as the explored portion of rock seems to assume 

that there is no exploration efficiency and that explorationists are unable to selectively identify the most promising 

areas to drill first. Volumetric assessments have yielded 

some of the largest estimates of resources of any assessment methodologies. 

Historical-performance and production-process models 

are based almost entirely on the concept of exhaustion and 

use historical information as a means of predicting future 

performance. In these methods, the actual drilling records, 

success rates, production rates, and related information are 

fitted to mathematical forms that are extrapolated to forecast future performance. Commonly used approaches include studies of rates of production per year and cumulative 

production, numbers of successful discovery wells as a 

function of time or drilling activity, and volumes of oil or 

numbers of fields found through time or with drilling activity. The basic concept of these historical performance studies was stated by Hubbert (1967): "Because gas and oil are 

exhaustible resources, the discovery and production history 

of these fuels in any particular area must be characterized 

by a beginning, a period of increase, a period of decline, 

and ultimately, an end." 

Discovery and production process models are especially attractive because they are rigorous, quantitative, 

and reproducible. The process models generally rely on 

statistical information and put very little emphasis on geological inference. The models work best if they are used in 

evaluating a population of accumulations and related rates 

of new-field discoveries that are within a clearly and narrowly specified set of geologic, temporal, and spatial 

boundaries. Historical performance models cannot be used 

in frontier areas where little or no drilling has taken place. 

DISCOVERY PROCESS AND 

FINDING RATES 

Where there is sufficient exploration history, an effective assessment approach is to extrapolate from the sequence of field discoveries what remains to be discovered, 

both in terms· of field sizes and their aggregate resource 

value. These approaches are variously termed "discoveryprocess models" or "finding-rate models." These models, 

in their more sophisticated forms, were pioneered by Arps 

and Roberts (1958), Drew (1974), and Barouch and Kaufman (1975). At their best, they are conducted at a play 

level by identifying and using natural populations of fields 

that are identifiable from their common geologic characteristics of trap, reservoir, seal, and source (Canada Department of Energy, Mines, and Resources, 1977; Lee and 

Wang, 1986; Podruski and others, 1988). In a subjective 

format, discovery process was part of the analysis of field 

sizes employed in the 1989 USGS National resource assessment (Mast and others, 1989; Houghton and others, 

1993 ). Various specific methodologic approaches can be 

used, and these are often highly statistical in nature. The 

discovery-process method has been successfully employed 

in the Permian basin, West Texas, and southeast New 

Mexico by Drew and others (1979), as well as in various 

plays of the U.S. Gulf Coast (Schuenmeyer and Drew, 

1991 ). Sufficient data are needed concerning exploration 

effort and discovery. The reader is referred to White and 

Gehman (1978) and Miller (1986) for further discussion of 

these methods. 

The primary criticism of the discovery-process and 

finding-rates methods is that they are inherently conservative. That is, because they are entirely based on past performance, they leave little room for improvements in 

exploration technology, economics, or imagination. These 

methods do not allow for the surprises of exploration that 

so commonly occur. 

DEPOSIT SIMULATION 

The deposit-simulation method is a volumetric calculation of resources based on measurement or estimation of 

the physical properties of traps, reservoir rocks, and fluids 

and of the temperatures, pressures, and fluid dynamics of 

the host environment. This method has the advantage of 

working directly with the basic geologic properties of accumulations and dealing with them in a rigorous, quantitative manner. It allows for simulation of the hydrocarbon 

deposit(s) through modeling their geologic properties. 

Consequently, subjectivity is introduced and uncertain parameters can be represented as estimates expressed in 

ranges of values, accompanied by probabilities of occurrence (probability distributions). The approach, therefore, 

uses stochastic and probabilistic methods, as well as statistical methods. An example of input for this type of approach is shown in figure 3. A general resource assessment 

model using these inputs has been described by the Canada Department of Energy, Mines, and Resources ( 1977), 

U.S. Department of Interior (1980), Dolton and others 
500 THE FUTURE OF ENERGY GASES 

Prob~bility of Favoubl~ Comments Attribute or Prc1ent 

Hydro~rbon Source /.0 

Timing r.o 

::;- Migr41tion /.0 

0: Potenti~l Reservoir Facies 1.0 

M.Jrginat Play Probability /. 0 

Trapping Mechanism 0.6 

o: Etfec:tive Porosity (-3'%) /.0 . ~ 

2-~ 0- Hydrocarbon Acc:umulation 0.7 ci:~ Conditional Oeposit 

Probability O.lt2 

Reservoir lithology S.nd X Carbonate 

Hydrocarbon Gas 1.0 Oil 0 

~ Probability of equal to or greater than 

. 1009575502550 

Area of Oosure 0.3 0.4- O.<j /.7 3.0 H b.2 E (xtol Aeresl 

~ Reservoir Thick· 

e ness/vertical /0 20 35 so 70 IOD 120 ~ doSIJre (Fd 0 

> 

c 

~ Effective Porosity 5 5.2 {, g 10 14- zo % 

~ Trop Fill (%1 :I: /0 25 ~s 60 75 ?O !00 

Reservoir Depth 

(xtol Ftl 18 J9~S \'\'~ 2.0 'f,f)';> '~-\s 22 

HC Saturation (%) {,0 {,5 70 75 -80 [M 90 

No. of dritlabte prospecu !0 (2 /J,. 15 17 zo n 

(a olav chnacwiniel 

Figure 3. Oil and gas appraisal data form completed for hypothetical deep natural-gas 

play. From Crovelli and Balay (1988) and Dolton and Crovelli (1992). 

(1987), and has been published by Crovelli and Balay 

(1986, 1988, 1990). 

The calculation of gas volume of a deposit is based on 

a fundamental reservoir engineering formula. Basic to the 

calculation is the determination of reservoir volume. The 

dimension of the gas container is critical, whether it be a 

single homogeneous reservoir rock in a conventional trap, 

a compartment of lesser size within a larger reservoir, or a 

heterogeneous reservoir of great size associated with an 

unconventional basin-center gas occurrence. 

The reservoir engineering formula used in deposit 

simulation or reservoir performance models is expressed 

as follows: 

Gas volume (ft3)=43,560 A·F·H·Por-(1-Sw)(Pr/Tr) 

( 1/Z)(Tsc/Psc ), 

where A is the area of closure (acres), F is the trap fill 

(decimal fraction), H is the reservoir thickness (ft), Por is 

the porosity (decimal fraction), Sw is the water saturation, 

Pr is the original reservoir pressure, Tr is the reservoir 

temperature (degrees Rankine), Psc is the pressure, standard conditions, Tsc is the temperature (degrees Rankine), 

and Z is the gas compressibility factor. 

Simulation of an accumulation or of an aggregate of 

accumulations requires that the parameters be expressed as 

ranges of values, accompanied by probabilities of occurrence 

(probability distributions). The probabilities should represent the natural variability of geologic characteristics and the 

assessor's uncertainty about them. Hence, the values derived 

represent the array of possibilities that might be encountered 

at a randomly selected prospect within a population. 

The modelling of gas-saturated reservoir volumes is 

affected by various geometric constraints. White (1987) 

and Abrahamsen (1989) discuss some of these geometric 

considerations as they may be applied when dealing with 

reservoir thicknesses within closures. For example, reservoir thickness is a function not only of the available stratigraphic thickness of the reservoir unit and of the effective 

porosity within it, but of the position of the gas-water con-
U.S. GEOLOGICAL SURVEY ESTIMATES OF NATURAL-GAS ENERGY RESOURCES 501 

tact and the configuration and size of the trap and its fractional fill. Where sufficiently mapped, thickness can be 

measured or, alternatively, gross hydrocarbon-bearing reservoir volume can be calculated directly from planimetered areas (Pirson, 1950), thereby combining the variables 

of reservoir thickness, area, and trap fill. 

Porosity and water saturation are the internal physical 

characteristics of the reservoir that determine contained hydrocarbon volumes. The porosity values used must meet an 

assigned minimum threshold value to qualify as "effective 

porosity." It is important that this same minimum value be 

adhered to during measurement of reservoir thickness and 

in the risking of attributes. Water saturation can be estimated directly or on the basis of an algorithm that relates 

water saturation to the average porosity of the reservoir. 

In this sort of model it is necessary to deal with engineering factors, including estimation of the thermal and pressure 

conditions of the simulated reservoir and trap. In addition, 

the compressibility factor of the gas (Z) must be calculated 

on the basis of known or estimated gas composition. 

Adequate framing of the basic geologic model or 

models of occurrence is essential to assessment, both in 

terms of assignment of risk to the variables controlling the 

occurrence of gas and to the assessment of volume parameters. The rock and fluid characteristics identified and investigated in companion studies are critical and include 

physical properties of reservoirs, such as thickness, distribution, porosity amount and variation, pore geometries 

and dimensions, trap types and dimensions, effectiveness 

of seals, physical environments of accumulations (including depths, present and past thermal conditions, pressure 

regimes, and fluid dynamics) and saturations and properties of the involved fluids (their composition and physical 

state). The availability of data for these characteristics and 

their sufficient quantification ultimately determine the adequacy of results. Development of relevant data bases is a 

requirement for assessment. 

The deposit-simulation method provides not only an 

overall resource assessment but a description of the individual accumulations in terms of their geologic characteristics 

and their contained gas and affords an easily updatable assessment record. It estimates resources in place and does 

not tell the user directly about their recoverability or producing characteristics, although it permits use of known or 

estimated recovery factors. The method is flexible in that it 

allows the geologist to model the geologic conditions controlling the resource. This allows for a wide range of resource values for a wide range of geologic conditions. 

The actual production characteristics of reservoirs that 

lead to recoverability are best determined by engineering 

studies of the reservoir rocks and fluids themselves, including reservoir drive and pressure characteristics, reservoirrock permeability, and fluid composition and properties. 

Such studies are especially critical for evaluation of "tight" 

(low-permeability) gas reservoirs. 

Although the preceding discussion focuses on the 

modeling of reservoirs, the deposit-simulation method also 

requires that estimates be made of the number of deposits 

remaining to be found. This number is an uncertain quantity that depends on the number of prospects and the probability that a random prospect will contain hydrocarbons. 

RESERVOIR PERFORMANCE 

Reservoir-performance methods are especially applicable to unconventional resources such as tight-gas sands or 

autosourced shales, . within which a single sedimentary 

rock serves as source bed, reservoir, trap, and seal for oil 

and (or) gas accumulations. In this class of resources, the 

in-place resource is known with some certainty to be. large 

and to extend over a wide area. The most significant questions concern the portions of these resources that might be 

extracted and the expected rates of extraction. Reservoirperformance methods are being developed by the USGS 

for evaluation of unconventional resources. 

Reservoir performance is an empirical method that relies on production data that are extrapolated to permit a 

calculation of ultimately recoverable resources, based on 

certain economic and technologic assumptions and well 

spacing. This method, which incorporates various production-decline-curve methods, cumulative-production-curve 

methods, material-balance methods, and other methods, relies heavily on a careful engineering approach. Detailed 

discussion of this method is beyond the scope of this 

paper. The reservoir-performance method is useful in a 

reservoir that has seen some development, as locally may 

be the case in a tight-gas reservoir, or for reserve calculations within a developed field. This method deals not only 

with the basic physical characteristics of the reservoirs and 

fluids, but it also measures, over time, how production and 

reservoirs respond to development controlled by both technologic and economic factors. This can be a very effective 

method of resource· assessment in areas where there has 

been a sufficient history of production. However, the assessor often does not have sufficient information to satisfy 

the method, except on an analog basis. 

MASS BALANCE 

Mass-balance calculations have been used by various 

workers as a tool for estimation of resources. This method 

deals with the amount of oil and (or) gas generated, on the 

basis of geochemical data, the amount that is expelled and 

migrated, and the amount that is finally retained in traps. 

Because of the difficulty and uncertainty in quantitatively 

assessing several of these variables, this method has been 

useful mostly in a qualitative sense, identifying the probable hydrocarbon composition, the migration history and 
502 THE FUTURE OF ENERGY GASES 

adequacy of charge, and the general resource potential. This 

method is particularly useful in identifying critical geologic 

elements and processes needed for resource evaluation. In 

very well studied areas containing the requisite information, 

it may be applied as an estimation method. The mass-balance 

approach has the potential to provide quantitative methods of 

estimating resources in advance of drilling, although as of 

yet only analyses after the fact have been conducted. At 

present, the most significant problems with mass- and material-balance approaches relate to as yet unresolved uncertainties in basic geochemical measurements and parameters, 

including primary migration, time-temperature range of oil 

and gas generation, migration and trapping efficiency, and 

preservation. Although as of yet largely inadequate for quantitative assessment, the material-balance approach continues 

to hold promise for linking geological and geochemical research to assessment methodology in a direct way. 

HISTORY OF U.S. GEOLOGICAL SURVEY 

ESTIMATES OF NATURAL-GAS 

RESOURCES 

Natural gas was first produced and sold as fuel for 

home lighting in 1821 at Fredonia, New York. Steadily increasing but small-scale use of gas as a fuel for heating and 

lighting occurred in the United States until 1878, when the 

first large gas field was found in the United States near 

Murrysville, Pennsylvania. Following the Murrysville discovery, the availability and demand for natural gas expanded dramatically. Following 1918, when one of the first 

estimates of the reserve of natural gas was published, the 

amount of natural gas marketed annually expanded from 

721 billion cubic feet (Bet) to a current level of roughly 

18 Tcf. Concerns about the natural-gas supply have caused 

interested parties to question the adequacy of the volumes 

of gas remaining to be discovered. 

Early estimates of fossil-fuel resources commonly did 

not deal with natural gas but focused on oil or coal. Natural-gas resources were more often evaluated on a local 

scale for specific market deliverability and field management. Estimates on a National scale appeared only fitfully 

at first, although with increasing frequency through time. 

From 1930 to 1938 several estimates were made of 

natural-gas reserves in the United States. Prior to the beginning of the systematic annual reporting of natural-gas 

reserve estimates by the American Gas Association (AGA) 

in 1946, reporting of gas reserves was done by various 

individuals and agencies. During World War ll, estimates 

were made by the Petroleum Administration for War. 

Since cessation of AGA reserve estimates in 1979, the Energy Information Administration (EIA) has reported annual 

estimates of gas reserves. 

Estimates of undiscovered gas resources for the Nation 

are far less common. They first date from 1919, when an 

estimate of total recoverable and marketable reserves in 

both discovered and undiscovered fields of the United 

States was made by Eugene W. Shaw, valuation engineer in 

charge of natural gas, U.S. Internal Revenue Bureau, and 

USGS geologist. In a paper presented at the annual meeting 

of the Natural Gas Association of America, Cleveland, 

Ohio, May 20-26, 1919, Shaw (1919) stated that the total 

recoverable and marketable reserves in both discovered and 

undiscovered pools in the continental United States were 

probably 5 to 15 Tcf. This estimate represented an amount 

equivalent to 30-50 percent of the original supply, then 

estimated to have been 50-75 Tcf in both discovered and 

still undiscovered pools. At that time, about 10 Tcf had 

been produced. 

Many years later, L.F. Terry (1950) estimated the ultimate recoverable gas reserves in the United States, including the continental shelves, to be 510 Tcf. His estimate 

was based on the assumption that the search for and production of the amount of oil called for by Weeks' (1948) 

estimate of ultimate reserves, would result in the discovery 

of 6,000 cubic feet of gas for each barrel of oil discovered. The estimation of undiscovered or ultimate recoverable gas resources has proceeded episodically since. 

The USGS, along with a variety of other groups, organizations, and individuals has been engaged in this assessment of undiscovered natural gas resources. After a hiatus 

following Shaw's (1919) paper, the USGS developed a series of estimates of natural-gas resources that were published beginning in the late 1950's. The first, published in 

1956 (U.S. Department of Interior, 1956), estimated that 

ultimate gas reserves in the United States were at least 

1,000 Tcf, or more than twice Terry's (1950) estimate of 

410 Tcf. In 1950, more than 260 Tcf had already been discovered (U.S. Geological Survey, 1951). 

In 1961, A.D. Zapp of the USGS used an extrapolation 

of data from exploratory drilling successes, combined with 

a geologic favorability factor derived from Weeks' (1959) 

estimates, to assess ultimate natural gas resources (Zapp, 

1961). Assuming then-current technology and economics, 

Zapp estimated ultimate natural-gas resources of the United States (including Alaska) to be 1,800 Tcf, with addition-

. al submarginal resources of 850 Tcf. According to Zapp 

(1961), of the ultimate resource, approximately 275 Tcf 

had been produced through 1960. Zapp incorrectly quoted 

38 Tcf as proved reserve. At the time, AGA proved reserves were listed as 264 Tcf. Variants of these estimates 

(including errors) were reported by McKelvey (1961) later 

that year. McKelvey (1961) listed known reserves of 

38 Tcf, potential reserves of 1,525 Tcf, and potential marginal resources of 850 Tcf. 

In 1965, T.A. Hendricks estimated original, in-place, 

economically recoverable gas resources to be 2,000 Tcf, 

with an additional 2,000 Tcf of "submarginal" gas resources (Hendricks, 1965). These gas estimates were derived 

through gas-oil-discovery ratios from estimates of oil. The 
U.S. GEOLOGICAL SURVEY ESTIMATES OF NATURAL-GAS ENERGY RESOURCES 503 

oil estimates were based on richness factors for explored 

and unexplored areas. At the time of Hendricks' (1965) 

work, cumulative production stood at 230 Tcf and proved 

reserves were listed by AGA at 268 Tcf, plus an unknown 

amount of inferred reserve. These figures suggest that 

Hendricks estimated undiscovered resources to be about 

1,080 Tcf, with an additional 202 Tcf in the inferred reserve (Miller and others, 197 5). 

In 1967, M. King Hubbert, working at USGS, published a refinement of the innovative work he had first released in 1956 and updated in 1962 (Hubbert, 1967). His 

analysis, based on statistical extrapolation of finding rates 

for oil and on a gas-oil-discovery ratio, yielded estimates 

of 900-1,200 Tcf of ultimately recoverable gas for the 

United States, excluding Alaska. Hubbert (1967) estimated 

that of the ultimately recoverable resource, 747 Tcf had 

already been discovered. Two years later, using the same 

method, Hubbert (1969) made a point estimate of ultimate 

recoverable gas of 1,044 Tcf (excluding Alaska) and estimated that approximately 826 Tcf of natural gas had been 

discovered. 

Theobald and others ( 1972), stated that undiscovered 

recoverable natural gas resources were estimated to be 

2, 100 Tcf and "submarginal" (noneconomic) resources 

were estimated to be about 4,000 Tcf. This estimate included Alaska and the U.S. continental shelves out to 

water depths of 2,500 m (8,200 ft). The method of 

Theobald and others (1972), using methodology developed 

by A.D. Zapp and T.A. Hendricks, applied the historical 

results of past exploratory drilling to unexplored rocks on 

an equal basis for all of the favorable strata of the United 

States. The methodology was a virtually pure volumetric 

estimate and was one of the largest estimates of U.S. resources ever published. 

Thus, for several years, the USGS had been publishing resource estimates that varied widely in both methodology and in results. Moreover, the widely divergent gas 

estimates were associated with estimates o-f oil resources 

that diverged even more. Two principal schools of thought 

had been developing at the USGS. One school, Jed by 

McKelvey and his colleagues Hendricks, Zapp, and 

Theobald, relied mainly on volumetric approaches and 

held a highly optimistic view of the United States oil and 

gas resource situation. The other school centered about 

Hubbert, whose extrapolations from historical information 

suggested that the United States was a country with an 

energy industry about to go into decline. These disparate 

and at times hostile viewpoints gave the public the (correct) impression that there was no monolithic or even coherent position on resources among the scientists at the 

USGS. In part because of the apparently critical issues of 

energy supply facing the United States after the OPEC oil 

embargo of I 973 and in part because of the seemingly 

chaotic approach having been taken to resource evaluation 

at the USGS, a new Branch of Oil and Gas Resources was 

formed within the Geologic Division. That branch was 

charged with conducting research to evaluate the Nation's 

oil and gas resources. 

On March 26, 1974, the USGS issued a news release 

estimating the natural-gas resources of the United States to 

be in the range of 1,000-2,000 Tcf; with inferred reserves 

of 130-250 Tcf. This estimate was said to include both 

Alaska and resources offshore to water depths of 200 m. 

This seeming revision of. the Theobald and others' ( 1972) 

estimate reflected the views of Peter Rose and other members of the newly formed Branch of Oil and Gas Resources at the USGS. The Branch of Oil and Gas Resources 

Resource Assessment Group (RAG) was organized for the 

express purpose of systematically evaluating the oil and 

gas resources of the United States. The press release of 

March 26, 1974, reflected a quick estimate developed 

using both Delphi (Baxter and others, 1978) and a volumetric method called ANOGRE (Mallory, 1975a, b). 

Following the press release, the Branch of Oil and 

Gas Resources undertook two systematic, labor-intensive 

resource assessments. The first of these was published by 

B.M. Miller and others (1975), who stated that conventionally recoverable undiscovered natural-gas resources 

were estimated to range from 322 to 655 Tcf, with a mean 

value of 484 Tcf; the inferred reserves were estimated at 

202 Tcf. The Miller and others (1975) group used a modified Delphi method based on a volumetric- and areal-yield 

analysis, coupled with analog evaluations. The estimates 

included, as usual, Alaskan resources and resources under 

water to depths of 200 m. The second assessment effort 

was led by G.L. Dolton and used a modified Delphi method based on volumetric-yield analysis, as well as finding 

rates, and analogy. The work culminated in the publication 

of a report by Dolton and others ( 1981 ). In that report, 

undiscovered conventionally recoverable resources of natural gas were estimated to range from 475 to 730 Tcf, 

with a mean value of 594 Tcf. Dolton and others (198 I) 

estimated inferred reserves of 178 Tcf. 

In 1982, James Watt, Secretary of the Interior, formed 

the Minerals Management Service (MMS) from a core of 

royalty management and leasing personnel previously employed in the Conservation Division of the USGS. Although the Conservation Division had previously been 

only peripherally involved in USGS assessment activities, 

it was the wish of the management at the Department of 

the Interior that resource estimation and leasing for the 

federal offshore areas be consolidated in the MMS. As a 

consequence, the Director of the USGS signed an agreement relinquishing all responsibility for assessment of the 

Federal offshore areas to the MMS. 

In 1989, R.F. Mast and others completed a joint 

USGS-MMS assessment of the undiscovered, conventionally recoverable oil and gas resources of the United States, 

with the USGS being responsible for onshore and State 

offshore areas and the MMS assuming responsibility for 
504 THE FUTURE OF ENERGY GASES 

the Federal offshore. The assessment utilized, for the first 

time at USGS and MMS, a play analysis approach (Baker 

and others, 1984) based on field size and number and discovery history (for example, Mast and others, 1989; 

Houghton and others, 1989, 1993). Included in the assessment was a numerical estimate of additions to reserves 

through reserve appreciation (Root and Mast, 1993 ). In 

their assessment, Mast and others ( 1989) estimated undiscovered, conventional natural-gas resources to be between 

307 and 507 Tcf, with a mean value of 399 Tcf and inferred reserves of 99 Tcf. 

Results from recent USGS assessments of natural "gas 

are shown graphically in figure 4. The figure plots gas in 

trillion cubic feet versus years for the United States. Various 

categories of resources are then plotted one on top of another. The lowermost curve is the generally well accepted values for cumulative U.S. gas production. The second curve 

represents the cumulative production plus proved reserves. 

In this curve, proved reserves for each year have been plotted atop the appropriate years value for cumulative production. The uppermost complete curve represents the total of 

cumulative production, proved reserves, and a new estimate, based on recent Energy Information Administration 

(EIA) data, for the inferred reserves. Superimposed on these 

three curves are the various USGS estimates discussed in 

this paper. The USGS 1956 assessment is plotted as a point 

estimate, as it only purported to show the ultimate amount 

of United States reserves. Similarly, Theobald and others' 

( 1972) estimate is plotted as a single point. The other assessments, however, are plotted on top of cumulative production and proved reserves at the time of the estimate. 

Further, the estimates are plotted from a base that includes 

the evaluation of inferred reserves (reserve growth) given in 

each specific estimate. Figure 4 seems to indicate that, excluding the Theobald and others (1972) estimate, other assessments have been fairly close in their evaluations of the 

undiscovered gas resource; however, all assessments would 

appear to have been systematically low in their evaluation 

of future reserve additions to be expected from reserve 

growth. 

The USGS and MMS are currently (summer, 1993) 

about midway through yet another joint assessment of the 

oil and gas resources of the United Sates. The new assessment, while retaining the play analysis approach developed by Mast and others, has been expanded somewhat in 

scope to reflect the changing energy situation in the United States. In particular, the new assessment" will include 

expected additions to reserves from all sources. The assessment will include a more systematic and comprehensive evaluation of reserve growth and will include one of 

the first play-level evaluations of reserve additions expected over the next two or three decades from unconventional 

sources. As with previous assessments, this latest one is 

hoped to reflect the situation, needs, and understanding of 

oil and gas resources at the time of its completion. 

2600 EXPLANATION 

2400 

2200 

- Cumulative production 

--- - Cumulative production 

+ proved reserves 

······· Cumulative production 

+ proved and inferred reserves 

... -···· 

...... -······· 

___ ... -

0

!920 1930 1940 1950 

Year 

1960 1970 1980 1990 

Figure 4. U.S. Department of the Interior and U.S. Geological 

Survey estimates of natural-gas resources. Cumulative production 

compiled from various sources. Reserves (1979-1990) from Energy Information Administration. Reserves (1935-1979) from American Petroleum Institute/American Gas Association. Reserves prior 

to 1935 compiled from various sources. Inferred reserves shown 

beneath upper (dotted) curve newly estimated from Department of 

Energy Oil and Gas Integrated Field File. Hubbert ( 1972), Miller 

and others (197 5 ), Dolton and others (1981 ). and Mast and others 

( 1989) estimates of undiscovered resources plotted relative to their 

respective estimates of inferred reserves (diamonds) rather than 

relative to the latest estimate of inferred reserves (dotted line). All 

estimates plotted with reference to date of estimate. Dates of publication shown next to plotted estimates. 

REFERENCES CITED 

Abrahamsen, K.A., 1989, Application of the resource estimation 

program FASPUM; experiences from offshore Norway, in 

Symposium of the 6th Meeting of the Working Group on 

Resource Assessment: Committee for Coordination of Joint 

Prospecting for Mineral Resources in Asian Offshore Areas 

(CCOP), Bangkok, Thailand, August 28 through September 2, 

1989, unpaginated. 

Arps, J.J., and Roberts, T.J., 1958, Economics of drilling for Cretaceous oil on east flank of Denver-Julesburg Basin: American Association of Petroleum Geologists Bulletin, v. 42, 

no. 11, p. 2549-2566. 

Baker, R.A., Gehman, H.M., James, W.R., and White, D.A., 

1984, Geologic field number and size assessments of oii and 

gas plays: American Association of Petroleum Geologists 

Bulletin, v. 68, no. 4, p. 426-437. 

Barouch, E., and Kaufman, G.M., 1975, Predicting undiscovered 

oil and gas in a play using a stochastic model of discovery, 
U.S. GEOLOGICAL SURVEY ESTIMATES OF NATURAL-GAS ENERGY RESOURCES 505 

in Davis, J.C., Doveton, J.H., and Harbaugh, J.W., conveners, Probability methods in oil exploration, American Association of Petroleum Geologists Research Symposium, 

Stanford, California: Kansas Geological Survey, 7 p. 

Baxter, G.G., and others, 1978, Workshop on the Delphi method: 

Journal of the International Association for Mathematical 

Geology, v. 10, no. 5, p. 581-587. 

Canada Department of Energy, Mines, and Resources, 1977, Oil 

and natural-gas resources of Canada, 1976: Ottawa, Ontario, 

Canada Department of Energy, Mines, and Resources Report 

EP7-1,76p. 

Crovelli, R.A., and Balay, R.H., 1986, FASP. an analytic resource 

appraisal program for petroleum play analysis: Computers 

and Geosciences, v. 12, no. 4B, p. 423-475. 

---1988, FASPUM metric version-Analytic petroleum resource appraisal microcomputer programs for play analysis 

using a reservoir-engineering model: U.S. Geological Survey 

Open-File Report 87-414A, 14 p. 

---1990, FASPU English and Metric version-Analytic petroleum resource appraisal microcomputer programs for play 

analysis using a reservoir-engineering model: U.S. Geological Survey Open-File Report 90-509B, 23 p. 

Day, D.T .. 1909, The petroleum resources of the United States, in 

Papers on the conservation of mineral resources: U.S. Geological Survey Bulletin 394, p. 30-50. 

Dolton, G.L., Bird, K.J., and Crovelli, R.A., 1987, Assessment of 

in-place oil and gas resources, in Bird, K.J .. and Magoon, 

L.B., eds., Petroleum geology of the northern part of the 

Arctic National Wildlife Refuge, Northeastern Alaska: U.S. 

Geological Survey Bulletin 1778, p. 277-298. 

Dolton, G.L., and Crovelli, R.A .. 1992, Resource assessment 

methodology for deep natural gas resources, in Dyman, 

T.S .. ed., Geologic controls and resource potential of natural gas in deep sedimentary basins in the United States: 

U.S. Geological Survey Open-File Report 92-524, p. 285-

295. 

Dolton, G .L., and others, 1981, Estimates of undiscovered recoverable conventional resources of oil and gas in the United 

States: U.S. Geological Survey Circular 860, 87 p. 

Drew L.J., 1974, Estimation of petroleum exploration success 

and the effects of resource hase exhaustion via a simulation 

model: U.S. Geological Survey Bulletin 1328, 25 p. 

Drew, L.J., Root, D.H., and Bawiec, W.J ., 1979, Estimating future rates of petroleum discoveries in the Permian Basin, in 

Hydrocarbon Economics and Evaluation Symposium, 8th: 

Dallas, Texas. 1979, Proceedings of Petroleum Engineers/ 

American Institute of Mining Engineers p. 101-109. 

Hendricks, T.A., 1965, Resources of oil, gas, and natural-gas liquids in the United States and the world: U.S. Geological 

Survey Circular 522, 20 p. 

Houghton, J.C., Dolton, G.L.. Mast, R.F., Masters, C.D., and 

Root. D.H., 1989, The estimation procedure for field size 

distributions in the U.S. Geological Survey's National oil 

and gas resource assessment, in National assessment of undiscovered conventional oil and gas resources, USGS-MMS 

Working Paper: U.S. Geological Survey Open-File Report 

88-373, p. 51-86. 

---1993, U.S. Geological Survey estimation procedure for 

accumulation size distributions by play: American Association of Petroleum Geologists Bulletin, v. 77, p. 454-466. 

Hubbert, M.K., 1967, Degree of advancement of petroleum exploration in United States: American Association of Petroleum Geologists Bulletin, v. 51, no. II, p. 2207-2227. 

---1969, Energy resources, in Resources and Man: San Francisco, W.H. Freeman and Co., National Academy of Science 

and National Research Council, Committee on Resources 

and Man, p. 157-242. 

---1974, U.S. energy resources-A review as of 1972, pt. I, 

in A national fuels and energy policy study: U.S. 93d Congress, 2d session, Senate Committee for Interior and Insular 

Affairs, Committee Print, serial no. 93-40 (92-75), 267 p. 

Lee, P.J ., and Wang, P.C.C., 1986, Evaluation of petroleum resources from pool size distributions. in Rice, D.O., ed., Oil 

and gas assessment-Methods and applications: American 

Association of Petroleum Geologists, Studies in Geology, 

no. 21, p. 33-42. 

Mallory, W.W., 1975a, Accelerated National oil and gas resource 

appraisal (ANOGRE), in Haun, J.D., ed., Methods of estimating the volume of undiscovered oil and gas resources: 

American Association of Petroleum Geologists Studies in 

Geology, no. I. p. 23-30. 

---1975b, Synopsis of procedure-Accelerated National oil 

and gas resource evaluation, in Mineral resources and the 

environment (appendix to sec. H)-Report of Panel on Estimation of Mineral Reserves and Resources: Washington, 

D.C., National Academy of Sciences, p. 1-5. 

Mast, R.F., Dolton. G.L.. Crovelli, R.A., Root, D.H., and Attanasi, 

E.D., Martin, P.E., Cooke, L.W., Carpenter, G.B., Pecora, 

W.C., and Rose, M.B., 1989. Estimates of undiscovered conventional oil and gas resources in the United States-A part 

of the Nation's energy endowment: U.S. Geological Survey 

and Minerals Management Service Special Publication, 44 p. 

McKelvey, V. E., 1961, Synopsis of domestic and world resources 

of fossil fuels, radioactive minerals, and geothermal energy: 

Preliminary reports prepared for the Natural Resources Subcommittee of the Federal Science Council, November 28, 

1961,20 p. 

Miller, B.M., 1986, Resource appraisal methods-Choice and 

outcome, in Rice, D.O., Oil and gas assessment, methods 

and applications: American Association of Petroleum Geologists Studies in Geology, no. 21, p. 1-24. 

Miller, B.M., and others, 1975, Geological estimates of undiscovered recoverable oil and gas resources in the United 

States: U.S. Geological Survey Circular 725, 71 p. 

Pirson S.J ., 1950, Elements of reservoir engineering: McGrawHill Book Company, 441 p. 

Podruski, J.A., Barclay, J.E., Hamblin, A.P., Lee, P.J., Osadetz, 

K.G., Procter, R.M., and Taylor, G.C., 1988, Part I, resource 

endowment, in Conventional oil resources of western Canada: Geological Survey of Canada Paper 87-26, p. 7-14. 

Root, D.H., and R.F. Mast, 1993, Future growth of known oil 

and gas fields: American Association of Petroleum Geologists Bulletin, v. 77, p. 479-484. 

Shaw, E.W., 1919, The income and expense of natural as production: Natural Gas Association of America, Proceedings 14th 

Annual Meeting. May 19-22, p. 479-503. 

Schuenmeyer, J.H., and Drew, L.J., 1991, Undiscovered oil and 

gas in the Frio Strand Plain trend-The unfolding of a very 

large exploration play: American Association of Petroleum 

Geologists Bulletin, v. 75, p. 1107-1115. 
506 THE FUTURE OF ENERGY GASES 

Terry, L.F., 1950, The future supply of natural gas: Gas Age, 

v. 106, no. 9, p. 58-60, 98, 100, 102. 

Theobald, P.K., Schweinfurth, S.P., and Duncan, D.C., 1972, Energy resources of the United States: U.S. Geological Survey 

Circular 650, 27 p. 

U.S. Department of Interior, 1956, Impact of the peaceful uses of 

atomic energy on the coal, oil- and natural-gas industries, in 

Peaceful uses of atomic energy: Background material for the 

report of the Panel on the Impact of the Peaceful Uses of 

Atomic Energy to the U.S. Congress Joint Committee on 

Atomic Energy, 84th Congress, v. 2, Washington, D.C., 

p. 68-89. 

U.S. Department of Interior, Office of Minerals Policy and Research Analysis, 1980, Final report of the 105(b) Economic 

and policy analysis-Alternative overall procedures for the 

exploration, development, production, transportation, and 

distribution of the petroleum resources of the National Petroleum Reserve in Alaska (NPRA): U.S. Department of Interior, 145 p. 

U.S. Geological Survey, 1951, Fuel reserves of the United States: 

Statement prepared by the U.S. Geological Survey at the request of the Committee on Interior and Insular Affairs Unites 

States Senate, Committee on Interior and Insular Affairs, 82d 

Congress. Committee Print, Washington, D.C., 49 p. 

U.S. Geological Survey and U.S. Bureau of Mines, 1976, Principles of the mineral resource classification system of the U.S. 

Bureau of Mines and U.S. Geological Survey: U.S. Geological Survey Bulletin 1450-A, 5 p. 

U.S. Geological Survey and U.S. Bureau of Mines, 1980, Principles of resource/reserve classification for minerals: U.S. 

Geological Survey Circular 831, 5 p. 

Weeks, L.G., 1950, Concerning estimates of potential oil reserves: American Association of Petroleum Geologists Bulletin, v. 34, no. 10, p. 1947-1953. 

---1948, Highlights on 1947 developments in foreign petroleum fields: American Association of Petroleum Geologists 

Bulletin, v. 32, no. 6, p. 1093-1160. 

White, D.A., 1987, Methods of oil and gas prospect and play 

assessment course manual: Oil & Gas Consultants 

International. 

White, D.A, and Gehman, H.M., 1978, Methods of estimating oil 

and gas resources: American Association of Petroleum Geologists Bulletin v. 63, no. 12, p. 2183-2192. 

Zapp, A.D., 1961, World petroleum resources, in Domestic and 

world resources of fossil fuels, radioactive minerals, and 

geothermal energy: Preliminary reports prepared by members of the U.S. Geological Survey for the National Resources Subcommittee of the Federal Science Council, 

Nov. 28, 1961, 9 p. 

Zapp, A.D., 1962, Future Petroleum producing capacity of the 

United States: U.S. Geological Survey Bulletin 1142-H, 

36 p. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

National Petroleum Council Source and Supply StudyThe Potential for Natural Gas in the United States 

By Donald L. Gautier1 and Robert L. Brown2 

CONTENTS 

Abstract .. . . .. . .. . . .. ... ... .. . . . ... . .. . .. . .. ... .. . .. . . . . . . . . .. . .. .. . . .. . . . . .. . .. . 507 

Introduction ....................................................... ............ 508 

Conventional Gas ......................................................... 508 

Existing Proved Reserves ...................................... 508 

Reserve Appreciation ............................................. 508 

NPC Analytical Approach ..... ................................ 509 

Results of NPC Analysis ....................................... 511 

Undiscovered Conventional Resources ................. 513 

Department of Energy 1988 Study ................. 514 

Energy Information Administration 1990 

Study ................................................................ 514 

U.S. Geological Survey and Minerals 

Management Service 1989 Study ................... 514 

Potential Gas Committee 1990 Study ............. 514 

Gas Research Institute 1991 Study ................. 515 

The Effect of Technological Advances ................. 515 

Nonconventional Gas Sources ..................................... 515 

Tight Gas ................................................................ 518 

Tight-Gas Potential ................................................ 519 

Devonian Shales of the Appalachian Basin 

and the Antrim Shale ............................................. 522 

Devonian Shale Resources .............................. 522 

Antrim Shale (Michigan Basin) ...................... 524 

Other Gas Shale Basins .................................. 524 

Coalbed Methane ................................................... 524 

1

U.S. Geological Survey, Denver Federal Center, Box 25046 MS 

960, Denver, CO 80225. 2Mobil Oil Corporation, 3225 Gallows Road, Fairfax, VA 22037-

0001. 

Nonconventional Gas Sources-Continued 

Historical Trends and Future Expectations 

for Coalbed Methane .............................................. 524 

Speculative Gas Sources ........................................ 525 

Conclusions ................................................................... 525 

References Cited ........................................................... 526 

ABSTRACT 

This paper summarizes the contribution of the Source 

and Supply Task Group to the recent (December 1992) 

National Petroleum Council (NPC) study entitled "The Potential for Natural Gas in the United States." This task 

group evaluated potential sources of additions to U.S. natural gas reserves with a team of more than 100 participants, representing various trade, academic, government, 

and industry organizations. The group evaluated reserve 

growth, unconventional resources, and undiscovered conventional resources of natural gas over a range of prices 

and to the year 2010. The study concluded that the U.S. 

recoverable resource base consists of nearly 1 ,300 Tcf in 

the lower 48 States alone, of which more than 413 Tcf 

will be in new fields and 203 Tcf will be added from reserve appreciation. In addition, more than 519 Tcf will be 

available as recoverable unconventional resources of gas 

in coalbeds, gas shales, tight sands, and in other categories. Of the total resource, more than 600 Tcf will be recoverable at wellhead prices of $2.50 per million British 

thermal units. The NPC evaluation of the U.S. resource 

base concluded that the domestic natural-gas resource is 

plentiful and that technological advances will ensure that 

the resources will be available to fill any foreseeable demand over the next few qecades. 

507 
508 THE FUTURE OF ENERGY GASES 

INTRODUCTION four water-depth zones. The proved reserves of dry gas for 

the lower 48 States are presented in table I. 

The National Petroleum Council (NPC) has recently 

conducted a study of natural gas on behalf of the Federal 

Secretary of Energy. The study entitled "The Potential for 

Natural Gas in the United States" (National Petroleum 

Council, 1992) spanned a wide range of subjects including 

resources, economics, production, transportation, environmental issues, and consumption. This paper summarizes 

the principal results of those sections of the NPC report 

that were devoted to the source and supply of natural gas 

in the United States. In particular, because the subject of 

this volume is "The Future of Energy Gases," the perspective of the NPC, representing as it does a wide range of 

industry, governmental, and other views, is especially relevant. The specific focus of the source and supply study 

was the resource base of conventional and nonconventional gas that can be made available as additions to United 

States reserves over the period of time from 1990 until the 

year 2010, with most gas priced at no more than $3.50 per 

thousand cubic feet (Mcf), and it covered a wide range of 

topics relevant to future supplies of natural gas for the 

United States. This paper, however, will concentrate on 

two themes: (l) present proved reserves and future supplies of conventional natural gas coming from new discoveries and from growth of reserves in existing fields and (2) 

sources of unconventional supplies of natural gas that are 

considered likely to be brought into production by 2010. 

Because this paper summarizes an NPC report, the 

stratigraphic nomenclature and unit age assignments discussed here may not necessarily conform to current usage 

by the U.S. Geological Survey. 

CONVENTIONAL GAS 

The Conventional Gas Work Group was established 

within the Source and Supply Task Group and charged with 

the assessment of the conventional resource base. The assessment centered on two topics: (1) the undiscovered nonassociated and associated/dissolved gas and (2) the 

expected future growth of proved reserves in existing fields. 

EXISTING PROVED RESERVES 

The NPC relied mainly on the reserves information 

contained i!l the annual reports of the Energy Information 

Administration (EIA). The EIA reports reserves by state; 

however, the Energy and Environmental Analysis Inc. 

(EEA) Hydrocarbon Supply Model (HSM) used for the 

NPC study is designed to economically analyze the resource base in thirteen onshore and five offshore segments. 

The onshore data were disaggregated into four reservoirdepth zones, and the offshore· data were subdivided into 

Table 1. Lower 48 States dry-gas proved reserves as of year end 1990, in billion cubic feet. 

]From National Petroleum Council, 1992] 

Region Total 

Appalachia A 6,718 

MAFLA Onshore• B 3,296 

Midwest c 1,243 

Arkla-E. Texas D 11,658 

So. Louisiana E 8,171 

Texas Gulf Coast G 13,154 

Williston WL 1,485 

Rockies Foreland FR 10,599 

San Juan Basin SJB 15,624 

Overthrust ov 3,790 

Midcontinent JN 31,841 

Permian JS 14,420 

Pacific L 2,993 

Subtotal Onshore 124,992 

Norphlet BO 4,780 

West Florida 

Gulf of Mexico EGO 28,626 

Pacific Offshore LO 1,646 

Atlantic Offshore AO 

Subtotal Offshore 35,052 

Grand Total 160,044 

• MAFLA- Mississippi, Alabama, and Florida. 

RESERVE APPRECIATION 

The estimated ultimate recovery (EUR) of an oil or 

gas field is defined as the sum of cumulative production 

and proved reserves. Data concerning EUR's for U.S. oil 

and gas fields have been published by the American Gas 

Association (AGA) and more recently by the EIA. These 

EUR data which are assigned to fields by the year of field 

discovery, indicate that most field reserves have increased 

through time (see also Root and Attanasi, this volume). 

This growth in EUR is referred to as reserve growth or 

reserve appreciation. Reserve appreciation results from a 

number of causes including additions to reserves by field 

extensions, the identification of new reservoirs within existing fields, infill drilling, increased recovery through improved technology or enhanced recovery techniques, and 

well workovers, recompletions, and longer productive life 

of wells encouraged by higher prices. Reserve growth also 

results from the way reserves are reported by the industry. 

Initial estimates of field sizes are normally conservative to 

avoid overinvestment. As field development proceeds and 
NATIONAL PETROLEUM COUNCIL SOURCE AND SUPPLY STUDY 509 

more information is gathered, field-size estimates are commonly increased to more accurately reflect the true field 

size. Measures of reserve appreciation provide an estimate 

of the reserves that are added through time to known 

fields. The growth in reserves in known fields accounts for 

about two-thirds of annual additions to U.S. proved gas 

reserves. Growth continues to occur even in old fields. For 

example, gas fields discovered before 1968 accounted for 

7.6 trillion cubic feet (Tct) of the 14.4 Tcf total reserve 

additions in 1989. 

The Office of Technology Assessment in a 1985 report 

"U.S. Natural Gas Availability, Gas Supply Through the 

Year 2000" (Office of Technology Assessment, 1985) cited 

five examples of sources of "new gas from old fields:" (1) 

lowering of abandonment pressure (decrease of the pressure threshold at which the decision is made to abandon a 

well), which is typically tied to gas prices and economic 

life of wells and surface equipment, (2) infill drilling, 

which can add new wells to recover gas not in communication with existing wellbores, (3) fracturing and acidizing, 

which can improve flow continuity between gas-bearing 

reservoir rock and the well bore, (4) well workovers, 

which improve the mechanical condition of the well or 

treat the reservoir to improve flow, (5) extension of drilling 

into previously subeconomic portions of the field, which 

again is tied to prices and (or) to improvements in extraction technology. 

Although each of these activities have added new reserves in old fields, most reserve appreciation comes from 

infill drilling, drilling extensions, and activities in existing 

wells such as recompletions and restimulations. The ultimate recovery of gas from fully delineated natural-gas accumulations tends to be much greater than initial estimates 

because technology developments during the last three decades have significantly improved the industry's ability to 

discover, develop, and produce hydrocarbons. 

0::: 8 0 

1-

() 

<( 

lL 6 :r: 

~ 0 

0::: 4 

(!) 

w 

> i= 

<( 2 ...J 

=> 

~ 

=> 0 () 

0 5 10 

NPC ANALYTICAL APPROACH 

Previously published estimates of reserve growth have 

ranged from largely subjective estimates to rigorous forecasts based on analyses of historical statistics. The NPC 

concluded that its study should have a sound technical 

basis. The analysis, therefore, relied on what has actually 

occurred in the industry regarding reserves data. Data for 

estimating ultimate recoveries were available from two 

sources: (I) the Oil and Gas Integrated Field File (OGIFF), 

maintained by EIA, and (2) the American Petroleum Institute (API)/American Gas Association (AGA) publication 

"Reserves of Crude Oil, Natural Gas Liquids, and Natural 

Gas in the United States and Canada." The OGIFF file 

contains estimates of crude oil and natural-gas proved reserves, annual production, cumulative production, and ultimate recovery for most U.S. oi I and gas fields. The file 

includes yearly estimates for the 13 year period from 1977 

to 1989 for each of about 46,000 oil and (or) gas fields. 

Both the EIA and AGA data include estimates for 

both nonassociated gas (gas not associated with oil) and 

associated/dissolved gas (gas dissolved in oil) or free gas 

in an oil reservoir. However, a careful review of the AGA 

data on associated/dissolved gas led to the conclusion that 

the EIA data set should be used for this type of gas. Although the two data sets were developed using different 

approaches and contained somewhat different results for 

overlapping years, the data were merged to provide a 

22-year history of reserve growth. The resulting data set 

demonstrates that the initial proved reserves reported by 

companies grow significantly through time; booked reserves from fields discovered more than 50 years ago are 

still increasing, although at a generally low rate of growth. 

The growth of reserves for fields discovered between 1966 

and 1988 for the NPC nonassociated gas data base are 

shown in figure I. 

15 20 25 

Figure 1. Growth factors for nonassociated gas. Numbers at end of lines marked with symbols 

indicate year of discovery. From National Petroleum Council ( 1992). 
510 THE FUTURE OF ENERGY GASES 

The NPC approach considers reserve growth as a 

function of both time and drilling activity. The 22-year 

history of available data covers a wide range of drilling 

activity, including the intense drilling activity of the early 

1980's "boom" to the late 1980's "bust." Thus, it was decided that reserve growth should be considered in terms of 

both immaturity and level of drilling activity. The NPC 

study considered well completions to be the most reliable 

indicator of industry activity. 

Growth curves based on both time and drilling activity 

assume that reserve growth will continue and that growth 

will vary through time as a function of industry activity. 

The EIA data base includes information from the great 

majority of production companies. 

Because the growth curve is tied to the initial booking 

of reserves, a concern remains about the nature of industry 

reserve booking practices over the 22-year time period. 

There have been various pressures that affect reserve estimates during the period of the data. For example, the gassales-contracts accounting standards and Securities and 

Exchange Commission regulations. Estimates of reserves 

tend to be self-correcting, however, as estimates that are 

too high must eventually be removed as a negative revision. The NPC concluded that industry reserve booking 

practices have been reasonably stable over an extended period and especially since the implementation of the Reserve Recognition Accounting Standards by the Securities 

and Exchange Commission of 1976. 

Well-completion data for the NPC study were obtained 

from DeGolyer and McNaughton's 'Twentieth Century Pea: 

0 

1-

0 

<( 

LL 

I 

~ 0 

a: 

(.!) 

w 

> 

i= 

<( 

_J 

::J 

:::2: 

::J 

0 

10 

8 

6 

4 

2 

0 

0 

/ - z~ 

t7 

r ----11------

25 

troleum Statistics" for 1920 through 1969. Well completions in the period 1969 through 1989 came from the 

source file for "Monthly Energy Review" of the EIA, Office of Energy Markets and End Use. 

An explicit functional form for the NPC study was selected that depended on both time and cumulative wells 

drilled. The addition of cumulative drilling permitted the 

development of a reserve appreciation function with a 

clearly defined limiting asymptotic value that naturally explains the increases in the rate of reserve appreciation per 

year in the period from 1977 to 1989 as compared to the 

period from 1967 to 1976. Figure 2 shows examples of the 

NPC nonassociated reserve appreciation model for 1922 

discoveries under different drilling assumptions. Although 

the analytical work used a data series based on wet gas 

data, the final results are believed to represent dry gas volumes as well. The lower growth factor curve assumes that 

2,000 gas wells are drilled every year, which approximates 

the actual early life of a 1922 discovery. The heavy middle 

curve represents the model prediction using historical 

drilling patterns; the abrupt change in slope after year 50 

reflects the rapid increase in gas well drilling in the mid1970's. The top curve represents the shape of the growth 

curve for 1922 fields if 20,000 gas wells per year had been 

drilled. The growth factors in this curve increase at a higher rate, but eventually approach the same asymptote (6.6). 

An additional feature of the work to develop an equation characterizing the appreciation of proved reserves was 

that nonassociated gas and associated/dissolved gas were 

analyzed separately. The functional forms of the equations 

50 

--

LEGEND 

-20,000 Gas Well 

Completions per Year 

----Historical and Projected 

Completions 

, .. ,_ .... ~.," .. ~ .. ,, 2,000 Gas Well 

Completions per Year 

75 100 

YEARS SINCE DISCOVERY 

Figure 2. Growth curve for 1922 discoveries of nonassociated gas. From National Petroleum 

Council (1992). 
NATIONAL PETROLEUM COUNCIL SOURCE AND SUPPLY STUDY 511 

were identical, but the associated/dissolved equation relied 

upon the number of oil wells drilled since discovery rather 

than on the number of gas wells drilled. 

RESULTS OF NPC ANALYSIS 

The results of the NPC analysis can be viewed by 

comparing the predicted growth curve for an example discovery year to some of the actual growth patterns of fields 

discovered between 1966 and 1988 (fig. 3). The growth 

factor was calculated by dividing the ultimate recovery in 

any year by the ultimate recovery estimate in the year of 

discovery. The actual growth factor is already over six for 

some discovery years (1972 and 1976) and under three for 

other discovery years ( 1967 and 1970). The heavy black 

line is an example growth curve calculated from the NPC 

reserve-appreciation equation. The curves calculated directly from the data show a fairly wide spread around the 

example curve. However, the example growth curve does 

reflect a rough average behavior of the growth curves directly calculated from the NPC data base. 

Using the same NPC data base, reserve-appreciation 

methods that use functional forms (Hubbert and EIA) that 

depend on field age and those that utilize other statistical 

methods not dependent on a specific functional form (Arrington, Marsh, and U.S. Geological Survey) would probably yield curves similar to the example shown in figure 3. 

One of the key observations to be made from figure 3 is not 

the spread of the actual curves around the example curve, 

but rather the rate of growth of the curves compared to the 

8 

0: 

0 

f0 

<( 

LL 6 

I 

f-

~ 

0 

0: 4 

(.') 

w 

> 

i= 

<( 2 _J 

::J 

:2: 

::J 

0 

0 

0 5 10 

predicted curve. The ultimate growth factor is important for 

new discoveries, but the rate of growth for existing proved 

reserves is the more important part of the prediction, because 

it is the rate that determines the size of the reserve appreciation resource. Figure 3 shows that after about five years after 

discovery, the predicted rates of growth are quite similar. 

Table 2 shows the predicted reserve appreciation for 

the years 2010 and 2030 with various drilling assumptions. In addition, the reserve appreciation of nonassociated gas after 4,000,000 cumulative gas wells are drilled is 

estimated to be roughly 216 Tcf. This is almost the limit 

of reserve appreciation in the model. Similarly after 

14,000,000 cumulative oil wells have been drilled the 

associated/dissolved gas reserve appreciation will reach 

20 Tcf for a total reserve appreciation of 236 Tcf. Most of 

this is proved by the year 2030. 

The reserve-appreciation resource was allocated to the 

HSM regions and depths in proportion to the distribution 

of ultimate recovery by discovery year in each area. 

Table 3 shows the results of that allocation and represents 

the actual data utilized as input to the HSM for the NPC 

gas study. 

Table 4 provides a further breakdown of the total gas 

reserve appreciation by nonassociated gas in high-permeability reservoirs, tight nonassociated gas in old plays, and 

associated/dissolved gas. This table includes tight gas in 

old plays in the total reserve-appreciation resource because 

such growth was in the historical data base. For the purposes of total resource base reporting in the NPC study, 

this volume of resource was also reported as nonconventional tight gas. 

15 20 25 

YEARS SINCE DISCOVERY 

Figure 3. Growth factors for nonassociated gas. Numbers at end of lines marked with symbols 

indicate year of discovery. Example curve calculated from the National Petroleum Council reserve 

appreciation equation. From National Petroleum Council (1992). 
512 THE FUTURE OF ENERGY GASES 

Table 2. Predicted reserve appreciation for the lower 48 States. 

[From National Petroleum Council, 1992] 

Non-Associated Gas (using 

combined EIAIAGA data) 

Ultimate Recovery at Year-end 1990, BCF 694,334 

Year 2010 with 314,500 additional Gas Wells 

Year 2030 with 771,720 additional Gas Wells 

After 4,000,000 Cumulative Gas Wells 

Change From 1990 

Ultimate Recovery 

(Billion Cubic Feet) Percentage 

135,664 

201,674 

216,090 

19.5 

29.0 

31.1 

Change From 1990 

Ultimate Recovery 

Associated/Dissolved Gas (using EIA data) (Billion Cubic Feet) Percentage 

Ultimate Recovery at Year-end 1990, BCF 223,588 

Year 2010 with 421,422 additional Oil Wells 

Year 2030 with 1,005,862 additional Oil Wells 

After 14,000,000 Cumulative Oil Wells 

Total Non-Associated and 

Associated/Dissolved Gas 

Ultimate Recovery at Year-end 1990, BCF 

Year 2010 with additional Gas and Oil Wells 

as above 

Year 2030 with additional Gas and Oil Wells 

as above 

After 4,000,000 Cumulative Gas Wells and 

14,000,000 Cumulative Oil Wells 

917,922 

14,450 

18,810 

20,224 

6.5 

8.4 

9.0 

Change From 1990 

Ultimate Recovery 

(Billion Cubic Feet) Percentage 

150,114 16.4 

220,314 24.0 

236,314 25.7 

Table 3. Total undiscovered conventional gas resources (current technology), in million barrels of oil 

equivalent. 

[Includes tight gas in old plays. From National Petroleum Council, 1992] 

Region 0-5,000' 5-10,000' 10-15,000' >15,000' Total 

Appalachia A 1,267 2,004 959 402 4,632 

MAFLA Onshore B 344 168 2,334 1,075 3,921 

Midwest c 11110 1,502 551 0 3,163 

Arkla-E. Texas D 1,513 2,795 1,413 279 6,000 

So. Louisiana E 0 190 699 2,594 3,483 

Texas Gulf Coast G 639 3,840 4,168 1,674 10,321 

Williston WL 395 906 338 0 1,639 

Rockies Foreland FR 1,448 5,658 2,910 3,230 13,246 

San Juan Basin SJB 362 680 0 0 1,042 

Overthrust OV 105 1,330 1,129 960 3,524 

Midcontinent JN 2,011 4,026 2,835 4,319 13,191 

Permian JS 1,539 2,447 1,423 2,704 8,113 

Pacific L 743 2,731 1,722 1,237 6,433 

Subtotal Onshore 11,476 28,277 20,481 18,474 78,708 

Subregion 

1 2 3 4 Total 

Norphlet BO 2,106 0 0 0 2,106 

West Florida 540 

Gulf of Mexico EGO 6,070 5,545 4,991 11,556 28,162 

Pacific Offshore LO 2,630 9,563 12,193 

Atlantic Offshore AO 3,552 

Subtotal Offshore 46,553 

Grand Total 125,261 
NATIONAL PETROLEUM COUNCIL SOURCE AND SUPPLY STUDY 513 

Table 4. Total undiscovered gas resources (current technology), in billion cubic feet. 

[Includes tight gas in old plays. From National Petroleum Council, !992] 

Region 0-5,000' 5-10,000' 10-15,000' >15,000' Total 

Appalachia A 6,216 10,288 4,926 2,159 23,589 

MAFLA Onshore B 854 357 5,468 4,229 10,908 

Midwest c 2,157 3,900 2,423 0 8,480 

Arkla-E. Texas ·o 3,843 7,198 6,165 1,317 18,523 

So. Louisiana E 0 557 2,319 12,319 15,195 

Texas Gulf Coast G 2,503 16,312 19,050 8,176 46,041 

Williston WL 946 1,199 447 0 2,592 

Rockies Foreland FR 3,577 16,449 12,221 16,351 48,598 

San Juan Basin SJB 1,170 1,981 0 0 3,151 

Overthrust ov 300 3,791 3,748 4,370 12,209 

Midcontinent JN 4,819 12,416 11,659 21,885 50,779 

Permian JS 3,586 6,202 4,598 12,328 26,714 

Pacific L 1,446 6,727 5,099 4,258 17,530 

Subtotal Onshore 31,417 87,377 78,123 87,392 284,309 

Subregion 

1 2 3 4 Total 

Norphlet 80 11,388 11,388 

West Florida 2,590 

Gulf of Mexico EGO 25,311 23,122 15,722 36,402 100,557 

Pacific Offshore LO 2,807 10,204 13,011 

Atlantic Offshore AO 17,013 

Subtotal Offshore 144,559 

Grand Total 428,868 

Note: Values are recoverable hydrocarbons as of 12-31-90; Subregions for 80, EGO are <40m, 40-200m, 200-

1 OOOm, and > 1 OOOm water depth: LO is 0-200m and 200-2000m; AO and West Florida have no defined water depth. 

UNDISCOVERED CONVENTIONAL RESOURCES 

The undiscovered resource was assessed by a consensus 

approach. A core group of industry, government, and association representatives, after becoming familiar with the HSM, 

discussed various aspects of the undiscovered resource basefield size distributions and regional variations in geologic 

factors affecting the resource base. Each participant brought 

an estimate of the resource base to the discussion based on 

various methods employed in his or her organization. However, because some of these methods and assessments were 

proprietary, open discussion of the details and results of each 

was not possible. Instead, the assembled group discussed 

ranges of assessments and, through detailed and lengthy 

discussions, arrived at a consensus concerning the size of the 

undiscovered resource in each region of the HSM. The results of the small-group assessment were used as a basis for 

review and revision of the resource base in the HSM. The 

results were presented to the entire Conventional Gas Work 

Group for review, feedback, and comments. The feedback 

and comments were incorporated, and a final consensus was 

obtained for the undiscovered resource. The results of these 

consensus assessments are listed in tables 3 and 4. The 

results assumed current technology and were reported by 

region, for each of four depth ranges, and for undiscovered 

associated/dissolved gas resource (table 4) and undiscovered 

conventional nonassociated gas resource (table 3). 

Although most estimates of undiscovered commodities 

begin with fairly certain data and well-known quantities, 

they proceed toward subjects of considerable uncertainty, 

with little data and less well-known information. It is useful to compare the results of the NPC study with those of 

other recent assessments of the conventional natural gas 

resource. In particular, table 5 presents a comparison of 

Table 5. Comparison of lower 48 States undiscovered conventional-gas resource estimates, in trillion cubic feet. 

(From National Petroleum Council, 1992] 

Onshore Offshore 

DOE- 1988' 219 134 

EIA -1990 t 197 130 

USGS/MMS - 1989 :t 189 135 

PGC-1990 § 352 139 

GRI-1992 ~ 

NPC- 1992 # 254 159 

• Current technology only. 

t Access to federal lands and Advanced Technology scenario. 

:t Excludes resource in fields less than 6 billion cubic feet. 

§ Summation of mean values. Includes some tight gas in old plays. 

~Excludes tight gas in old plays. Advanced Technology case. 

#Advanced Technology case. 

Total 

353 

327 

324 

491 

394 

413 
514 THE FUTURE OF ENERGY GASES 

recent assessments by the Department of Energy, Energy 

Information Administration, U.S. Geological Survey, Minerals Management Service, Gas Research Institute, and 

Potential Gas Committee. It is important to be aware of 

the context in which assessment totals are presented. 

DEPARTMENT OF ENERGY 1988 STUDY 

The Department of Energy (DOE) released a study in 

1988 of natural-gas resources, entitled "An Assessment of 

the Natural Gas Resource Base of the United States." The 

study was conducted by a review panel of natural-gas analysts who estimated technically recoverable resources (including proved reserves) of I ,059 Tcf in the lower 48 States, 

using then-current technology. The onshore undiscovered conventional resources were estimated to be 219 Tcf 

and offshore resources were estimated to be 134 Tcf. 

These results were somewhat smaller (5 percent onshore, 

and 8 percent offshore) than the NPC current-technology 

estimate. 

The DOE study was intended to explore the underlying 

assumptions involved in the resource estimates available to 

the review panel, to normalize the application of assumptions to all resource estimates, and to form a consensus on 

resources estimated for various categories of gas including 

undiscovered, inferred reserves, gas in low-permeability 

reservoirs, coalbed gas, and shale gas. Economic assumptions 

were studied in order to evaluate the recovery of resources at 

wellhead prices of less than $3.00/Mcf and recovery of 

resources at wellhead prices of $3.00-$5.00/Mcf (1987 

dollars). 

The NPC and DOE methods of assessing conventional 

undiscovered resources were similar in that resource assessments from a variety of sources were considered and that a 

consensus process was employed to arrive at final estimates. 

ENERGY INFORMATION ADMI,NISTRATION 1990 STUDY 

As part of an effort to support the formulation of a 

National energy strategy, the EIA conducted a literature 

search and review of information pertinent to the availability of natural-gas resources in the United States. The results of that review were published in a document entitled 

"The Domestic Oil and Gas Recoverable Resource BaseSupporting Analysis for the National Energy Strategy." 

The EIA document emphasized a future with unrestricted 

access to Federal lands and enhanced development of exploration technology. 

The EIA estimated the undiscovered onshore conventional resources in the lower 48 States at 197 Tcf (about 

22 percent lower than NPC). EIA estimates of offshore 

undiscovered conventional resources are lower than those 

of the NPC. EIA estimates included resources in minimum 

field sizes greater than 30,000 barrels of oil equivalent 

(boe) onshore and greater than 100,000 (boe) offshore. 

U.S. GEOLOGICAL SURVEY AND MINERALS MANAGEMENT 

SERVICE 1989 STUDY 

The U.S. Geological Survey (USGS) and the Minerals 

Management Service (MMS) conducted a joint study for 

the Department of the Interior (DOl) in which they estimated undiscovered conventional gas resources in the United 

States. The USGS was responsible for the onshore and state 

offshore areas, while the MMS maintained responsibility 

for the Federal offshore. The results were published in a 

joint document entitled "Estimates of Undiscovered Conventional Oil and Gas Resources in the United States-A 

Part of the Nation's Energy Endowment." 

The DOl study focused almost exclusively upon undiscovered, conventionally recoverable oil and gas. Furthermore, estimates were subjected to various economic 

screening criteria. The USGS MMS numbers listed in 

table 5 are those not reduced by economic filters. The DOl 

assessment used a play analysis technique, which made estimates of the sizes and numbers of undiscovered fields in 

given areas or used a summation of individual prospect 

evaluations. The methodology used in the USGS MMS 

study is similar to that employed by many large exploration and production companies such as those represented 

in the NPC study. However, the risks and probabilities 

may have been evaluated differently by the DOl and by 

various individual companies. 

, Compared to the NPC study, the USGS MMS assessment for the lower 48 States was about 22 percent lower. 

However, much of this difference can be accounted for by 

the fact that the DOl assessment only evaluated onshore 

resources in fields greater than 30,000 boe and offshore 

fields greater than 100,000 boe. 

POTENTIAL GAS COMMITTEE 1990 STUDY 

The Potential Gas Committee (PGC), part of the Potential Gas Agency sponsored by the American Gas Association at the Colorado School of Mines, utilizes volunteer 

members from the oil and gas industry. The industry volunteers provide resource estimates of natural gas based on 

their expert judgments. The PGC develops resource estimates for each region of the U.S. and presents the results 

in terms of minimum, most likely, and maximum estimates 

for gas resources categorized as probable, possible, or 

speculative. The NPC considered only those resources that 

the PGC would classify as possible and speculative in the 

consensus process. The PGC's most recent publication 

"Potential Supply of Natural Gas in the United States," 

reported both values summed arithmetically and statistical 

mean values for the total lower 48 States data. The mean 

values are referenced in this report. 

PGC estimates of undiscovered conventional resources 

for the lower 48 States exceeded those of the NPC by 

about 19 percent. This is due in part to the fact that the 
NATIONAL PETROLEUM COUNCIL SOURCE AND SUPPLY STUDY 515 

PGC includes some tight gas resources and shale gas 

whereas these categories are largely considered by the 

NPC to belong in the nonconventional category. 

GAS RESEARCH INSTITUTE 1991 STUDY 

The Gas Research Institute (GRI) makes yearly estimates of natural gas supply and demand by means of the 

HSM, a version of which was used for the NPC study. 

The results of the GRI model run are presented in the 

GRI "Baseline Projection." The GRI Baseline and other 

GRI publications require inputs of estimates of resources 

available for discovery and future development. The GRI 

projections include assumptions of technological advances that affect the amount of resource available and its 

cost. 

The 1991 GRI publication "The Long-Term Trends in 

U.S. Gas Supply and Prices-1992 Edition of the GRI 

Baseline Projection of U.S. Energy Supply and Demand to 

201 0" outlines assumptions regarding the resource base 

used by GRI in the HSM. The undiscovered resource base 

for the lower 48 States is estimated by the GRI to be 

about 394 Tcf, an estimate which is about 4 percent lower 

than the NPC estimate for the advanced technology case. 

A minimum field size of 4,000 boe was included in both 

the GRI study and in the NPC study. 

THE EFFECT OF TECHNOLOGICAL ADVANCES 

The basic NPC assessment of undiscovered, conventional accumulations of natural gas was based on the assumption of discoveries and developments that used 

technology existing in 1992. However, because the focus 

of the study was the estimation of recoverable resources 

of natural gas, the size of the resource will be affected by 

future changes in technology that influence the recovery 

ofnatural gas. The history of the oil and gas industry has 

been one of continuous technological advancement, and 

future breakthroughs in oil and gas technology are inevitable, even though forecasting the exact nature and timing of such advancements is difficult (see Roberts, this 

volume). 

The conventional resources of natural gas have been 

extensively exploited, and the technological changes that 

have affected recovery of natural gas have been many, 

varied, and substantial. At present, the total recovery of 

conventional gas is estimated to have been in the range of 

70 to 80 percent of the original gas in place (OGIP). Consequently, the NPC believes it likely that future increases 

in recovery factors will probably be small. Therefore, the 

NPC study used an assumption of technological advances 

yielding 0.5 percent per year increase in recovery. This increasing recovery factor suggests that recovery will grow 

by about 10 percent from 1990 to the year 2010. Thus a 

1990 recovery factor of 75 percent would increase to 82.5" 

percent by 20 I 0, owing to technological advancement. 

The gas-in-place figure would not change as a result of 

technological breakthroughs. 

Technological advances were also considered for nonconventional gas resources. It was concluded that the effect 

of technology on these resources would be much greater. 

In particular, for nonconventional resources such as tight 

gas, recovery factors are expected to grow by 2 percent per 

year, or 50 percent by the year 20 I 0. Such increases in 

recovery factors in the nonconventional resources seem 

reasonable in light of the low recovery factors that are currently affecting nonconventional resources in co·ntrast to 

conventional resources. Tables 6-9 express the natural-gas 

resource base under advanced technology. 

NONCONVENTIONAL GAS SOURCES 

A nonconventional gas subgroup was charged with 

establishing the recoverable gas resource base from nonconventional sources. For convenience, shale gas, coalbed 

methane, and tight gas were classified together as "nonconventional." The NPC views this as something of a misnomer, 

as each of these resource categories is currently productive. 

However, the term is used because these resources are each 

in an early stage of technological development. 

Although the potential tight-gas resource base is quite 

large, the NPC evaluated in detail only that portion for 

which sufficient data existed to adequately characterize the 

potential. Therefore, only those portions of the tight-gas 

resource that were currently in production or which were 

expected to be significantly developed during the period 

examined by the study (1990-2010) were included in the 

assessment. 

Speculative resources such as gas hydrates, geopressured brines, and deep gas are estimated to be as large as 

12,000 Tcf. The cost of recovering such resources, however, is large and uncertain. Consequently, no recoverable resources from these gas sources were included in the NPC 

reference case. For further discussion of these potential resources, consult appropriate chapters in this volume. 

As of 1990, production of gas from nonconventional 

sources accounted for about 12 percent of the gas production from the lower 48 States. Modelling used in the NPC 

study suggests that the proportion of nonconventional gas 

will increase to 22-27 percent of total production from the 

lower 48 States by 2010. The nonconventional gas basins 

of the United States considered in the NPC report are 

shown in figure 4. NPC estimates of recoverable nonconventional resources and production rates are given in tables 10 and II. 
516 THE FUTURE OF ENERGY GASES 

Table 6. Total undiscovered gas resources (advanced technology), in billion cubic feet. 

!Includes tight gas in old plays. From National Petroleum Council, 1992] 

Region 0-5,000' 5-10,000' 10-15,000' >15,000' Total 

Appalachia A 7,762 11,747 5,419 2,375 27,302 

MAFLA Onshore B 939 393 6,015 4,652 11 ,999 

Midwest c 2,373 4,290 2,665 0 9,328 

Arkla-E. Texas D 4,456 8,656 7,394 1,554 22,060 

So. Louisiana E 0 613 2,551 13,551 16,715 

Texas Gulf Coast G 2,766 20,119 21,362 9,255 53,502 

Williston WL 1 '195 1,319 492 0 3,006 

Rockies Foreland FA 4,638 21 ,531 16,271 21,583 64,023 

San Juan Basin SJB 1,496 2,492 0 0 3,988 

Overthrust ov 330 4,170 4,123 4,807 13,430 

Midcontinent JN 5,417 14,276 13,260 26,262 59,215 

Permian JS 4,197 7,269 5,291 13,561 30,318 

Pacific L 1,591 7,400 5,609 4,684 19,283 

Subtotal Onshore 37,159 104,274 90,452 102,284 334,168 

Subregion 

2 3 4 Total 

Norphlet BO 12,527 12,527 

West Florida 2,849 

Gulf of Mexico EGO 27,842 25,434. 17,294 40,042 110,613 

Pacific Offshore LO 3,088 11,224 14,312 

Atlantic Offshore AO 18,714 

Subtotal Offshore 159,015 

Grand Total 493,183 

Note: Values are recoverable hydrocarbons as of 12-31-90; Subregions for 80, EGO are <40m, 40-200m, 200-

1 ooom, and > 1 ooom water depth; LO is 0-200m and 200-2000m; AO and West Florida have no defined water depth. 

Table 7. Undiscovered associated- and dissolved-gas resources (advanced technology). in billion cubic 

feet. 

[From National Petroleum Council, 1992] 

Region 0-5,000' 5-10,000' 1 0-15,000' >15,000' Total 

Appalachia A 108 86 41 0 234 

MAFLA Onshore B 90 54 776 40 959 

Midwest c 1,260 1,278 40 0 2,577 

Arkla-E. Texas D 1,088 2,119 187 0 3,394 

So. Louisiana E 0 117 362 0 479 

Texas Gulf Coast G 350 1,437 799 0 2,585 

Williston WL 191 574 215 0 980 

Rockies Foreland FR 710 2,342 482 0 3,533 

San Juan Basin SJB 330 744 0 0 1,074 

Overthrust ov 53 673 96 0 822 

Midcontinent JN 2,118 3,029 854 0 6,001 

Permian JS 1,243 1,913 776 0 3,931 

Pacific L 311 1 '125 664 422 2,523 

Subtotal Onshore 7,851 15,490 5,289 462 29,092 

Subregion 

1 2 3 4 Total 

Norphlet 80 0 0 

West Florida 87 

Gulf of Mexico EGO 2,339 2,136 3,642 8,434 16,551 

Pacific Offshore LO 1,618 5,882 7,500 

Atlantic Offshore AO 568 

Subtotal Offshore 24,705 

Grand Total 53,797 

Note: Values are recoverable hydrocarbons as of 12-31-90; Subregions for 80, EGO are <40m, 40-200m, 200-

1 ooom, and > 1 ooom water depth; LOis 0-200m and 200-2000m; AO and West Florida have no defined water depth. 
NATIONAL PETROLEUM COUNCIL SOURCE AND SUPPLY STUDY 517 

Table 8. Undiscovered conventional nonassociated-gas resources (advanced technology), in billion cubic 

feet. 

[From National Petroleum Council, 1992] 

Region 0-5,000' 5-10,000' 10-15,000' >15,000' Total 

Appalachia A 4,188 10,049 5,378 2,375 21,989 

MAFLA Onshore B 849 339 5,239 4,612 11,040 

Midwest c 1 '113 3,012 2,626 0 6,751 

Ali<la-E. Texas 0 2,511 3,770 4,909 1 '159 12,350 

So. Louisiana E 0 496 2,189 13,551 16,236 

Texas Gulf Coast G 2,369 10,523 19,037 8,274 40,203 

Williston WL 425 745 277 0 1,447 

Rockies Foreland FR 1,290 6,301 5,184 8,094 20,869 

San Juan Basin SJB 383 574 0 0 957 

Overthrust ov 277 3,497 4,027 4,807 12,608 

Midcontinent JN 2,866 8,928 10,775 18,055 40,623 

Permian JS 2,006 3,682 3,640 13,561 . 22,889 

Pacific L 1,279 6,274 4,945 4,261 16,760 

Subtotal Onshore 19,557 58,188 68,225 78,750 224,720 

Subregion 

1 2 3 4 Total 

Norphlet BO 12,527 12,527 

West Florida 2,762 

Gulf of Mexico EGO 25,504 23,298 13,652 31,609 94,062 

Pacific Offshore LO 1,470 5,343 6,812 

Atlantic Offshore AO . 18,147 

Subtotal Offshore 134,310 

Grand Total 359,030 

Note: Values are recoverable hydrocarbons as of 12-31-90; Subregions for BO, EGO are <40m, 40-200m, 200-

1 OOOm, and > 1 OOOm water depth; LO is 0-200m and 200-2000m; AO and West Florida have no defined water depth. 

Table 9. Undiscovered tight-gas resources in old plays (advanced technology), in billion cubic feet. 

[From National Petroleum Council, 1992] 

Region 0-5,000' 5-10,000' 1 0-15,000' >15,000' Total 

Appalachia A 3,467 1,613 0 0 5,079 

MAFLA Onshore B 0 0 0 0 0 

Midwest c 0 0 0 0 0 

Ali<la-E. Texas 0 857 2,768 2,298 395 6,317 

So. Louisiana E 0 0 0 0 0 

Texas Gulf Coast G 47 8,160 1,527 981 10,715 

Williston WL 579 0 0 0 579 

Rockies Foreland FR 2,639 12,888 10,605 13,490 39,621 

San Juan Basin SJB 783 1 '175 0 0 1,958 

Overthrust ov 0 0 0 0 0 

Midcontinent JN 434 2,319 1,632 8,207 12,591 

Permian JS 948 1,674 876 0 3,498 

Pacific L 0 0 0 0 0 

Subtotal Onshore 9,752 30,596 16,938 23,072 80,357 

Subregion 

1 2 3 4 Total 

Norphlet BO 0 0 

West Florida 0 

Gulf of Mexico EGO 0 0 0 0 0 

Pacific Offshore LO 0 0 0 

Atlantic Offshore AO 0 

Subtotal Offshore 0 

Grand Total 80,357 

Note: Values are recoverable hydrocarbons as of 12-31-90; Subregions for BO, EGO are <40m, 40-200m, 200-

1 OOOm, and > 1 OOOm water depth; LOis 0-200m and 200-2000m; AO and West Florida have no defined water depth. 
518 THE FUTURE OF ENERGY GASES 

Figure 4. Location of principal nonconventional gas basins in the United States. For region abbreviations see table l. From National Petroleum Council ( 1992). 

Table 10. Recoverable nonconventional gas resources, in trillion 

cubic feet. 

!From National Petroleum Council. 1992] 

Current Advanced 

Technology Technology 

Category of Gas 

Tight Gas 232 349 

Devonian/Antrim Shale 37 57 

Coalbed Methane 62 98 

Total Nonconventional 332 504 

Total Gas Resources, 

including Proved Reserves 1,065 1,295 

Table 11. Nonconventional gas production reference cases l and 2. 

I Reference case 2 shown in parentheses. From National Petroleum Council, 1992] 

1990 2000 2010 

Category of Gas 

Tight Gas 1.7 2.0 (1.6) 3.7 (2.6) 

Devonian/Antrim Shale 0.2 0.5 (0.4) 0.5 (0.4) 

Coalbed Methane 0.2 1.1 (1.0) 1.3 (0.9) 

Total 2.1 3.6 (3.0) 5.5 (3.9) 

TIGHT GAS 

Tight gas occurs in a wide variety of reservoir types 

and in almost every sedimentary basin in the United 

States. In most wells, gas flow rates are not commercial 

without artificial stimulation. The USGS and others have 

characterized tight-gas reservoirs by reservoir genesis and 

geologic characteristics (see Law and Spencer, this volume). In the Rocky Mountains, where a majority of the 

tight-gas reserves is thought to exist, the tight-gas formations are typically of low permeability, low porosity, and 

limited reservoir continuity. Tight-gas reservoirs are commonly characterized by small grain size, intergranular cementation, restricted pore throats, and complex reservoir 

architecture. Each of these features requires sophisticated 

reservoir evaluation and extraction techniques to profitably 

produce gas. 

The tight-gas resource base includes proved reserves, 

reserve growth potential in existing fields, and new fields 

and reservoirs. The sum of reserve growth potential and 

new-field potential represents the total quantity of undeveloped resource to be assessed and characterized. The 

NPC has not divided proved reserves into conventional 

and nonconventional categories. 

New-field resources include existing (producing) plays 

and resources in new or undeveloped plays. Because gas 

quantities in existing plays are better understood and were 

evaluated separately in the HSM, they were included in 
NATIONAL PETROLEUM COUNCIL SOURCE AND SUPPLY STUDY 519 

·historical "finding rate" equations. For simplicity, reserve 

growth is included with new-field resources in existing 

plays." Thus, the two categories reported were (I) reserve 

growth and new fields in existing plays and (2) new fields 

in new plays. 

Estimates of the resource base and its recovery potential were based on an extensive, confidential survey of current operators and detailed statistical analysis of historical 

production data. The NPC adopted the Federal Energy 

Regulatory Commission (FERC) legal definition of a tight 

formation--average in-place permeability of 0.1 millidarcy or less. For existing plays, the FERC tight formation 

designations were used to allocate resource between conventional and tight gas. For new plays the NPC used the 

confidential survey of operators and the FERC designations to select 47 units of analysis. These analytic units 

generally represented a formation-depth interval combination within a basin recognized as having significant tightgas potential. 

The NPC based its estimates of resource base, well 

recoveries, and costs on a confidential survey of operators in 

known tight-gas fonnations. Respondents included five integrated companies, five independents, and two consultants. 

The survey included at least one operator from nine of the 

most significant tight-gas producing basins (Appalachian, 

East Texas/North Louisiana, Texas Gulf Coast, West Texas, 

San Juan, Denver, Piceance, Uinta, and Green River). Survey data were evaluated and transformed into consistent 

distributions of well recoveries and costs to be used in HSM 

runs. Survey respondents provided detailed estimates of formations currently under development and their best judgment on remaining resources in their respective areas of 

expertise. For those areas not covered by the survey, the 

NPC used historical production data and the 1980 NPC 

study results to estimate resource base and per well recoveries. Dwight's Energy Data Corporation's (I 985) well production data were used for producing wells in known tight 

formations to derive a distribution of expected ultimate well 

recoveries. These were used to calibrate survey results or 

adapted as the basis for estimating ultimate recoveries of 

tight-gas wells where no survey data were available. Because some of these formations contained nontight wells, 

well distributions were adjusted to exclude these nontight 

wells. In predominantly tight formations, the top 10 percent 

of wells with high recoveries were removed from the distributions to back out nontight wells. In partially tight formations, the top 20 percent of wells with high recoveries were 

excluded. 

The NPC specified a constant rate of technological 

improvement in recovery efficiency for each area in the 

study to be implemented over the 1990-20 I 0 period. In 

nonconventional reservoirs, however, low recoveries usually result from the inability of the well to contact all of 

the gas in the drilling pattern. Technologies designed to 

increase reservoir contact are thus most effective in the 

lower recovery wells. In higher productivity wells, which 

already contact a greater percentage of total gas, the use of 

these technologies would increase recovery by a smaller 

percentage than in lower recovery wells. The Nonconventional Subgroup thus determined that if these technologies 

were applied, wells recovering less than 0.5 billion cubic 

feet (Bcf) could increase recovery by 70 percent, wells recovering between 0.5 and 1.5 Bcf could increase recovery 

by 60 percent, wells between 1.5 and 2.5 Bcf could increase by 50 percent, and wells recovering over 2.5 Bcf 

could increase by 40 percent. This potentially increases 

the recovery of the average well by about 60 percent as a 

result of advanced technology. The technological improvements could be of several kinds, including more extensive 

fracturing methods and fracturing of multiple zones. Horizontal or slant drilling may also improve recovery in some 

situations. Slim-hole drilling combined with closer well 

spacing may be cost effective in some areas. 

TIGHT-GAS POTENTIAL 

Reserve additions were added from the low-permeability resource areas using the same model as employed 

in the conventional resource fields. Assuming existing 

technology, a total of 84 Tcf of potential tight-gas reserve 

additions were estimated for existing plays and 148 Tcf for 

new plays, for a total potential tight-gas resource recovery 

of about 232 Tcf. The majority of this potential is in the 

foreland area of the Rocky Mountains (53 percent), followed by southern Arkansas/northern Louisiana (Arkla) 

East Texas (12 percent), Midcontinent (9 percent), Texas 

Gulf Coast and Permian Basins (each 8 percent), Appalachian Basin (6 percent), and others (4 percent) (table 12). 

Technology improvements were expected to increase 

recovery per well and decrease costs per Mcf produced. 

The application of advanced technology to tight-gas resources is assumed to increase steadily over the period 

1990-2010, after which all tight-gas wells were assumed 

to use advanced technology. For the same resource base of 

148 Tcf for undeveloped plays, improved technology 

could increase potential reserve additions by about 60 percent to 235 Tcf. Although this is a seemingly large potential, high front-end costs incurred for stimulation make 

tight-gas wells particularly sensitive to wellhead gas prices. At $3.00/Mcf, potential resources for the study areas 

are estimated to be only 30 Tcf with current technology, 

but increase to 103 Tcf with advanced technology. 

Individual formations were characterized to reflect 

current understanding of the resource base in new tightgas formations. Table 13 provides the details of this char~ 

acterization for the areas considered in this study. Total 

recovery, mean recovery per well, and estimated number 

of successful wells are provided for 47 areas for both current and advanced technology cases. Assuming current 
520 THE FUTURE OF ENERGY GASES 

Table 12. Estimated U.S. tight-gas resource base technically recoverable with current technology, in 

trillion cubic feet. 

[Some columns and rows do not sum to totals because of rounding. From National Petroleum Coun~il, 1992J 

Region Old Plays New Plays Total 

New Fields Old Fields 

A (Appalachian) 3.4 0.0 10.5 13.9 

D (Arkla-Tex) 4.2 4.2 19.0 27.4 

G (S. Texas Onshore) 7.1 5.5 5.8 18.4 

WL (Williston) 0.4 0.3 0.0 0.7 

FR (Foreland) 26.4 7.3 89.9 123.6 

SJB (San Juan Basin) 1.3 6.5 0.0 7.8 

JN (Midcontinent) 8.4 2.7 10.8 21.9 

JS (Permian) 2.3 4.0 12.4 18.7 

Total 53.6 30.4 148.4 232.4 

Table 13. Distribution of tight-gas resources in new plays. 

[Data are on a January I, 19R6, basis, which is the starting dale of each model run. Data in table 12 are on a January I, 1991, basis; only Appalachian region shows a 

sigmficanl difference between 1986 and 1991 basis. From National Petroleum Council, 1992] 

Current Technology Advanced Technology 

Mean Re- Mean ReDepth Recovery covery/Well No.Succ. Recovery co very/Well No.Succ. 

Basin and Formation (Feet) (BCF) (MMCF) Wells (BCF) (MMCF) Wells 

Region G -Texas Gulf Coast 

Vicksburg 10,500 240 1,482 162 384 2,371 162 

Cook Mountain 10,400 160 229 699 272 389 699 

Lobo 8,900 2,556 1,390 1,839 4,090 2,224 1,839 

Olmos 4,800 1,677 201 8,343 2,851 342 8,343 

Edwards Lime 11,700 1 '118 1,425 785 1,789 2,280 785 

TotaUAverage 5,751 486 11,827 9,385 794 11,827 

Region FR- Rockies 

Green River- Ft. Union 6,300 2,990 907 3,297 4,784 1,451 3,297 

Green River- Lance 5,600 3,707 822 4,510 5,931 1,315 4,510 

Green River- MV/Lewislntermed. 9,500 30,391 1,500 20,261 45,587 2,250 20,261 

Green River- MV/Lewis -Deep 12,000 12,157 1,000 12,157 19,451 1,600 12,157 

Green River- MV/Lewis -VDeep 15,000 4,052 500 8,104 6,888 850 8,104 

Green River- Frontier 8,800 2,917 1,390 2,099 4,667 2,224 2,099 

Piceance- Wasatch 2,600 327 510 641 523 816 641 

Piceance- MV lntermed. 6,000 8,718 500 17,435 13,948 800 17,435 

Piceance - MV Deep 4,359 8,718 500 17,435 13,948 800 17,435 

Piceance- Mancos/Dakota 6,000 847 303 2,795 1,440 515 2,795 

Wind River- Fr. Union/Lance 7,200 6,581 905 7,272 10,530 1,448 7,272 

Wind River- Mesaverde, etc. 10,300 1,804 2,516 717 2,526 3,522 717 

Uinta- Wasatch 6,600 4,194 1,008 4,161 6,710 1,613 4,161 

Denver- Sussex/Codell 7,000 190 200 950 323 340 950 

Denver- Niobrara 1,500 410 100 4,100 697 170 4,100 

Denver- D and J 8,000 1,928 497 3,879 3,278 845 3,879 

To taU Average 89,930 819 109,812 141,231 1,286 109,812 
NATIONAL PETROLEUM COUNCIL SOURCE AND SUPPLY STUDY 521 

Table 13. Distribution of tight-gas resources in new plays-Continued. 

Current Technology Advanced Technology 

· Mean Re- Mean ReDepth Recovery co very/Well No. Succ. Recovery co very/Well No.Succ. 

Basin and Formation (Feet) (BCF) (MMCF) Wells (BCF) (MMCF) Wells 

Region A- Appalachia 

Clinton Deep (OH) 6,000 1 '115 150 7,433 1,896 255 7,433 

Clinton Shallow (OH) 4,500 2,342 80 29,275 3,981 136 29,275 

Berea(OH) 1,550 780 80 9,750 1,326 136 9,750 

Medina (PA) 5,000 1 '115 153 7,288 1,895 260 7,288 

Bradford (PA) 3,500 2,119 175 12,109 3,602 298 12,109 

Berea - Gordon (WV) 3,600 446 100 4,460 758 170 4,460 

Benson (WV) 4,500 1,673 200 8,365 2,844 340 8,365 

Medina (NY) 2,500 781 100 7,810 1,328 170 7,810 

Berea (KY) 1,500 22 180 122 37 306 122 

Comiferous (KY) 2,500 112 179 626 190 304 626 

Oriskany (PA) 5,000 691 150 4,607 1,175 255 4,607 

TotaVAverage 11,196 122 91,844 19,033 207 91,844 

Region D- East Tx, Arkla 

E. Texas- James Lime 8,100 629 545 1,154 1,006 872 1 '154 

E. Texas- Travis Peak 8,400 793 1,250 634 1,269 2,000 634 

E. Texas- Cotton Valley 10,200 12,604 2,233 5,644 18,906 3,350 5,644 

Arkla- James Lime 8,000 109 349 312" 185 593 312 

Arkla- Travis Peak 7,800 468 1,250 374 749 2,000 374 

Arkla- Cotton Valley 9,200 1,400 735 1,905 2,240 1 '176 1,905 

Arkla- Smackover 11 '1 00 2,979 574 5,190 4,776 918 5,190 

TotaVAverage 18,982 1,248 15,214 29,122 1,914 15,214 

Table 13. Distribution of tight-gas resources in new plays-Continued. 

Current Technolog~ Advanced Technolog~ 

Mean Re- Mean ReDepth Recovery covery/Well No. Succ. Recovery covery/Well No.Succ. 

Basin and Formation (Feet) (BCF) (MMCF) Wells (BCF) (MMCF) Wells 

Region JN- Midcontinent 

Anadarko- Cleveland 7,400 3,792 505 7,509 6,067 808 7,509 

Anadarko- Cherokee/Red Fork 11,000 2,800 510 5,490 4,480 816 5,490 

Anadarko- Granite Wash/Atoka. 11,400 3,433 774 4,435 5,493 1,238 4,435 

Arkoma - Atoka 9,800 817 456 1,792 1,389 775 1,792 

TotaVAverage 10,842 564 19,226 17,429 907 19,226 

Region JS- Permian 

Abo 3,800 1,823 391 4,662 3,099 665 4,662 

Canyon SS 6,100 7,900 560 14,107 12,640 896 14,107 

Strawn, Atoka, etc. 12,000 985 418 2,356 1,675 711 2,356 

Morrow and Mississippian 13,000 1,682 922 1,824 2,691 1,475 1,824 

TotaVAverage 12,390 540 22,950 20,105 876 22,950 

Lower-48 TotaVAverage 149,091 550 270,874 236,305 872 270,874 

Lower-48 TotaVAverage 

Adjusted to 1/1/91 Basis 148,440 235,204 
522 THE FUTURE OF ENERGY GASES 

technology, per well ultimate recoveries for the undeveloped plays range from 80 Mcf to 2.5 Bcf with a mean 

recovery ·of 550 Mcf. Developing the total resource in new 

plays would require over 270,000 wells. 

DEVONIAN SHALES OF THE APPALACHIAN 

BASIN AND THE ANTRIM SHALE 

Gas shales, such as the Devonian shales of the Appalachian Basin or the Antrim Shale of the Michigan Basin, are 

fine-grained, organic-rich sedimentary rocks that are generally gas saturated and have served as both source rock and 

reservoir rock for widespread gas accumulations. The principal deposits of gas-producing shales are concentrated in 

the Appalachian, Michigan, and Illinois Basins in the Eastern United States and in several Western U.S. basins. The 

Appalachian, Michigan, and Illinois Basin deposits have 

been characterized by delineating the black- and gray-shale 

horizons. The black shales have a higher gas content than the 

gray shales and are generally believed to be the predominant 

source beds of the natural gas found in the shales. Although 

the average total thickness of the shale deposits in the Appalachian Basin is many times greater than 'the total thickness 

of shale deposits found in the other two basins, a large part 

of the deposits consist of the poorer quality gray shales. 

Energy and Environmental Analysis (EEA), a consultant to the National Petroleum Council, provided to the NPC 

their Devonian shales and Antrim shale resource estimates. 

These estimates were in turn based on the 1980 NPC study, 

Potential Gas Committee estimates published in 1984, and 

work by consultants. The NPC reviewed the estimates and 

made revisions on the basis of the field experience of some 

of its members. The most significant changes were in the 

Michigan Basin, where estimates of recoverable resources 

were reduced by about 50 percent. A comparison of the 

1980 NPC study, the EEA estimates, and the 1992 NPC 

study is shown in table 14. For modeling purposes estimates were not included for the Illinois Basin and Western 

U.S. basins because they were expected to remain undeveloped during the timeframe of the NPC study. 

DEVONIAN SHALE RESOURCES 

The EEA data for Devonian shales in the Appalachian 

Basin encompasses 30 subdivisions or "cells" (see also 

Milici, this volume). The cells are bounded by degrees of 

latitude and longitude, and each cell encompasses parts of 

two or more counties. Columbia Natural Resources (CNR) 

voluntarily supplied Devonian Shale production data from 

wells in counties of West Virginia, Virginia, Ohio, and 

Kentucky for use by the NPC in verifying the EEA estimates. The CNR data are based on I ,621 wells drilled in 

17 counties (table 15). The wells are divided into old and 

new wells, with old wells being completed before 1971 

and the new ones from 1971 through the present. CNR 

gas-in-place estimates are based on DOE studies completed from 1983 to 1985. Estimated ultimate recoveries from 

each well were based on actual well performance up to the 

present and estimated future recovery. Recoveries range 

from about 12 percent to as much as 50 percent of the 

estimated gas in place for the old wells and from 2.5 percent to as much as about 14 percent for new wells. These 

recoveries were estimated on the basis of 120-acre spacing. Ultimate recoveries per well range from about 0.2 Bcf 

to 1.1 Bcf for the old wells (averaging about 0.6 Bcf) and 

from about 0.05 Bcf to about 0.3 Bcf for new wells (averaging about 0.2 Bcf). Most of the new wells are infill 

wells and one possible explanation for the lower recovery 

is pressure depletion, which has been evident in many 

cases. The NPC compared EEA and CNR data. In general, 

Table 14. Devonian and Atrim shale resources, in trillion cubic feet. 

[From National Petroleum Council, 1992] 

Gas in Place 

Appalachian Basin 

1980 NPC 225' 

1991 EEA t 248 

1992 NPC 248 

Michigan Basin 

1980 NPC 55 

1991 EEA t 72 

1992 NPC 35 

• Black shales only. 

Recoverable, 

Current 

Technology 

37 

25 

27 

21 

11 

t Adjusted to January 1991 basis to be consistent with 1992 NPC. 

Recoverable, 

Advanced 

Technology 

50 

40 

42 

29 

15 
NATIONAL PETROLEUM COUNCIL SOURCE AND SUPPLY STUDY 523 

the averages of the estimated recoveries of old and new 

wells drilled in a given EEA cell compared reasonably 

well with EEA's estimates. 

For the 1992 NPC study, well recoveries in several 

cells were revised as a result of CNR comparisons. These 

revisions increased the estimated recoverable gas in the 

base case by about 1.3 Tcf and reduced the costs of recovery in lower cost cells, which comprise about one-fourth 

of the total recoverable resources. The resource estimates 

for Appalachian Devonian shale exclude areas that have 

been heavily drilled. The effects of pressure depletion that 

were observed by CNR at many of the new wells should 

therefore be absent. CNR had observed that field pressure 

had dropped as much as several hundred pounds per 

square inch over several decades of gas production. 

Table 15. National Petroleum Council shale study. 

Forecasts of recoverable resources based on current 

technology were increased to allow for advances in technology such as horizontal drilling and better fracturing. 

Advanced technology was assumed to be phased in over 

20 years ending in 2010 and is the basis for the NPC estimate of recoverable resources. A second generation of advanced technology begins in 2011 and is completed in 

2030 and is used in sensitivity runs to the year 2030. The 

1991 EEA and 1992 NPC estimates do not include resources in the Illinois Basin or in basins west of the Mississippi. These areas are discussed below but were 

considered to be too speculative for inclusion in the NPC 

study. Estimates are compared in tables 16 and 17. 

The EEA had estimated a total gas in place of 248 Tcf 

in the Appalachian Basin, which was slightly higher thari 

[Well data supplied by Columbia Natural Resources. MMcf. million cubic feet. From National Petroleum Council, 1992] 

Well Class:t Old New Total 

Average Average Average 

No. Ult. Rec. Recovery No. Ult. Rec. Recovery No. Ult. Rec. Recovery County State Wells MMCF % Wells MMCF % Wells MMCF % 

Floyd KY 186 1,064 31.00 10 310 9.00 196 1,027 29.90 

Knott KY 42 440 18.10 13 61 2.50 55 350 14.40 

Letcher KY 14 290 11.90 0 14 290 11.90 

Magoffin:l: KY 5 680 0 5 680 19.80 

Martin KY 202 808 23.50 83 233 6.80 285 641 18.70 

Pike KY 143 589 13.30 5 230 5.20 148 577 13.00 

Lawrence OH 13 500 35.30 24 40 2.80 37 202 14.20 

Licking OH 4 325 50.00 0 4 325 50.00 

Meigs OH 16 190 29.20 21 50 7.70 37 110 17.00 

Buchanan§ VA 1 520 8 94 3.80 9 141 5.80 

Wise§ VA 0 7 293 12.00 7 293 12.00 

Kanawha VN 2 432 19.06 18 214 9.44 20 236 10.41 

Lincoln VN 227 713 17.32 18 294 7.14 245 682 16.57 

Logan VN 112 697 27.19 0 112 697. 27.19 

Mingo VN 181 547 21.34 24 255 9.95 205 513 20.00 

Roane VN 0 31 309 13.63 31 309 13.63 

Wayne VN 197 518 12.59 14 104 2.53 211 490 11.93 

Total/Average 1,345 554 23.83 276 191 7.11 1,621 445 18.03 

tOld Wells: Completed Prior to 1971. New Wells: Completed 1971 to present. 

:j: Utilized Floyd County, Ken\ucky GIP. 

§Utilized Letcher County. Kentucky GIP. 

Table 17. Production of Devonian and Atrim 

shale gas, in trillion cubic feet. 

Table 16. Recoverable gas resources (January 1, 

1991, basis), in trillion cubic feet. [From National Petroleum Council, 1992] 

[From National Petroleum Council, 1992] 

Run* 2000 2010 2030 

$1.50 0.34 0.29 0.16 

1990 to Second $2.50 0.39 0.50 0.51 

Current 2010 Generation $3.50 0.45 0.60 0.91 

Tech- Advanced Advanced $4.50 0.45 0.65 1.02 

nology Technology Technology 

Appalachian/ 'Maximum Gulf Coast wellhead price of gas in 

1990$ per million BTU. In some runs. prices are well 

Antrim 37 57 73 below the maximum up to 2010. 
524 THE FUTURE OF ENERGY GASES 

the 1980 NPC estimate of 225 Tcf based on black shales 

only. The 1980 NPC study estimated higher recoverable 

resources, both with current and advanced technology; 

however, these estimates were based on high prices ($9.00 

per million british thermal units (MMBtu) in 1979 dollars 

or about $16.00 per MMBtu in 1991 dollars). 

ANTRIM SHALE (MICHIGAN BASIN) 

The Antrim Shale areas of Michigan have been active in 

the last several years as drillers have responded to tax credits 

extended in 1990 legislation. Most of the drilling has been 

done by independents. The 1991 EEA gas-in-place estimate 

was 72 Tcf. Of that, about 21 Tcf was estimated to be 

recoverable with current technology and about 29 Tcf was 

estimated to be recoverable with advanced technology. 

During the NPC study, new information was supplied to 

the NPC indicating that the area that would be productive for 

Antrim Shale gas was overstated in EEA's estimate. Subsequently, EEA modified the HSM to reflect the new information. Drillable area was reduced from 34,000 square 

miles to about 17,000 square miles, and the gas-in-place 

estimate was consequently reduced from about 72 Tcf to 

about 35 Tcf; the recoverable-gas estimate was reduced from 

21 Tcf to 11 Tcf with current technology and from 29 Tcf to 

15 Tcf with advanced technology. 

OTHER GAS SHALE BASINS 

Outside of the Michigan and Appalachian Basins, 

shale gas activity has been minimal. The most widely 

known basins are in Illinois, Texas (Barnett Shale of the 

Fort Worth Basin), Oklahoma (Shales of the Hunton Group 

and Woodford Shale), and Rocky Mountains (Shales of the 

Niobrara Formation, Mancos and Pierre Shales, and Green 

River Formation). These shale basins have been minimally 

explored, and this shale gas is not well defined. The recoverable resources may be significant, but the limited knowledge of these areas available at this time precludes 

inclusion of the data in gas supply projections. 

COALBED METHANE 

The NPC reviewed information on coalbed methane 

activity and resource estimates to update the 1980 NPC 

report "Unconventional Gas Sources" and to assess coalbed 

methane's potential contribution to future U.S. gas production (see also Rice and others, this volume). 

The last 12 years have seen a significant increase in the 

production and utilization of coal bed methane. Most of this 

increase has occurred since 1986 and has been largely due to 

the stimulus of the Section 29 tax credit and early exploration succ~sses in the San Juan and Black Warrior Basins. 

These drilling programs, by several operators, took coalbed 

methane production from an experimental curiosity to an 

established resource. Coal bed methane production rose from 

40 Bcf in 1988 to 196 Bcf in 1990 and to 348 Bcf in 1991. 

Coalbed methane accounted for about 2 percent of annual 

U.S. dry-gas production in 1991. Coalbed methane wells 

increased from 736 in 1988 and to 2,414 in 1990. 

The NPC reviewed public and proprietary data from 

the coal basins of the lower 48 States to determine the 

potential for commercial gas production. NPC coalbed 

methane areas in the lower 48 States are shown in figure 5. 

The results of the NPC assessment of coalbed methane resources in the lower 48 States are summarized in table 18. 

Undiscovered recoverable coalbed methane resources total 

62 Tcf, with current technology and 98 Tcf with advanced 

technology. The estimates are based on data as of January I, 

1991. 

HISTORICAL TRENDS AND FUTURE 

EXPECTATIONS FOR COALBED METHANE 

Development of coalbed methane resources has accelerated during the past 3 years because of tax incentives 

and a better understanding of the resource and technology 

requirements for gas recovery. Proved reserves of coalbed 

methane at the end of 1990 were only about 5 Tcf. However, NPC estimates that 62 Tcf of coalbed methane are 

technically recoverable with current technology and about 

98 Tcf are recoverable with advanced technology from 

300 to 400 Tcf of estimated gas in place. 

The main uncertainties for coalbed methane resources 

concern (1) whether the Section 29 tax credit will be extended to new wells after 1992 and, if so, will it stimulate 

drilling and production as much as it has in the last 2 to 3 

years (the tax credit was not extended in 1992 legislation 

and it was not considered in the NPC projections), (2) 

whether other coal basins will become as productive as the 

Black Warrior or San Juan Basins, and (3) whether there 

will be an unexpected technological breakthrough that improves well productivity and makes otherwise marginal or 

subeconomic basins exploitable. Positive developments 

could increase estimated recoverable resources of coalbed 

methane by 1 0 to 30 Tcf. 

If coalbed methane operators can use tax credits, 

coalbed methane resource development is less sensitive to 

price. If tax credits cannot be used, many coalbed methane 

projects will remain marginally economic and extremely 

sensitive to price. Price sensitivity is especially evident in 

the Midcontinent and Rocky Mountain areas where markets 

are distant and transportation costs are high. Exceptions 

occur in the San Juan and Black Warrior Basins, where 

some wells remain profitable without the tax credit. In light 

of these considerations, the NPC has made its best estimate 
NATIONAL PETROLEUM COUNCIL SOURCE AND SUPPLY STUDY 525 

Figure 5. National Petroleum Council lower 48 States coalbed methane areas. From National Petroleum 

Council (1992). 

of the coalbed methane resource and reserves from the 

most recent data available. 

SPECULATIVE GAS SOURCES 

Natural gas also occurs in various other settings and 

categories, collectively identified by the NPC as "speculative" gas sources. These speculative sources include natural gas originating in deep (>I5,000 ft) sedimentary rocks, 

gas trapped in clathrate hydrates, and gas from geopressured aquifers. The amount of gas in these categories is 

extremely large (about II ,600 Tcf), dwarfing estimates of 

gas remaining in conventional categories. However, the 

cost and technical feasibility of recovering gas from these 

sources remain uncertain. 

The thrust of required research in connection with the 

recovery of these sources is twofold. First, research toward 

better quantitative estimates of the gas actually present in 

each of these sources is needed. Second, research is needed to identify and develop techniques for extraction of 

these resources at acceptable cost. These gas sources are 

viewed as long-range research and development efforts 

with potential payoffs beyond 20IO. 

CONCLUSIONS 

The sustainability of the natural-gas supply is not dependent on source and supply availability but on technoloTable 18. Coalbed methane recoverable resources in the lower 48 States, in trillion cubic feet. 

[From National Petroleum Council, 1992] 

Recoverable Resources 

Current Advanced 

Basin Technology Technology 

San Juan 22 33 

Black Warrior 7 10 

Piceance 17 27 

Raton and Misc. 

Rockies 8 12 

Northern 

Appalachian 9 15 

Total Undiscovered 

Resources 62 98 

gy and market conditions. The price/supply economic 

modelling approach was used to draw conclusions concerning the sustainability of a competitive gas supply between 

I990 and well beyond 2010 to 2030. For this evaluation, 

gas supply potential was assessed at various price levels-

$1.50, $2.50, $3.50, and $4.50/MMBTU (1990 dollars). 

The NPC study concluded that gas supply cannot be sustained even in the near term at $1.50, but is readily sustainable beyond 2010 at $2.50 to $3.50/MMBTU. The supply 

capability of the United States, as indicated by the NPC 
526 

:=l 

fro 

z 

0 

:J 

.....) 

a: 

0 

<{ 

:=l 

a 

THE FUTURE OF ENERGY GASES 

30 J I 

Demand Target (set at approximately 1% growth per year) 

25 

20 

15 

10 

5 

t-= -~·~-·t ~-·· 

-

.. 

-~:-~r-~T - --- ~---,... - ' ~-~ 

" ... --.-.' M, $3.50/MMBTU (max) ... ... - ' -

- - $2.50/MMBTU (max) 

~ ... ... -- - $1.50/MMBTU 

I 

(max) --I - -------- • Price growth continues until point marked by bulle!, with maximum price thereafter. 

0 

1990 2000 2010 

YEAR 

2020 2030 

Figure 6. Long-term gas supply at various maximum wellhead price levels. Demand target is fully 

satisfied through 2030 at prices that do not exceed $4.50 per million British thermal unit (MMBtu). 

Prices are in 1990 dollars for Texas Gulf spot gas. Figure assumes advancing technology. From 

National Petroleum Council (1992). 

study, is summarized and illustrated in figure 6. The principal finding of the NPC study of the resource base is that 

natural gas is an abundant domestic resource that can be 

produced and delivered at prices that allow expansion of 

the market and development of the tesource. A number of 

challenges face the United States in its development of the 

natural-gas resource; these can be overcome by a concerted 

effort of industry and government to alleviate· concerns 

about the reliability of natural gas in the view of the customer and about the further development of a competitive 

marketplace. 

REFERENCES CITED 

Dwight's Energy Data Corporation, 1985, Petroleum data system 

(through 1985): Available from Dwight's Energy Data Corporation, Oklahoma City, OK 73108. 

National Petroleum Council, 1992, The potential for natural gas 

in the United States-Source and supply: Washington, D.C., 

National Petroleum Council, 501 p. 

Office of Technology Assessment, 1985, U.S. natural-gas availability-Gas supply through the year 2000: Office of Technology Assessment Report OTA-E-245, 252 p. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Domestic Conventional Natural-Gas ReservesCan They Be Increased by the Year 2010? 

By Thomas S. Ahlbrandt1 and David J. Taylor1 

CONTENTS 

Abstract ......................................................................... 527 

Introduction ................................................................... 528 

Background ................................................................... 529 

Competition from Coal .......................................... 529 

Prices ...................................................................... 529 

Increasing Coal Use ............................................... 529 

Natural-Gas Reserve Base ............................................ 530 

EIA Annual Report ................................................ 530 

Gas Reserves ................................................... 530 

Oil Versus Gas Exploration ............................ 530 

New Fields and Field Growth ......................... 531 

Reserve to Production Ratios ......................... 532 

Productive Capacity ........................................ 532 

NRG Associates ..................................................... 532 

Significant Fields ............................................. 532 

Offshore Emphasis .......................................... 532 

Field Growth ................................................... 533 

Significant Plays ...................................... : ....... 533 

Petroleum Information Corporation Study ............ 533 

Productive Capacity ........................................ 533 

Drilling Activity .............................................. 533 

Congressional Research Service Study ................. 534 

Drilling Activity .............................................. 534 

National Petroleum Council Study ........................ 534 

Overview ......................................................... 534 

Drilling Activity .............................................. 534 

Field Growth ................................................... 534 

1

U.S. Geological Survey, MS 934, Denver Federal Center, Denver, 

co 80225. 

Natural-Gas Reserve Base-Continued 

Gas Research Institute Study ................................. 534 

Producing Gas Reserves .................................. 534 

Interpretation ................................................................. 535 

Implications for Increasing the Reserve Base .............. 536 

More Wells .............................................................. 536 

Better Prospects ...................................................... 536 

Seismic-Data Acquisition ................................ 537 

Seismic-Data Processing .................................. 539 

Seismic Interpretation ...................................... 542 

Summary ........................................................................ 544 

References Cited ........................................................... 545 

ABSTRACT 

A review of recent natural-gas studies and supporting 

data bases suggests that natural-gas reserves and excess 

productive capacity are declining and remedial action to 

ensure adequate supplies will require increased drilling of 

high-quality prospects. Conventional gas resources will remain the dominant source of natural gas through the year 

2010, although nonconventional gas sources will increase 

and competition from coal in the utility sector will remain 

strong. More than two-thirds of current domestic gas production is coming from wells 11 or fewer years old. There 

is a need for increased conventional resources to fulfill anticipated increased demand for natural gas, and new concepts, be they new geophysical techniques or looking in 

lightly explored, deep, or remote areas particularly on 

Federal lands where most undiscovered conventional gas 

resources presumably are present, are required to find 

these resources. Conventional resources discovered during 

the past decade have initial production rates nearly three 

527 
528 THE FUTURE OF ENERGY GASES 

times that of unconventional resources developed under 

tax credit incentives for wells drilled before December 31, 

1993. The industry has nearly doubled its efficiency, as 

measured by reserves found per well, from 1988 to 1991 

at a low level of drilling relative to the high level drilling 

during the early 1980's. Significant reserve growth of old, 

large gas fields has helped to reduce the rate of decline of 

gas reserves. However, a developing hypothesis related to 

the field-growth phenomenon is that younger, smaller 

fields may grow at a lower rate and for a shorter time span 

than older, larger fields. This hypothesis may reflect, in 

part, the important role of new seismic techniques to better 

define the field size and reserves earlier in the process of 

gas-field development and thereby result in more accurate 

estimates of ultimate reserves. The desire to increase natural-gas usage and preserve the land will compete with the 

need to drill more gas wells to maintain or increase natural-gas reserves. 

INTRODUCTION 

Studies of conventional natural-gas reserves and production data bases were evaluated to determine if there is a 

consensus on available natural-gas resources and, if there 

is consensus, what may be the implications. Although legislation or world events can rapidly alter the energy situation, we will use the current status of domestic natural-gas 

resources and recent industry exploration and development 

trends as a starting point to look forward to a more environmentally conscious future in which increased naturalgas usage may be favored. Most of this gas through the 

year 2010 will likely be from conventional gas sources. 

Unlike oil, natural gas has been perceived by some to 

be less profitable and more difficult to produce, transport, 

and market. On the positive side, however, under certain 

conditions, natural-gas accumulations can now be distinguished directly on specially processed seismic sections; 

therefore, the exploration and development risk and costs 

are reduced, and a better initial estimate of reserves is provided. More accurate determinations of reserves, or potential reservoirs, by high-resolution, cost-effective seismic 

data early in a field's development may help to explain a 

developing hypothesis that new field discoveries grow considerably less than some older fields. Natural gas differs 

from oil in that the current demand for natural gas is mostly 

met by domestic production, whereas the current demand 

for oil is only half met by domestic production. Currently, 

there is a record high number of producing gas wells 

(280,899) for the 25th year in a row (American Petroleum 

Institute, 1992), whereas the number of domestic producing 

oil wells has declined since 1984 and now totals 594,189 

which is a 2.6 percent drop from 1991 to 1992 (World Oil, 

1993). Perceptions of the abundance of the natural-gas resources in the United States range from very optimistic 

views expressed by explorationists to more pessimistic 

views derived from analysis of resource data bases. We defer 

to other authors in this volume (see Gautier and Brown, this 

volume) to evaluate amounts of undiscovered conventional 

(see C. Masters, this volume) and unconventional naturalgas resources and the future market of this gas. 

Episodic regulatory intervention, proration, and tax incentives further complicate both exploration as well as the 

development and interpretation of resource data bases. 

There are many recent studies appraising natural-gas resources including the U.S. Geological Survey and Minerals Management Service study of field growth and 

undiscovered resources (Mast and others, 1989), the National Petroleum Council (NPC) study entitled The Potential for Natural Gas in the United States (1992), the 

biennial projections of the Potential Gas Committee (PGC, 

1992), the annual natural-gas and energy-commodity summaries of the Energy Information Administration (EIA) of 

the Department of Energy (DOE) (EIA, 1992a, b, 1993), 

Petroleum Information Corporation's (PI) natural-gas analysis (Butler and Stark, 1993), the Congressional Research 

Service studies (Riva, I 993), the Gas Research Institute 

(GRI) analysis (Woods, 1992, 1993; Holtberg and others, 

1993), and the Natural Gas Supply Association survey 

(NGSA, 1992). In addition, large data bases have been 

constructed in recent years to aid these appraisals. They 

are the EIA oil and gas information field file (OGIFF) 

(EIA, 1992a, b), Richard Nehring's significant oil and gas 

field file (NRG Associates, 1992) and the PI well history 

control system and production data file. The U.S. Geological Survey has been actively involved in many of these 

studies and in the construction and (or) use of these data 

bases, which have provided much of the documentation 

for U.S. Geological Survey oil and gas assessments (Mast 

and others, 1989). 

The inconsistency of terms and categories among these 

data sets clouds our perception of the relative number of 

wells drilled, the measure of their economic success, and 

the reserves and production established by such success. 

For example, EIA's revised exploratory well total for 1990 

is 4,920; PI's new field wildcats total is 2,684, and the 

American Petroleum Institute (API) new field wildcats 

total is 2,558. Significant success rates for 1990 are given 

as 5.86 percent by API, 5.59 percent by PI and 24 percent 

(total success) by EIA. A reader using the three different 

sources could conclude that the number of exploration 

wells drilled in 1990 ranged from 2,558 to 4,920 and the 

success ratio ranged from 5.59 percent to 24 percent! 

The perception of natural-gas resources that results 

from these inconsistent data is certainly confusing. One 

could conclude that the U.S. natural-gas resource base is 

plentiful and will be used to solve our environmental, 

transportation, and utility concerns. Alternatively, the perceived gas bubble will disappear and a collision course 

awaits with declining gas-well productivity and increasing 
DOMESTIC NATURAL-GAS RESERVES-CAN THEY BE INCREASED BY THE YEAR 2010? 529 

demand. Both scenarios cannot be simultaneously true, yet 

both scenarios are actively espoused. The domestic oil and 

gas industry awaits the outcome of this struggle. 

BACKGROUND 

COMPETITION FROM COAL 

A commonly held perception is that domestic naturalgas production and reserves are on a strong upswing while 

competing fuels, particularly coal, are decreasing as a result 

of increasingly stiff environmental regulations. Figure 1 

shows domestic energy consumption and production by 

commodity from 1950 to 1991 (EIA, 1992a). Since 1960, 

coal production has virtually doubled and is likely to continue to grow (Gluskoter, 1991). By contrast, the percentage of natural-gas usage for electricity generation has 

declined from 24.3 percent in 1970 to 9.4 percent in 1991 

(EIA, 1992a). The curves shown on figure 1 reflect several 

legislative actions, which affected each commodity differently; however, the most dramatic event for all three energy 

sources (that is, natural gas, crude oil, and coal) occurred in 

1973 following the Arab oil embargo. After 1973, domestic 

coal usage increased to the point that by the middle of the 

1980's, energy production by coal exceeded energy production by either natural gas or oil and continued to increase 

whereas energy production by oil and natural gas generally 

decreased; oil and gas have only recently stabilized (fig. 1 ). 

PRICES 

Traditionally natural-gas and coal prices have been 

tied to the price of oil. For example, for the 1989 U.S. 

Geological Survey and Mineral Management Service assessment (Mast and others, 1989), the natural-gas acquisition price had fallen to about 56 percent of the Btu (British 

thermal unit) equivalent price of oil. Price fluctuations 

have been more volatile for natural gas during the past 

several years than for oil. Gas prices have either doubled 

or halved in the course of a single year (Parent, 1993). 

Similarly, coal prices per ton were based or at least strongly correlated with oil price although this relation seems to 

have been less certain in recent years (Gluskoter, 1991 ). 

The real prices of coal in 1987 dollars have been stable to decreasing since 1975 and nominal coal prices have 

been decreasing since 1983 (fig. 2A), whereas nominal and 

real natural-gas prices have shown substantial long- and 

short-term instability. However, natural-gas prices currently (1993) are considerably above 1973 prices (fig. 2B, 2C; 

Parent, 1993). Projections by various groups suggest further significant gas price increases. For example, the NPC 

predicted a price of either $3.50 per thousand cubic feet 

(Mcf) or $4.50 per Mcf by the year 2010 (NPC, 1992) in 

40 

35 

i 30 

g 

§ 25 

1 

£20 

g 

a 

E 15 

~ " 10 

--Coal 

----- NaruralGas 

--······· CI\JdeOil 

+-+++++ t- 1- I + Hl-+-1-+--1-+--1-+--t-+-t-+-++++~ t-+-+-+-+-+-+-+-+-+-n 

A 

25 

20 

\,/·, ___ :; ..... ;- ____ 

--Coal 

-----Natural Gas 

---- Crudem 

B 

Figure 1. Domestic energy consumption. A, Domestic energy 

production. B, Coal, natural gas, and crude oil from 1950 to 

1991. Data from the Energy Information Administration ( 1992a). 

contrast with rather fiat to declining prices for coal. Such a 

price scenario might favor coal usage if external parameters such as environmental legislation are excluded. 

INCREASING COAL USE 

Despite all internal and external influences, coal production from 1973 to 1991 has doubled, whereas naturalgas production has declined 17 percent and oil production 

has declined 20 percent (EIA, 1992a). Meanwhile the price 

of coal has stabilized and even decreased recently relative 

to natural-gas prices, which are considerably more volatile 

(figs. 2A, 2B). There has been a shift, not only in increased 

production and consumption of coal, but also a geographic 

shift in the source of domestic coal related to the Clean Air 

Act and other legislation. The shift to those coals, which 

comply with reduced SOx, NOx, and other gas emission 

standards, favors western U.S. coals relative to certain 

eastern U.S. coals. This changing environmental influence 

is reflected in the coal production data over the past few 

years. Coal production from Wyoming exceeded that of 

Kentucky for .the first time in 1988 and in each subsequent 

year (Coal Data, 1991 ). It is far easier to. look backward 
530 THE FUTURE OF ENERGY GASES 

than project forward; however, if recent history is any 

measure of the future coal usage, coal production will certainly grow on a global scale, if not nationally. Coal will 

continue to compete strongly with natural gas, particularly 

if new coal gasification techniques prove economically viable, as demonstrated by the steady increase in coal consumption and production (figs. 1A, 18). 

45 

40 

-a 35 B 

~ " 30 

t 

"'25 

~ :9 20 

-~ 15 

"' 

~ 10 

A 

0.5 

Bituminous and lignite 

Bituminous and flgnite 

+-+++++-+-+-+--+-+-++++-1-+-H 

I 

I 

/ 

/ 

--------

I 

I 

I 

I 

I 

I 

' ' 

I 

I 

I 

I 

I 

I ' \ I \ 

I I 

I I I I I I 

' I 

~-F't··i="t--;-:tlt ltlt lt-+t ::;=;=;:::;:::;:;:::;:::;:::;::::;::.:::;:::;:::-+-+-H-+-r-r-H-H-H-+--+-H 

B 

1992 1993 

c 

Figure 2. Long-term prices for coal and natural gas. A, Longterm nominal and real prices of bituminous coal, lignite, and all 

coal from 1950 to 1991. B, Long-term nominal and real prices of 

wellhead natural-gas prices from 1950 to 1991. Data for A and B 

from the Energy Information Administration ( 1992a). Real prices 

in 1987 dollars. C, Short-term natural-gas prices from 1992 to 

1993. Data from Petroleum Information Corporation ( 1993). 

NATURAL-GAS RESERVE BASE 

As opposed to estimating undiscovered resources, a review of natural-gas reserves studies including the projected 

growth of fields, should be a relatively more precise exercise because numerous production and reserve data are 

available as described in the "Introduction" section. There 

are some salient or comparable points from the review of 

each data base and (or) analysis. 

EIA ANNUAL REPORT 

GAS RESERVES 

The most recent published results of natural-gas reserves, which will serve as a baseline for subsequent discussion, is derived from the EIA's annual survey (EIA, 

1992a). The report includes information gathered through 

Form EIA-23, "Annual Survey of Domestic Oil and Gas 

Reserves." Issues about definition arise when trying to 

compare reporting categories of reserves among various 

analysts. In the EIA report, dry natural-gas reserves are 

separated from liquid natural-gas reserves and include both 

associated and nonassociated gas. Proved natural-gas reserves, which include revisions and adjustments plus total 

discoveries less production, show an overall decline of 34 

percent from the highest reserve year of 1967 to 1991 

(fig. 3). There are caveats to this overall decline such as the 

removal of Alaskan North Slope proved gas reserves in 

1988, which were not considered economic at that time 

(Mast and others, 1989); however, the lower 48 States 

proved gas reserves also show a slight decline of 7 percent 

subsequent to 1988 as well. 

OIL VERSUS GAS EXPLORATION 

To determine the relative proportion of oil to gas exploration, we again have to review various subsets of the 

300 L::7 

250 

j 200 

" ~ u 150 c 

,g 

~ 100 

50 

1967 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 

Figure 3. Proved gas reserves from 1967, the highest recorded 

reserves, to 1991. Data from the Energy Information Administration (1992b ). 
DOMESTIC NATURAL-GAS RESERVES-CAN THEY BE INCREASED BY THE YEAR 2010? 531 

data base. For example, the percentage of gas wells drilled 

in 1991 of the total of exploratory and development wells 

drilled is 31 percent according to the EIA ( 1992b ). However, if we restrict the area of interest to only successful 

exploratory wells drilled in 1991, the percentage of successful natural-gas completions is 48 percent. From 1970 

to 1991, exploratory gas completions exceeded oil completions from 1973 through 1980. However, at no time 

during the period from 1970 to 1991 did gas completions 

exceed oil completions when total exploratory and development wells were considered. Total drilling in 1991 has 

returned to the level of the early pre-oil embargo 1970's. 

Drilling was at its highest level in 1981 and totaled 90,030 

wells. Today drilling activity is 29,410 wells, which is 

about one-third of the 1981 rate (EIA, l992b ). The overall 

ratio of oil and gas in terms of total exploratory and development wells is also roughly the same as the early 1970's. 

NEW FIELDS AND FIELD GROWTH 

A complicated picture of the state of proved natural-gas 

reserves emerges if we look at the two components of (1) 

revisions and adjustments and (2) new field discoveries. 

New field discoveries over the 11 year period from 1981 

through 1991 as reported by EIA (1992b) are shown in 

figure 4. From a high of 3.7 trillion cubic feet (Tcf) in 1981, 

there has been a 77 percent decrease in new field discoveries to less than one Tcf in 1991 (0.85 Tcf). Fortunately, the 

phenomenon of field growth reflected in categories such as 

revisions and adjustments, extensions, and new reservoir 

discoveries in old fields helped to maintain reserves from 

the precipitous decrease in new field discoveries (also called 

"inferred reserves" by Root and Mast, 1993). The phenomenon of field growth in which the estimated recoverable 

reserves of a field increase through time due to extensions, 

infills, or increased recovery efficiency can account for significant reserve additions. There are a range of estimates of 

the amount of such growth in natural-gas fields (fig. 5). The 

duration of such field growth is also debated-the observed 

4000 

,------~---------------------------------, 

p 3500 

3000 

! 2500 

0 

:;; 

~ 2000 

i 

ii 1500 

n 1000 

500 

1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 

Figure 4. Volumes of new gas field discoveries from 1981 to 

1991. Data from the Energy Information Administration ( 1992b ). 

growth for old fields ranges from 60 years following discovery (Mast and others, 1989) up to 100 years (EIA, 1990b ). 

Others observe, for recent field discoveries, relatively shorter lived field growth of a few years (Butler and Stark, 1993; 

NRG Associates, 1992). Thus, in spite of the significant tax 

credit incentives that resulted in the addition of 3.1 Tcf of 

coalbed methane reserves in 1991, which are included in the 

data set, there were significant declines in 1991 relative to 

1990 in total discoveries (39 percent), new field discoveries 

(55 percent), extensions (36 percent) and gas-reserve additions from new reservoirs in old fields (33 percent) (EIA, 

1992b). Exploratory U.S. gas completions are at there lowest level since 1970 (fig. 6). Were we to solely look at 

projections based on these data at current prices, prevention 

of significant erosion of proved reserves by improved recoveries or field growth might be an overly optimistic goal. 

From 1988 to 1991, even though these were record 

low exploratory drilling years, the petroleum industry became more than twice as efficient in exploration on the 

basis of per well recoveries compared to the record high 

drilling years from 1979 to 1982. During the high-level 

drilling years from 1979 to 1982, the annual completed gas 

discoveries per well were less than half ( <7 .5 billion cubic 

feet or Bcf per well) of those drilled in the low-level drilling years from 1988 to 1991 (>15 Bcf per gas well) (EIA, 

1992b). The overall 23 to 24 percent success ratio for exploratory wells for each year from 1988 to 1991 is much 

improved from the early 1970's when success rates were 

300 

250 

200 C7 

/J 

150 

100 

'"] .. -,_ on -

" "' 0> 

;; go "' .0 

-g 0 J: "C 

~ 

" 

~ 

:2 "

cCJ 

-

* 0 

0 

a: 

L_ 

"' "' 0> 

~ 0 

-g 

" <;; 

-:;; 

u: 

~ 

- -

~ 

<;; 

= 0 

-g 

" 

~ :2 

~~ 

0 

"' 0. 

-

"' 0> 

0> 

~ 

"' "ll 

g 

~ B 

0 

I 

?7 

L:7 

- T'--:- ~ 

~ ~ 8 N' 

N' 0> 

0> 

~ 0 

0. 0 z 0. 

z 

Figure 5. Estimates of volume of gas derived from field growth 

of natural gas reserves (also called growth to known reserves, 

reserve appreciation, or inferred reserves). Oldest estimate (on 

left) to more recent estimates (on right). Sources of information 

shown on horizontal axis. Adv., advanced technology. 
532 THE FUTURE OF ENERGY GASES 

30000 

25000 

20000 .!1 

; 

a 

... 15000 

~ :il 10000 

5000 

' ' ' 

X_ Rrva --Exploratory 

- - - - - Exploratory and Development 

--------·()=~ 

------ NPC-case1 

------- NPC..Case2 

-------

--------------------......_ t-+-1--f-'Ft-t-+-+-+-J +++++++-1-+--t-+ H 0 

0 

N 

Figure 6. Historical levels of exploratory and total exploratory 

and development natural-gas wells from 1970 to 1991 (ETA, 

1992b) and projections of exploration and development gas drilling activity from 1992 to 20 I 0 as projected by the Gas Research 

Institute, GRI, (Woods, 1993 ), and two projections by the 1992 

National Petroleum Council Study, NPC, (1992). Necessary drilling activity needed to sustain the level of natural-gas reserves as 

proposed by Riva (1993), X, and Petroleum Information, PI, 

shown for near term only for comparison. 

16 to 18 percent as calculated from EIA data (EIA, 1992b ). 

The highest success rates for exploratory wells, about 30 

percent, occurred from 1979 to 1982 coincident with low 

per well discoveries; these data suggest that many poor 

wells were completed during the drilling boom, and that 

the industry has become more efficient and economic in its 

exploration during the subsequent bust. 

RESERVE TO PRODUCTION RATIOS 

A measure of uncertainty for the natural-gas reserve 

base is the declining reserves to production ratios for natural gas, which have declined for the United States from a 

high in 1945 of about 33 to 1 to a current low of about I 0 

to I (EIA, 1992b ). EIA (1992a) notes significant regional 

differences in natural-gas reserve to production ratios. 

Areas of the country such as the Rocky Mountains that are 

newly discovered or less developed have high ratios. For 

example, New Mexico has a reserve to production ratio of 

18 to I; whereas Alabama has a ratio of 36 to I; the ratio 

for Alabama reflects the recent active drilling in these regions induced by tax incentives particularly for coalbed 

methane. Conversely, the major gas producing areas have 

reserve to production ratios below the national average 

such as the Gulf of Mexico Federal offshore (6 to 1), 

Texas onshore (8 to I), and Oklahoma (7 to I) (EIA, 

1992b). Analyses by NRG Associates demonstrate significant (>6 Bcf or I million boe (MMboe)) natural-gas reserve additions in these last three regions-in the same 

regions where EIA concludes that natural-gas reserve to 

production ratios are below the national average of 10 to 

I. In summary, EIA ( 1992b) data projects less than I 0 

years of natural-gas reserves at current production rates in 

the major domestic gas provinces of the midcontinent and 

Gulf of Mexico. 

PRODUCTIVE CAPACITY 

Most recently, EIA (1993) indicates that gas productive capacity is expected to decline sharply in the next 2 

years by 5.0 percent in 1993 and 3.4 percent in 1994. This 

shrinking capacity is expected to cause an increase in 

wellhead gas prices from $1.84 to $2.18 per Mcf by 1994. 

This view of near-term decreased gas productive capacity 

contrasts markedly with the view of Woods ( 1992) discussed in the section "Gas Research Institute." The views 

of different estimators are summarized as follows: 

NRG ASSOCIATES 

SIGNIFICANT FIELDS 

Comparison between the EIA and NRG Associates 

data bases is not simple. NRG considers only significant 

oil and gas fields (> 6 Bcf of gas or I million barrels of 

oil (MMboe); whereas, EIA reports all drilling results including small fields. NRG Associates publish a newsletter 

entitled "Exploration Insight" in which they evaluate and 

compare their significant oil and gas fields of the U.S. data 

base with other sources of data including API and PI. In 

NRG Associates November 1992 newsletter (which has 

the same release date as the most recent EIA annual summary), a different conclusion regarding new field successes is reached relative to the EIA data. NRG Associates 

(1992) argue that significant fields discovered in the United States have stabilized in the past few years and are 

comparable to more favorable discovery periods if viewed 

in light of the past half century of exploration. Discoveries 

of recent significant fields are still at a comparatively low 

level and are roughly comparable to the levels of 1967 to 

1971 and 194I to 1947, but they are only 50 to 60 percent 

of peak levels of the 1950's and 65 to 75 percent of levels 

achieved from 1973 to 1982. The current levels of discovery are substantially higher than the low level of 1986. 

They argue that overall significant success rates of from 5 

to 6 percent are similar regardless of the source of data 

(API or PI). NRG Associates (1992) argue that nationwide 

the ratio of oil discoveries to gas discoveries has been relatively constant since 1988. For instance, of 107 total significant discoveries in 1990, 64 percent were gas, 30 

percent were oil, 6 percent were both oil and gas. These 

figures are virtually identical for the 112 significant fields 

discovered in 1989. 

OFFSHORE EMPHASIS 

The proportion of offshore discoveries to onshore discoveries increased from 38 percent of the total in 1989 to 
DOMESTIC NATURAL-GAS RESERVES-CAN THEY BE INCREASED BY THE YEAR 2010? 533 

nearly 45 percent in 1990 (NRG Associates, 1992). This 

trend toward more offshore exploration is enhanced by the 

ease of acquisition of offshore marine seismic data, which 

further reduces exploration risk in areas such as the Gulf 

of Mexico where direct seismic detection of natural-gas 

accumulations is increasingly relied upon to define smaller 

fields. 

FIELD GROWTH 

The declining size of new field discoveries is a well 

known phenomenon with larger fields found early in the 

exploration of a region following by decreasing field sizes 

through time. This phenomenon is the basis for forecasting 

future resources in the technique known as discovery process modeling (Mast and others, 1989; Drew, 1990; Drew 

and Schuenemeyer, 1993). NRG Associates (1992) preliminarily observe that significant or potentially significant 

discoveries made in the late 1980's do not grow significantly after the few years of production following discovery and have proportionately more rapid declines in 

subsequent production. While this observation is preliminary, it is worth noting that new field sizes are declining 

(Drew and Schuenemeyer, 1993) and it suggests a potential 

relation between field growth and field size. It also suggests that there may be a regional influence with the Gulf 

Coast showing the greatest field growth where limited to a 

few years duration. This analysis is supported by the Petroleum Information study of Butler and Stark (1993 ). 

SIGNIFICANT PLAYS 

NRG Associates (1992) further analyzed their reserve 

data base by subdividing their data into 580 plays. They 

evaluated both new plays in 1990 only and exploratory 

plays from 1986 to 1990 of the 580 plays nationwide. They 

found 33 plays that had at least 150 Bcf or 25 million 

barrels of oil equivalent (boe) discovered in them during the 

1980's. Of these 33 plays, 23 occurred in the Gulf Coast 

Basin onshore (9) and offshore (14), Arkoma Basin (2), 

Michigan Basin (2), Permian Basin (2), and one each in the 

Anadarko Basin, Arctic Slope Basin, Black Warrior Basin, 

and Powder River Basin. The most active plays were predominantly gas plays (23 of the 33); 6 were both oil and gas 

and only 4 were oil plays. The estimated ultimate recovery 

per play was estimated to be 3.3 to 5 Bboe (billion barrels 

of oil equivalent) producing an average of 0.66 to 1 Bboe 

per year. They conclude that significant exploration potential remains in conventional plays in the United States. 

However, a new approach will be required to develop these 

plays. There will likely be a shift from exploring for minimum prospect sizes to a strategy driven by minimum attainable play potential. From 1986 to 1990, two-thirds of the 

significant plays in the United States were gas plays, which 

reflect the increased role of natural gas in the energy mix. 

PETROLEUM INFORMATION 

CORPORATION STUDY 

PRODUCTIVE CAPACITY 

Butler and Stark (1993) recently presented Petroleum 

Information's (PI) analysis of natural gas in a study entitled "U.S. Gas Outlook: Where will we get it?" They 

project a 3 trillion cubic feet (Tcf) per year decline in 

gross wellhead production capacity, which will fall short 

of the Nation's demand for natural gas. They argue that 

two-thirds (68 percent) of the current U.S. gas production 

as of December 1991 comes from wells that are 11 years 

or younger. As pointed out previously, we are currently 

drilling less than one-third of the wells of the early 1980's. 

Butler and Stark (1993) project a production decline in existing wells of the lower 48 States from 18.5 Tcf per year 

in 1991 to 8.6 Tcf per year by the end of 1995-an overall 

14 percent decline. Anticipated drilling is projected to add 

back some 6.9 Tcf per year; however, P.H. Stark (oral 

commun., 1993) now believes that the drilling levels used 

in their model were too high because the model incorporated an anticipated increased drilling activity in 1993. But 

there has been a 34 percent decline in drilling activity in 

the first quarter of 1993 following the termination of the 

Federal Energy Regulatory Commission (FERC) section 

29 incentives at the end of 1992. Fifty percent of the gas 

completions drilled from 1978 through July 1992 were for 

unconventional gas resources, which had tax incentives. In 

fact, during this period, the industry drilled 79,267 section 

29 gas wells, including wells penetrating tight sandstone, 

coalbed methane, and Devonian shales. The initial potential for the unconventional wells, however, averaged 613 

Mcf per day, which is about one-third of the average conventional gas well, which had' an average initial potential 

of 1 ,800 Mcf per day (P.H. Stark, oral commun., 1993). 

The authors document a short-lived field-growth phenomenon alluded to by NRG Associates for fields discovered 

since 1980 and demonstrate that newer field discoveries 

are declining rapidly (fig. I) for gas wells drilled from 

19 80 to 1991 (Butler and Stark, 1993 ). They argue that the 

gas bubble will soon disappear, and they conclude that 

productive capacity is no more than 80 percent of measured capacity; thus there is little spare productivity to meet 

increasing demand. 

DRILLING ACTIVITY 

Acco~ding to P.H. Stark (oral commun., 1993), between 15,000 and 18,000 gas wells will need to be drilled 

in each year commencing in 1993 to maintain the domestic natural-gas reserve base. 
534 THE FUTURE OF ENERGY GASES 

CONGRESSIONAL RESEARCH SERVICE STUDY 

DRILLING ACTIVITY 

Perhaps the most startling view of the declining natural-gas reserve base is provided by Riva (1993). He estimates that 13,334 wells were drilled for natural gas (both 

exploration and development) in 1991,9,010 of which were 

completed as producers according to EIA (1992b). Riva 

( 1993) argues that this yearly drilling rate is low compared 

to the yearly rate of 21,000 to 27,000 natural-gas wells in 

the late 1970's and 1980's and that more than 30,000 gas 

wells per year are needed to meet future gas demands. He 

relies on increased drilling to fill the impending supply gap 

in natural gas and that significant investment of time and 

money will be needed to develop new energy technology to 

replace fossil fuels. He feels that a natural-gas shortage 

could happen sooner rather than later. He concludes that we 

have about a 16-year supply of producible gas including 9 

years of proved reserves plus perhaps 6 years from field 

growth and 1 year from undiscovered resources (if the drilling experiences of the past decade are repeated). In summary, according to this study, current production will not 

sustain the anticipated demand and a significantly higher 

rate of drilling will be required immediately. 

NATIONAL PETROLEUM COUNCIL STUDY 

OVERVIEW 

The 2,012 page, six-volume publication entitled "The 

Potential for Natural Gas In the United States" was released 

by the NPC in December 1992 (NPC, 1992). This 2-year 

study was a collaborative effort of over 200 individuals in 

industry, government (including the U.S. Geological Survey), trade associations, academia, and private enterprise. 

This study is summarized elsewhere in this volume (see 

Gautier and Brown, this volume). In brief, the NPC study 

discusses two relatively optimistic views of the natural-gas 

resource base and the ability of field growth and unconventional resources to meet anticipated increased demand for 

natural gas relative to the Butler and Stark (1993) and Riva 

(1993) studies. The NPC study describes two cases. Case I 

is that energy demand grows at 1 percent per year with a 

crude-oil price in 1990 dollars of $28 per barrel (maximum 

of $4.50 per Met) in 2010. Case 2 is that energy demand 

grows at 0.5 percent per year with a crude-oil price in 1990 

dollars of $20 per barrel (maximum of $3.50 per Met) in the 

year 2010. Both NPC cases portray optimistic projections 

for higher gas usage, higher gas prices, and more production 

by the year 2010. They anticipate that a large part of the 

supply will be met through substantial gas-reserve additions 

from field growth and unconventional resources, particularly from tight gas sandstones. The NPC study does acknowledge a third, less optimistic case at lower gas prices where 

there would be a dramatic decline in gas supply potential 

and drilling activity (NPC, 1992, vol. I, fig. 2) brought on 

by a fall in gas prices to $1.50 or less per Mcf. 

DRILLING ACTIVITY 

The NPC argues that by the year 2010, gas-well completions wiJJ range from 12,000 (case 2) to 18,000 (case 1) 

per year compared to the 9,010 gas in 1991, the last year 

of complete data (EIA, 1992b). Many projections of price, 

technology, imports, markets, and demand are contained in 

the NPC study and summarized by Gautier and Brown 

(this volume). Drilling activity related to the two reference 

cases is shown in figure 6. 

FIELD GROWTH 

The subject of reserve growth, also called growth to 

known, inferred reserves or reserve appreciation, will provide a critical component of additional gas reserves according to the NPC study. The report predicts as much as 

250 Tcf of cumulative reserve additions by field growth by 

the year 2010 (NPC, 1992, vol. 2). There are a variety of 

opinions about the magnitude of field growth (fig. 5); 

however, the projected 250 Tcf value for field growth from 

1992 to 2010 represents a consensus of industry, trade 

group, and government investigators. This reserve growth 

of 250 Tcf (from 1992 to 2010) may account for more gas 

reserves than current proved reserves of natural gas estimated at 167 Tcf (EIA, 1992b). 

GAS RESEARCH INSTITUTE STUDY 

PRODUCING GAS RESERVES 

EIA ( 1992b) reported that proved gas reserves were 

indeed declining. Woods (1992, this volume), however, argues that producing gas reserves have not declined and that 

producing gas reserves are stable. Woods believes that gas 

drilling activity has become a poor leading indicator of 

new gas additions in terms of deliverability. He also argues 

that nonproducing gas reserves have increased from 23 Tcf 

in 1982 to 35 Tcf in 1990 with most of that increase coming from onshore regions. His analysis finds that the share 

of deeper wells (>5,000 ft or I ,650 m) that produce only 

gas as opposed to shallow wells that produce only gas has 

increased in recent years and that there is an increasing 

emphasis on drilling deep offshore gas wells in the Gulf of 

Mexico owing to their high deliverability. This shift, he 

argues, is consistent with the Natural Gas Supply Association (1992) survey, which showed that offshore gas deliverability increased in 1991 more than offsetting the 

anticipated decline in gas deliverability despite decreased 
DOMESTIC NATURAL-GAS RESERVES-CAN THEY BE INCREASED BY THE YEAR 2010? 535 

drilling activity levels. Thus, Woods suggests that proved 

reserves and drilling activity are poor indicators of producing gas reserves. Rather he would prefer gas deliverability 

as a measure of producing gas reserves. Woods argues that 

an analysis of drilling depth distributions should be used in 

conjunction with drilling activity to give a clearer picture 

of the true nature of the Nation's gas reserves. Thus, 

Woods surmises that the gas bubble has perpetuated in 

spite of an overall 10 percent decline in drilling in 1991 

owing to increased offshore drilling for gas and increases 

in onshore depth of drilling, both of which have actually 

allowed an increase in gas deliverability in 1991 over 

1990. In other words, industry has become so much more 

efficient in exploration that, in spite of less drilling, the 

"gas bubble" has been maintained and does not appear to 

affect deliverability. 

Although data in the 1992 ·EIA report can be used to 

support Woods (1992) argument of stabilizing producing 

gas reserves, more recently EIA (1993) has projected a 

sharp decline in gas deliverability in 1993 and 1994. EIA 

(1993) expects gas production capacity to fall by 5 percent 

in 1993 and by 3.4 percent in 1994. This shortfall is expected to drive up gas prices, as it seems already to be 

doing, and thereby cause an increase in drilling for gas 

wells in 1993 and 1994. 

In a separate discussion by Woods (1993), conventional high-permeability gas resources are expected to dominate natural-gas production; they should provide 72 

percent of production in lower 48 States and gradually decline to 66 percent of production by the year 201 b. He 

argues that the remainder of the lower 48 States' gas supply would come from a combination of associated gas, 

low permeability, Devonian-age shale, and coalbed methane sources totaling less than one-third of the lower 48 

States gas supply through the year 2010. By means of 

comparison, the NPC (1992) study argues that using current technology (total assessed natural-gas resource of 905 

Tcf), 62 percent of our natural-gas supply by the year 

2010 will be from conventional sources and using advanced technology by the year 2010 (total assessed resource of 1,135 Tcf) only 54 percent will come from 

conventional gas resources. These are vastly different scenarios of the role of conventional gas resources versus unconventional resources, but conventional gas resources 

will dominate through the year 2010 according to both the 

Woods (1993) and NPC (1992) studies. 

T.J. Woods (oral commun., 1993) further argues that 

the source of these conventional gas resources will come 

from increasingly greater depths on the basis of greater 

gas recoveries being observed in the lower 48 States at 

each successive 5,000 foot (1,640 m) increment through 

the 25,000 foot range. The need to more precisely define 

such deep resources through risk reduction methods such 

as seismic is imperative because drilling and completion 

costs rise exponentially for deep wells (beyond 20,000 ft). 

INTERPRETATION 

Deriving overall meaning from the six most recent 

conventional natural-gas studies is a difficult task. The first 

point of general agreement is that gas drilling activity is at 

a low level even though recent tax incentive legislation 

increased the drilling for gas. Second, natural-gas exploration has become more efficient, as indicated by nearly 

twice the gas reserves per new well during the past 5 years 

(1986-1991) relative to the previous 5 years (1980--1985). 

The increase in reserves per well has occurred despite 

higher prices and drilling activity in the earlier period. 

Third, the size and number of new gas field discoveries are 

decreasing. New field discoveries are at their lowest level 

since 1981 and drilling activity continues to decrease. 

Fourth, field growth has been an important factor in maintaining gas deliverability and minimizing the loss of the 

natural-gas reserve base; however, as new field discoveries 

decrease in size, significant field growth may also be diminishing. And fifth, proved gas reserves and gas productive capacity is shrinking in spite of a record number of 

producing gas wells. 

A fair conclusion from the summarized studies is that 

the natural-gas reserve base may not be sustainable unless a 

dramatic increase of drilling commences soon. We would 

further argue that the bulk of additional reserves in the near 

future will have to come from conventional reservoirs, including those which may occur in areas designated as unconventional gas because conventional reservoirs average 

nearly three times the initial production of the average unconventional well (P.H. Stark, oral commun., 1993). Increasing the drilling activity from current historical lows 

will be an enormous task in light of the low active rig count, 

low seismic-crew activity, and loss of more than 50 percent 

of the experienced industry personnel (over 450,000 people 

in the last decade by many estimates, Riva, 1993). 

The expiration of the section 29 FERC incentives on 

December 1992 has resulted in a 34 percent decline in drilling activity in the first quarter of 1993 from 926 rigs in 

December 1992 to 611 rigs in March 1993 (PI, March 

1993). As noted in the "Background" section of this paper, 

dramatic swings in energy usage have accompanied political or social events. In the current depressed state of the 

petroleum industry, we find it hard to envision drilling 

30,000 gas wells a year, without Federal intervention. Such 

Federal legislation could be brought on by reserve loss, 

political instability in a significant petroleum producing 

country of the world, or environmental pressures mandating 

increased gas use. 

The NRG Associates' analysis and GRI analysis 

(Woods, 1992; 1993) suggest that substantial exploration 

pot~ntial remains and that much of this potential is in gas 

plays particularly in the offshore Gulf Coast and onshore. 

This potential, however, is at a level lower than the prolific levels of the 1950's but higher than the levels of the 
536 THE FUTURE OF ENERGY GASES 

mid-1980's. On the basis of the EIA data (1992b, 1993), 

one could conclude that many low productivity wells are 

being completed that do not contribute significantly to reserves. This last point is reinforced when one considers 

that there are declining natural-gas reserves despite the 

record number of current producing gas wells (280,899), 

which have been steadily increasing in number since 1967. 

IMPLICATIONS FOR INCREASING THE 

RESERVE BASE 

MORE WELLS 

According to data contained in the Petroleum Information Corporation files, drilling for new field wildcats, both 

oil and gas, peaked in 1981 with 10,675 wells and declined to 2,684 wells in 1991, a 75 percent decrease. The 

American Petroleum Institute (1992) showed a decline of 

68 percent for the same period but shows only 8,034 new 

field wildcats in 1981 as compared to 2,558 wells in 1991. 

Riva (1993) argues that in excess of 30,000 natural-gas 

wells per year must be drilled to sustain future gas production. If not sustained, other forms of energy, or imports of 

gas, may be required to substitute in part for domestic natural gas by the year 2000. As shown by Dolton and others 

( 1990), 53 percent of undiscovered conventional gas resources lie beneath Federal lands or waters. Moratoria imposed on major offshore areas along the East Coast, West 

Coast, and Florida further intensify activities in those Federal areas where drilling is permitted. The impact of drilling 30,000 gas wells a year, the majority of them on 

Federal lands will drastically affect Federal land managing 

agencies in many ways. Drilling on Federal land requires 

long lead times and considerable expense both to operators and affected agencies to satisfy requirements such as • 

tract nomination and leasing, environmental impact studies, resource management, and land-use planning area 

and (or) development strategies. Land managing agencies 

may not be able to quickly respond to such increases partly because of reductions in many Federal energy resource 

programs paralleling the severe reductions in the oil and 

gas industry. The drilling infrastructure, investment capital, experienced people to permit, drill, complete, transport, and market such a record high level of activity are 

simply unrealistic in the next few years. A more modest, 

but significantly increased level of drilling of 15,000 to 

18,000 gas wells per year seems optimistic in light of first 

quarter of 1993 in which gas drilling in the United States 

is down 34 percent relative to drilling in December 1992; 

this decrease reflects the repeal of tax credits for new 

wells drilled in 1993. Productive capacity has reached 80 

percent of measured capacity. Should demand for natural 

gas increase, there is little excess capacity. (Butler and 

Stark, 1993). This underscores the need for increased drilling for conventional gas accumulations. 

-Others argue that productive capacity has been stable 

and, therefore, the number of new gas wells required to 

maintain the natural-gas reserve base is adequate at approximately current levels (Woods, 1992). The Gas Research Institute (Holtberg and others, 1993) predicts 

reduced levels of drilling through 1995, marginally increasing to 10,403 gas wells per year by the year 2000, 

and a maximum of 16,542 gas wells per year by the year 

2010 (fig. 6). The GRI model used to produce the estimates of drilling shown in figure 6 is the hydrocarbon supply model developed by Energy and Environmental 

Analysis (EEA) of Arlington, Virginia. The EEA hydrocarbon supply model was also used for the 1992 NPC study, 

using various assumptions about price, demand, resources, 

and technology. The NPC study anticipated decreased 

drilling to a level less than 8,000 gas wells per year in 

both of their reference cases in 1992 but then predicted 

increased drilling by the year 2000 to 12,500 gas wells per 

year under reference case 1 and about 9,000 wells per year 

under reference case 2. By the year 2010, the NPC study 

estimates 18,000 gas wells per year will be drilled under 

reference case I and 12,000 gas wells per year under reference case 2-both cases end with more gas wells drilled 

per year than were drilled in 1991 (fig. 6). 

The projections of Butler and Stark (1993) and Riva 

(1993) require an immediate upswing in drilling in 1993, 

which is in marked contrast to GRI's (Holtberg and others, 

1993) projections of stable or declining drilling and the 

NPC reference case 2. The NPC reference case 1 calls for 

increased drilling of about 33 percent (that is, from over 

9,000 to over 12,000 gas wells per year) through the year 

2000, which is modest compared to the intense drilling 

projections of 30,000 immediately (Riva, 1993). The most 

recent rig count according to PI in February 1993 has 

dropped from 926 in December 1992 to 611 rigs in the 

first quarter of 1993, which is a 34 percent decline, and 

total new well starts are down 23 percent from 917 to 704 

during the same period (PI, 1993). Drilling activity near 

the 600+ level of much of 1992 and 1993 reflects historically low drilling levels. The impact of reduced drilling 

levels, particularly in new field wildcats, is also reflected 

in the strong declines in the EIA production data as previously discussed. The termination of the section 29 qualification for tax credits at the end of 1992 evidently curtailed 

1993 drilling in spite of a gas price increase from $1.09 

per Mcf to $2.09 per Mcf from February 1992 to the February 1993 (fig. 2C). 

BETTER PROSPECTS 

The role of technology in reducing risk by locating 

better prospects for drilling is critical in exploiting natural-
DOMESTIC NATURAL-GAS RESERVES-CAN THEY BE INCREASED BY THE YEAR 2010? 537 

gas resources, particularly if resources are found at greater 

depths where higher costs and risks are encountered. Of 

particular importance are the advances made in multichannel seismic-reflection technology. Evolution of the seismicreflection method has helped extend the search for natural 

gas beyond the structural trap to the more subtle stratigraphic trap and even into the realm of direct detection. 

The increased success of recent gas exploration as measured by per well discoveries and the observed decrease of 

field growth in certain recently discovered gas fields, particularly in the Gulf Coast, may relate to the effectiveness 

of seismic technological advances. The importance of seismic advances in natural-gas exploration is underscored by 

the recent NPC (1992) study. NPC (1992, vol. 2, p. J-5 to 

J -7), in describing the bright -spot technique, states 

"the bright-spot (high seismic amplitude) technique was a revolutionary 

tool used by geophysicists, from the 1970's through the early 1980's, as 

a means to find natural gas in the subsurface. . .. this technology is now 

used in conjunction with amplitude-versus-offset (AVO) analysis, which 

offers the geophysicist more precision .... AVO analysis has played a significant part in the exploration and development of natural gas." 

In the NPC (1992) study of the role of technology to 

increase gas resources, the first item listed under existing 

technologies is 2-D and 3-D seismic processing and the 

first item listed under future technologies is advanced geophysics (NPC, 1992, vol. 2, Appendix H). 

Cost effectiveness of such seismic advances is of paramount importance. The ability to reprocess older 2-D seismic data using new techniques provides a cost effective · 

method to recycle seismic data particularly in areas where 

it may be prohibitive to collect new seismic data either 

due to surficial or environmental restrictions or prohibitive 

acquisition costs. Risk reduction in exploration for natural 

gas using the seismic method can be examined by looking 

at the progress made in three areas. These areas are multichannel seismic-data acquisition, seismic-data processing, 

and data interpretation. 

SEISMIC-DATA ACQUISITION 

The volume of recorded seismic data has increased 

dramatically beginning in the early 1970's to the present 

(Lindseth, 1990) as shown in figure 7. Introduction of digital recording onto magnetic tape along with development 

of the common depth point (CDP) acquisition method allowed this growth to occur. The use of more recording 

1 o6 J-...-4--+--+----!---+-:-----+---t-.............................. .. 3-D surveys 1-

z 105 :::J 

>- w 

> 104 

a: 

:::J 

(f) 

a: 103 

w 

a.. 

(f) 1 o2 

1-

en 

101 

1 024-channel instruments 

I---+------r--Fioajjgital r ,_~~~ ~ I I r 24-fold 

12-fold 1---+---+-'S"""ix;..;...-~fo;;....ld~digital r- i .................. .. . r T ree-tqld staqKing 

M1gnet1c

1 

tape" 1 j 

12-channelr-! 24-c ~anne I l 1---.....r::,..;::,~:..:.:..:.;~F:!::-:+i rs-t~c-o-m+-m-e_r_c+ial -:-in-s-:-tr+-u-m_e_n-:t+-s ...... :-w- __ w ........... -

r First r~flectiqn discpvery I i ll 

1 Fessenden Karcher two-channel l 

1910 1920 1930 1940 1950 1960 1970 1980 1990 2000 

YEAR 

Figure 7. Increase in recorded data volume over time as a result of advancements in seismic 

technology. From Lindseth, 1990, and courtesy of Samuel J. Allen. 
538 THE FUTURE OF ENERGY GASES 

channels results in better signal-to-noise ratios where coherent signal energy is reinforced and noncoherent noise is 

canceled during the CDP stacking process. The ultimate 

benefit is a more accurate imaging of the subsurface and 

the ability to directly observe subtle structural and stratigraphic traps. 

But not all noise is noncoherent. Some energy, such as 

ground roll and water-bottom multiple reflections, produce 

coherent noise patterns. Conventional stacking techniques 

do not eliminate this noise effectively; therefore, some 

other method must be used. For example, in the acquisition phase, the design of specific land receiver arrays can 

help eliminate ground roll and use of specially tuned marine sources can reduce the water-bottom multiple effect. 

These techniques coupled with multiple-fold recording and 

processing further enhance our ability to image the subsurface correctly. Consequently, the risk of misinterpreting 

possible natural-gas traps is reduced. 

The seismic source has evolved over time. During the 

early 1970's, dynamite was primarily used as the energy 

source for seismic data acquisition. In response to environmental concerns and the destructive nature of dynamite, 

Conoco developed the modern nondestructive vibrator 

source. In the marine environment, the complement to the 

land vibrator is the air-gun source. Modern seismic energy 

sources also allow the input signal to be controlled and 

recorded. Controlling the design of specific input signals 

produces better noise reduction and subsurface resolving 

power in specific terrain. A known source signature can be 

used in the data-processing phase to determine exactly how 

the Earth has filtered the input wavelet to produce the resultant recorded signal. From this information, one can 

begin to determine subsurface characteristics such as lithology, pore-fluid composition, and apparent porosity. 

This information along with basic knowledge of the subsurface structure helps locate possible reservoirs and determine their characteristics. 

Terrain plays an important role in data acquisition. 

Mountainous terrain and marsh-covered areas pose special 

obstacles to conventional acquisition techniques. Development of the portable shot-hole rig and recording system, 

which can be maneuvered by helicopter in mountainous 

regions, has allowed exploration of these otherwise inaccessible areas. In certain areas where dynamite sources are 

not acceptable and vibrator vehicles cannot gair. access, 

the air-blast method can be used. This method uses an explosive charge, usually primacord, planted above ground 

as the energy source. The air-blast method does not produce input signals as clean as those produced using conventional dynamite or vibrator sources, but it does allow 

acquisition to continue in otherwise environmentally sensitive areas. Shallow-water recording and the use of radio 

telemetry has provided a means to explore marshy or nearshore marine areas. This is especially important because 

many of most promising areas for natural-gas exploration 

occur in and around the shallow Gulf of Mexico and the 

marshlands of the Mississippi Delta. 

The most recent advancement in modern acquisition 

of seismic-reflection data is the development of 3-D shooting. The geometry used to record this type of data provides enough properly oriented information to produce a 

3-D image of the subsurface and helps refine the picture 

commonly produced by using grids of 2-D data. The 3-D 

method provides the data necessary to construct not only 

vertical cross section slices but also horizontal slices of 

the Earth's subsurface. A comparison of interpretations 

based on 2-D data and 3-D data (Nestvold, 1992) is shown 

in figure 8. The 3-D interpretation is superior to the 2-D in 

its ability to resolve and locate fault patterns, which in 

turn assist in determining the exact location and extent of 

A 

/ 

B 

Figure 8. Subsurface interpretation of same area using 2-D seismic data versus 3-D seismic data. A, 1974 structure map based 

on 2-D seismic data, showing fault patterns as dark lines and 

prospects as shaded areas from onshore in the Netherlands. B, 

The same area in 1990, based on 3-D seismic data. From 

Nestvold, 1992. 2 kilometers = 1.2 miles. 
DOMESTIC NATURAL-GAS RESERVES-CAN THEY BE INCREASED BY THE YEAR 2010? 539 

potential reservoirs. Detailed information from 3-D surveys can reduce the risk of missing potential natural-gas 

traps and enhance the success of step-out wells once potential natural-gas reservoirs are located. 

SEISMIC-DATA PROCESSING 

Perhaps the most important advance in seismic-data 

processing was the introduction of the high-speed digital 

computer and magnetic recording tape. The ability to manipulate large amounts of data quickly and economically 

provided the power to develop and use more sophisticated 

signal-processing algorithms. The evolution of digital 

computers from large mainframes capable of executing 

about I million instructions per second (MIP) at a cost of 

about $500,000 per MIP to today's 60 MIP desktop workstations operating at a cost of about $500 per MIP provides enough reduction in cost to use compute-intensive 

processing routines necessary to enhance seismic imaging 

of the subsurface. 

There are specific processing routines that are especially useful in locating better prospects when exploring for 

A 

natural-gas accumulations. Probably the best known is relative amplitude processing, otherwise known as bright-spot 

processing. Notable differences in speed are shown by 

seismic energy traveling through reservoir rocks containing 

natural gas in the pore space as opposed to rocks containing water or oil in the pore space, or rocks that have no 

pore space. The seismic velocity is slower in the gas reservoir because gas has a lower density than water or oil. This 

difference produces a sharp contrast in acoustic impedance 

and a resulting higher amplitude on the processed data. 

When conditions are right, these high-amplitude anomalies 

can directly indicate hydrocarbon accumulations, especially natural-gas accumulations. A 2-D seismic section, which 

has been processed conventionally, and a section processed 

using relative amplitude or the bright spot technique (GeoQuest International, 1975) are shown in figure 9. On the 

relative amplitude processed section, the gas zone produces 

a larger true amplitude reflection relative to surrounding 

nongas-bearing reflectors. This technique seems to be 

especially effective in areas of the Gulf of Mexico where 

subsurface temperatures, sand-shale lithologies, and highreservoir porosities allow the use of relative amplitude processing as a direct detection method. In some special cases 

B 

Figure 9. Two-dimensional seismic section from the Gulf of Mexico, which has been processed conventionally (A) and reprocessed 

to recover relative amplitudes (B). Note "bright-spot" amplitude anomaly at 1.4 seconds. From GeoQuest International, 1975. Data 

courtesy of Teledyne Exploration. 
540 THE FUTURE OF ENERGY GASES 

when geologic factors are appropriate, amplitude anomalies resulting from hydrocarbon accumulations can produce 

a low amplitude anomaly or a dim spot. In either case, the 

presence of several other indicators, such as a trapping 

structure, presence of a flat spot, polarity reversal or phasing of the waveshape, low-frequency shadow, velocity sag, 

amplitude shadow, or shear-wave amplitude anomaly, contribute support to a stronger case in favor of the anomaly 

being the product of a hydrocarbon accumulation (Sheriff, 

1992). 

Another recent advance in processing technology, 

which is being used as a potential direct-detection method 

comes from looking for increasing seismic-reflection amplitude as the distance from the receiver to the source increases. This technique is known as amplitude versus 

offset or AVO. The change in amplitude is controlled by 

the contrast in seismic velocity, density, and Poisson's ratio 

among gas-bearing and nongas-bearing reservoir rocks. A 

model of a seismic gather from a gas-bearing sand showing the increase in amplitude with receiver offset distance 

from the source (Hilterman, 1990) is shown in figure 10. 

Many factors influence direct hydrocarbon detection by 

AVO, however, an understanding of the geology and careful processing of the data enhances the probability of successful direct detection. 

Seismic inversion is a processing technique, which 

uses a complex mathematical process to calculate an acoustic impedance or velocity trace from a processed seismic 

800' 

Vp = 4643'/s 

p = 1.9 7 (J == .06 

Vs == 3177'/s 

trace (Sheriff, 1992). These inverted traces are known as 

seismic logs or "seislogs.'' Sections composed of these seismic log traces provide a continuous vertical and lateral picture of the subsurface velocity structure. This can be very 

useful in locating low-velocity layers, which may represent 

porous reservoirs filled with gas. A continuous seislog section produced from reflection data (Lin9seth, 1982) is 

shown in figure 11. Note the similarity between the synthetic sonic trace produced from a seismic trace to the actual 

borehole sonic log. The main difference is that the seislog 

trace is smoother than the borehole sonic log. Several zones 

of lower relative velocity are located between 1.3 and 1.4 

seconds. Closer examination of these zones using several 

other processing tools may suggest a possible hydrocarbonbearing zone. Interpretability of these seislog sections is 

enhanced by color contouring the velocity values derived 

from the inversion. 

Several processing techniques have recently been developed, which enhance the imaging power of the seismicreflection method. In areas where large subsurface dips are 

present, a processing technique called dip-moveout (DMO) 

correction can adjust for the common-depth-point smear, 

which often occurs when dipping reflections are stacked 

(Sheriff, 1992). Several DMO methods have been developed including those involving application of special migration techniques, finite difference methods, Fourier-domain 

implementation, and Kirchhoff routines. Use of DMO processing in special cases can sharpen the subsurface seismic 

Source to Receiver Offset 

7500' 

I 

<« •{)!!!!!(/((((((, ~() t) 

GAS SAND 

Vp (P-We.ve Velocity) 

Vs (S-Wave Velocity) 

p (Density) 

cr (Poisson's Ratio) 

A 

= 4643 '/sec 

= 3177 '/sec 

= 1.97 gm/cc 

= .06 

c c 

B 

~ I 

) 

( {c ({ rr ,, ,, 

tt } . ( 

Figure 10. Gas sand model (A) and corresponding synthetic amplitude-versus-offset (AVO) response (B). Note increase in 

amplitude as source to receiver distance increases. Modified from Hiltennan, 1990. 
DOMESTIC NATURAL-GAS RESERVES-CAN THEY BE INCREASED BY THE YEAR 2010? 541 

image and help locate the subtle structural or stratigraphic 

trap. Another newly developed processing technique involves the use of both DMO and Kirchhoff migration processing applied to traditional 2-D data. This technique 

produces better results in areas where dips exceed 90° and 

is especially useful in imaging underneath salt overhangs in 

the Gulf of Mexico (Ratcliff and others, 1992). In salt, the 

best imaging technique is migration of 3-D data, but when 

such data are not available, the steep-dip method is applied. 

The steep-dip method, which uses turning waves, works 

well in locating the vertical flanks of salt structures. The 

flanks of salt domes are classic exploration targets and more 

accurate knowledge of the location of the sediment/salt interface reduces the risk of missing potential hydrocarbon 

traps. 

Where 3-D data are available and processing is performed correctly, the 3-D technique provides the best image 

of the subsurface. Processed 3-D data produce traditional 

vertical slices through the Earth, the same as 2-D data, but 

in addition can show horizontal slices in time. These horizontal time slices provide better visualization of surfaces in 

map view that are especially useful in determining the 

~----- 1 mile 

0 

Q) 

(/) 1.4 

Q) 

E 

i= 

Q5 1.5 > 

ro 

... 

1-

>-

ro 

$: 1.6 I 

0 

;: 

1-

1.7 

140 90 40 1J Sec/It 

30 15 1 

.c 

+-' 

a. 

Q) 

0 

Figure 11. Continuous "seislog" section constructed from inverted seismic data showing 

correspondence between "seislog" trace, synthetic sonic log, and actual borehole sonic 

log. From Lindseth, 1982. I mile = 1.6 kilometers. 
542 THE FUTURE OF ENERGY GASES 

1000 MS. 

1500 MS. 

A ORIGINAL PROCESSING NEW PROCESSING 

Figure 12. Seismic processing techniques used in the 1960's produced the image A from seismic data acquired at that time. 

Standard processing techniques in use in the 1990's produced the image B from the same data. I kilometer = 0.6 mile. 

surface expression of complicated fault systems. Determination of fault patterns is critical not only in exploration but 

also in field development. The obvious benefits derived 

from the 3-D method make it the seismic method of choice 

in the 1990's. 

Finally, a large amount of old 2-D data that can be 

reprocessed is still available. New techniques can make 

2-D data more usable. In figure 12, the original data was 

acquired and processed in the early 1960's, before modern 

deconvolution, static corrections, filtering, and migration 

algorithms, to name just a few new techniques, where commonly used. Often the use of these new algorithms in many 

cases can justify the reprocessing of older 2-D data. Using 

reprocessed 2-D data can help reduce risk, especially where 

cost prohibits additional surveys using newer 2-D or 3-D 

methods. 

SEISMIC INTERPRETATION 

Perhaps the single most important development in interpretation of seismic-reflection data comes through the 

application of color. Color is now used as a visualization 

tool in almost all data enhancement processing. This is especially true for trace attribute processing techniques such 

as relative amplitude, instantaneous frequency, and instantaneous phase analysis. Standard use of color coding is 

also used in displaying the results of trace inversion processing and in presenting both vertically and horizontally 

sliced 3-D data. The interpretation of a portion of a salt 

dome in the Gulf of Mexico using horizontally sliced 3-D 

data (Brown, 1988) is shown in figure 13. The salt core, 

shown in blue, the structure surrounding the salt dome, 

and fault locations are easier to interpret when color is applied. A traditional seismic section enhanced by color coding of reflection amplitude strength (Lindseth, 1982) is 

shown in figure 14. Strong positive and negative amplitudes, possibly indicating hydrocarbon-bearing zones, 

stand out when color is associated with reflection strength. 

When color is applied to seislog data derived from inverted seismic data as described above, velocity changes are 

easier to visualize. An example of inverted seismic data that 

has been contoured and colorized is shown in figure 15. The 
DOMESTIC NATURAL-GAS RESERVES-CAN THEY BE INCREASED BY THE YEAR 2010? 543 

A B 

Figure 13. Color-coded horizontally sliced 3-D time data from a salt dome in the Gulf of Mexico showing the uninterpreted section (A) 

and the interpreted section (B). Application of color aids in the visualization and interpretation of the salt core shown in blue and the 

faults shown in green. From Brown, 1988. 

Figure 14. Two-dimensional seismic section with the strength of reflection amplitude color-coded to 

improve the interpretability of "bright-spots" anomalies (shown in red at roughly 0.73 seconds). 

From Lindseth, 1982. See Lindseth, 1982, for explanation of colors. 
544 THE FUTURE OF ENERGY GASES 

Figure 15. Inverted "seislog" seismic section, which has been contoured and colorized according to interval transit time (velocity). From Lindseth, 1982. I mile = 1.6 kilometers. See 

Lindseth, 1982, for explanation of colors. 

scale on the left in figure 15 indicates velocity expressed 

as travel time in microseconds per foot, a common sonic 

log unit. The blue zone represents a section of material 

that has higher seismic velocity than material that encases 

it. Inverted traces colored in orange '\nd located just above 

the blue zone have velocities ranging from 14,285 ft/sec 

(4.35 km/sec) to 13,330 ft/sec (4.06 kmlsec). The velocities 

in the blue zone range from 16,660 ft/sec (5.08 km/sec) to 

18,180 ft/sec (5.54 km/sec). Velocities colored light green 

and located just below the blue zone range from 14,200 ft/sec 

(4.32 km/sec) to 16,500 ft/sec (5.03 km/sec). The change 

from the overlying orange zone into the blue zone in figure 15 represents a transition from clastic into carbonate 

material. Application of color to these sections makes it 

easier for the eye to locate subtle lithologic changes and 

small velocity anomalies which may indicate hydrocarbon 

accumulations. This is especially true when the color 

changes indicate slower velocities indicative of natural-gas 

accumulations. 

SUMMARY 

Despite a record number of producing gas wells, several parameters point to declining natural-gas reserves: declining gas reserve to production ratios, rapidly declining 

natural-gas reserves (EIA, 1992b, 1993; Riva, 1993), significant recent downturns in drilling (PI, 1993), increasingly rapid depletion of young natural gas fields (Butler and 

Stark, 1993), significant natural-gas price instability (Parent, 1993), anticipated sharp declines in excess productive 

capacity (Butler and Stark, 1993; EIA, 1993) and the termination of FERC section 29 tax incentives. These trends 

suggest an immediate need for increased drilling of highquality prospects for conventional gas resources if further 

erosion of the natural-gas reserve base is to be prevented. 

Conventional gas resources will play the dominant source 

through the year 2010 according to several studies. Some 

argue (Woods, oral commun., 1993) that these additional 

conventional resources will come from lightly explored 

deep basin resources. The need to adequately define such 

deep resources will require sophisticated exploration tools, 

particularly the most advanced seismic techniques. Alternatively, either increased imports of natural gas or the increased use of coal or perhaps natural gas derived from 

new coal gasification techniques may play an increased 

role. This seems plausible in light of the increasing use of 

coal shown in figure 1. The decline of the petroleum infrastructure to historic lows affects not only the ability of the 

nation to rapidly increase drilling, but also our ability to 

define prospects, principally seismically, because the number of seismic crews are at historic lows also. There are 

undoubtedly large natural-gas resources to develop; however, the hope for increased natural-gas usage may be 

thwarted in the final analysis by the petroleum industry's 

collapse commencing in 1982, exacerbated in 1986 and 

continuing to present. The wish to increase domestic natural-gas usage conflicts with the concurrent need to increase 
DOMESTIC NATURAL-GAS RESERVES-CAN THEY BE INCREASED BY THE YEAR 2010? 545 

domestic drilling significantly, particularly on Federal 

lands. Environmental advocates of increased natural-gas 

use, which will require significant drilling particularly on 

Federal lands, will confront other environmental groups 

opposed to increased drilling on public lands and work to 

slow the process of bringing these resources to the Nation. 

The battle, if not at hand, is near. 

REFERENCES CITED 

American Petroleum Institute, 1992, Basic petroleum data book: 

Washington, D.C., American Petroleum Institute, v. 12, no. 3. 

Brown, Alistair, R., 1988, Interpretation of Three-Dimensional 

Seismic Data, 2d ed.: American Association of Petroleum 

Geologists Memoir 42, 253 p. 

Butler, J.R., Jr., and Stark, P.H., 1993, U.S. gas: Where's the supply corning from?: World Oil, v. 214, no. 2, p. 39-44. 

Coal Data, 1991: Published by the National Coal Association, 

1130 Seventeenth Street, N.W., Washington, D.C., 94 p. 

Dolton, G.L., Mast, R.F., and Crovelli, R.A., 1990, Estimates of 

undiscovered conventional resources of oil and gas for federal lands, and for Indian and Native lands of the continental 

United States: U.S. Geological Survey Open-File Report 90-

705, 64 p., 2 plates. 

Drew, L.J., 1990, Oil and gas forecasting-Reflections of apetroleum geologist: International Association for Mathematical Geology, Studies in Mathematical Geology No. 2, New 

York, Oxford University Press, 252 p. 

Drew, L.J., and Schuenerneyer, J .H., 1993, The evolution and use 

of discovery process models at the U.S. Geological Survey: 

American Association of Petroleum Geologists Bulletin, 

v. 77, no. 3,p.467-478. 

Energy Information Administration, 1990a, The domestic oil and 

gas recoverable resource base-Supporting analysis for the 

national energy strategy: DOE!EIA SR/NES/90-05, 56 p. 

[Available from National Energy Information Center, EI231, Energy Information Administration, Forrestal Building 

I F-048, Washington, D.C. 20585.] 

---1990b, U.S. Oil and gas reserves by year of field discovery: 

Washington, D.C., DOE!EIA-0534. [Available from National 

Energy Information Center, EI-231, Energy Information Administration, Forrestal Building lF-048, Washington, D.C. 

20585.] 

---1992a, U.S. crude oil, natural gas and natural gas liquids 

reserves, 1991 Annual Report: Washington, D.C., Energy Information Administration DOE/EIA-0216(91), Nov. 1992, 

129 p. [Available from National Energy Information center, 

EI-231, Energy Information Administration, Forrestal Building lF-048, Washington, D.C. 20585.] 

---1992b, Annual Energy Review 1991, Washington, D.C., 

Energy Information Administration DOE/EIA-0384(91), 

347 p. [Available from National Energy Information Center, 

EI-231, Energy Information Administration, Forrestal Building lF-048, Washington, D.C. 20585.] 

---1993, Short term energy outlook, quarterly projections-

! st quarter: Washington, D.C., Energy Information Administration, DOE/EIA-0202(93/lQ), 30 p. [Available from 

National Energy Information Center, EI-231, Energy Information Administration, Forrestal Building lF-048, Washington, 

D.C. 20585.] 

Exploration Insight, 1992, NRG Associates: Nov. 1992, v. 90--

Review: 20 p. [Available from Nehring Associates, Inc., P.O. 

Box 1655, Colorado Springs, Colorado 80901.] 

Fisher, W.L., Finley, R.J., Sene, S.J., Ruppel, S.C., White, G.W., 

Ayers, W.B., Jr., and Dutton, S.P., 1988, An assessment of 

the natural-gas resource base of the United States: Austin, 

Texas, Bureau of Economic Geology, p. 1-77. 

GeoQuest International, Ltd., 1975, Amplitude and waveforms in 

seismic interpretation: GeoQuest International Ltd. Seismic 

Interpretation Course Notes, 187 p. 

Gluskoter, H.J., 1991, Coal-A brief overview, in Gluskoter, 

H.J., Rice, D.O., and Taylor, R.B., eds., Economic Geology, 

U.S.: Geological Society of America, v. P-2, p. 463-467. 

Hilterman, F., 1990, Is AVO the seismic signature of lithology?-

A case history of ship shoal-south addition: Society of Exploration Geophysicists Leading Edge, v. 9, no. 6, p. 15-22. 

Holtberg, P.O., Woods, T.J., Lihn, M.L., and Koklauner, A.G., 

1993, Baseline projection data book-GRI baseline projection of U.S. energy demand to 2010, 1993 edition: Washington, D.C., Gas Research Institute, Strategic Planning and 

Analysis Division, 588 p. 

Hubbert, M.K., 1974, U.S. energy resources, a review as of 

1972, pt. 1, in A national fuels and energy policy study: 

U.S. 93rd Congress, 2d Session, Senate Committee on Interior and Insular Affairs, Committee Print, Serial no. 9340 

(92-75), 267 p. 

Lindseth, Roy 0., 1982, Digital processing of geophysical dataA review: Society of Exploration Geophysicists Continuing 

Education Program Notes, 320 p. 

---1990, The next wave of exploration: Society of Exploration Geophysicists Leading Edge, v. 9, no. 12, p. 9-15. 

Marsh, R.G ., 1971, How much oil are we really finding?: Oil and 

Gas Journal, v. 69, p. 100-104. 

Ma~t. R.F., and Dingler, J., 1975, Estimates of inferred and indicated reserves for the United States by State, in Miller, 

B.M., Thomsen, H.L., Dolton, G.L., Coury, A.B., Hendricks, 

T.A., Lennartz, F.E., Powers, R.B., Sable, E.G., and Varnes, 

K.L., eds., Geological Estimates of Undiscovered Oil and 

Gas Resources in the United States: U.S. Geological Survey 

Circular 725, 78 p. 

Mast, R.F., Dolton, G.L., Crovelli, R.A., Root, D.H., Attanasi, 

E.D., Martin, P.E., Cooke, L.W., Carpenter, C.B., Pecora, 

W.C., and Rose, M.B., 1989, Estimates of undiscovered conventional oil and gas resources in the United States-A part 

of the Nation's energy endowment, Department of Interior: 

U.S. Geological Survey and Minerals Management Service 

Special Publication, 44 p. 

Natural Gas Supply Association, 1992, Natural gas field deliveries and productive capacity as of January 1, 1992, Sept. 

1992. [Available from Natural Gas Supply Association, I I 29 

Twentieth Street, N.W., Suite 300, Washington, D.C. 20036.] 

Nestvold, E.O., 1992, 3-D seismic-Is the promise fulfilled?: Society of Exploration Geophysicists Leading Edge, v. 11, 

no. 6, p. 12-19. 

National Petroleum Council, 1992, The potential for natural gas 

in the United States: National Petroleum Council, 1625 K 

Street N.W., Washington, D.C., v. I-VI, 2, 102 p. 
546 THE FUTURE OF ENERGY GASES 

NRG Associates, Inc., 1992, The significant oil and gas fields of 

the United States (through December 31, 1991). [Available 

from Nehring Associates, Inc., P.O. Box !655, Colorado 

Springs, Colorado 80901.] 

Parent, L. V., 1993, U.S. gas outlook-Stability eludes industry: 

World Oil, v. 214, no. 2, p. 35-38. 

Petroleum Information Corporation, 1993, Statistical services division, executive summary, March 1993, Denver, CO, 20 p. 

[Available from Petroleum Information Corporation, 4100 

East Dry Creek Road, Littleton, CO 80122.] 

Potential Gas Committee, 1992, Potential supply of natural gas in 

the United States (as of December 31, 1992): Golden, Colorado, Potential Gas Agency, Colorado School of Mines, 168 p. 

Ratcliff, D.W., Gray, G.H., and Whitmore, N.D., Jr., 1992, Seismic 

imaging of salt structures in the Gulf of Mexico: Society of Exploration Geophysicists Leading Edge, v. 11, no. 4, p. 15-31. 

Riva, J.P., Jr., 1993, Domestic natural gas-Part of the solution 

or part of the problem?: Congressional Research Service 

93-150 SPR. [Available from the Congressional Research 

Service, Library of Congress, Science Policy Research Division, Washington, D.C. 20540.] 

Root, D.H., 1982, Historical growth estimates of oil and gas field 

sizes in Oil and gas supply modeling: National Bureau of 

Standards Special Publication 631, p. 350-368. 

Root, D.H., and Mast, R.F., 1993, Future growth of known oil 

and gas fields: American Association of Petroleum Geologists Bulletin, v. 77, p. 479-484. 

Sheriff, R.E., 1992, Encyclopedic Dictionary of Exploration Geophysics 3d ed., Society of Exploration Geophysicists Geophysical References No. I, 323 p. 

Woods, T.J., 1992, Near-term, lower-48 gas deliverability-Implications of gas drilling activity and gas reserves: Washington, D.C., Gas Research Institute, October, 1992, 10 p. 

[Available from Gas Research Institute Strategic Planning 

and Analysis Division, 1331 Pennsylvania Ave., N.W., Suite 

730 N., Washington, D.C. 20004-1703.] 

Woods, T.J., 1993, The long-term trends in U.S. gas supply and 

prices: 1993 edition of the GRI baseline projection of U.S. 

energy supply and demand to 2010: Chicago, Illinois, Gas 

Research Institute, 92 p. 

World Oil, 1993, Producing oil well numbers head down again: 

February, 1993, p. 70. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

A Primer In Field-Growth Estimation 

By David H. Root1 and Emil D. Attanasi 1 

CONTENTS 

Abstract ......................................................................... 547 

Introduction ................................................................... 547 

Modeling Field Growth ....... .. . .. ..... .. ... .. . .. ... ... ... .. . . . ....... 548 

Growth Factors and Functions .............................. 548 

Methods of Projecting Field Growth . .. .... ... .. . .. ... . . . 549 

Field Growth Outside of North America ..................... 550 

Data and Evidence on Nonassociated 

Gas Field Growth ................................................... 550 

Example Analysis of Nonassociated Gas Field 

Growth ................................................................... 551 

Implications of Field-Growth Analysis ........................ 553 

References Cited ........................................................... 554 

ABSTRACT 

Field growth refers to the phenomenon of increasing 

estimates of ultimately recoverable oil and gas that occur 

as oil and gas fields are developed. From 1978 to 1990, 

growth of known fields in the United States has accounted 

for 90 percent of the annual additions to proved reserves. 

Now that field growth is recognized as a significant source 

of additions to proved reserves, field-growth prediction 

models are being made more sophisticated so that the timing of these reserve additions can be forecast. 

This paper surveys the literature on field growth and 

methods of field-growth estimation. It also examines data 

on nonassociated gas fields of South America, Western 

1

U.S. Geological Survey National Center, 12201 Sunrise Valley Dr., 

MS 920, Reston, VA 22092-0001. 

Europe, the Middle East, Africa, non-Communist Far 

East, and the southwestern Pacific to demonstrate evidence of field growth. Field growth patterns are influenced by market conditions for the resource as well as 

physical characteristics. These data are also then used in 

an example that demonstrates field-growth analysis. Although international gas fields show clear evidence of 

field growth, the data are not yet sufficient for estimating 

reliable growth functions. 

INTRODUCTION 

Field growth refers to the phenomenon of increasing 

estimates of ultimately recoverable oil and gas, which 

occur as fields are developed and produced. A field is defined by the U.S. Department of Energy (Energy Information Administration, 1990a) as an area consisting of single 

reservoir or multiple reservoirs all grouped on, or related 

to, the same individual geologic structural feature and (or) 

stratigraphic condition. Two or more reservoirs assigned to 

the same field may be separated vertically by impervious 

strata or laterally by geologic barriers. 

Typically, initial estimates of field recovery are only 

detailed enough to establish whether the field can be commercially developed. As fields are developed, wells may 

be drilled to extend the surface limits of the field and to 

find new pay zones. Even if no additional wells are drilled 

to extend field limits or find new reservoirs, the initial estimates of ultimate field recovery may be revised to reflect 

operation experience, newly installed water flood, gas reinjection, or recompletions of existing development wells 

to produce from other pay zones. The ultimate field size 

refers to the sum of current field reserves and cumulative 

past production. Generally, the number of years since the 

discovery of a field or age of the field is used as a proxy 

variable for the degree of field development. 

547 
548 THE FUTURE OF ENERGY GASES 

Early efforts to estimate field growth focused on 

determining sizes of recent discoveries to evaluate the 

effectiveness of ongoing exploration. Moreover, in the 

United States, field growth provides 90 percent of the 

total annual additions to proved reserves. Now that field 

growth is recognized as a significant source of additions 

to proved reserves, models for predicting field growth are 

also being made more sophisticated so that the timing of 

the related additions to proved reserves may be forecast. 

Since 1950, the United States and Canada have accounted for more than 90 percent of the world's cumulative 

exploratory and development drilling. They are the most 

intensively explored and developed of the major oil-producing countries. Because of this drilling, the phenomenon 

and importance of field growth was recognized earlier in 

these countries than elsewhere. Although international oil 

and gas data show clear evidence of field growth, the gas 

data are not yet sufficient for estimating reliable growth 

functions. 

MODELING FIELD GROWTH 

GROWTH FACTORS AND FUNCTIONS 

Even in intensively drilled areas of the United States 

and Canada, there are few fields for which annual estimates 

of ultimate recovery from the year of discovery to the year 

of abandonment are publicly available. Generally, data used 

in the modeling of field growth consist of short time-series 

34 

32 

30 

28 

UJ 26 ,_ 

~ 24 

Iii 22 UJ 

__J 20 

~ 

.... 18 

z 16 

LL 

0 14 

UJ 

__J 12 

': 

,_ 10 __J 

::> 8 ::!: 

6 

4 

2 

0 

(6 to 14 years) of estimates of fields grouped by discovery 

year. For example, with such a series the expected field 

growth for a field going from age 19 to age 20 is computed 

using estimates of ultimate recovery for all those fields that 

went from age 19 to 20 during the sample period. An entirely different set of fields may be used in calculating expected field growth from age 4 to age 5. The U.S. data 

series used most frequently in early field growth studies 

was published by the American Petroleum Institute (API) 

and American Gas Association (AGA) (American Petroleum Institute, American Gas Association, and Canadian 

Petroleum Association, 1967-1980) and covers the period 

from 1966 through 1979. A later data series, by the Energy 

Information Administration, covers from I 977 to 1988 (Energy Information Administration, 1990a). Since 1985, NRG 

Associates of Colorado Springs has published a data series 

of estimates of ultimate field sizes. 

Over the years, researchers have attempted to characterize the systematic nature of field growth. Because of the 

nature of available data, techniques have usually been statistical. Efforts to characterize field growth have centered on 

the estimation of growth factors. These factors can be presented in several different ways. For example, the factors 

can be given as the ratio of the size of a field K years after 

discovery to the size of the field as estimated in its year of 

discovery. We call these the "cumulative-growth factors." 

When the cumulative-growth factors can be calculated 

or presented in a functional form, the function is sometimes called a "growth function." Examples of growth 

functions are shown in figure I. Curves in the figure show 

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 

0 ARRINGTON 

YEARS S I NCE 0 I SOOVEAY 

---- LEAST SQUARES 0 MONOTONE 

Figure 1. Three separate growth functions, described in text, showing current 

field size as a multiple of initial estimated field size in year of discovery. Data 

used was for productive nonassociated gas fields in South America, Western 

Europe, the Middle East, Africa, non-Communist Asia, and the southwestern 

Pacific. Data from Petroconsultants, SA, 1985-1992. 
A PRIMER IN FffiLD-GROWTH ESTIMATION 549 

the current estimated field size as a multiple of its initial 

estimated field size. The factors can also be given as the 

ratio of the size in year K + 1 to the size in year K after 

discovery. We call these the "annual-growth factors." The 

cumulative-growth factors can be calculated from the 

annual-growth factors and vice versa. As the age of fields 

increase without limit one would expect the annualgrowth factors to approach 1 and the cumulative-growth 

factors to approach an asymptote. 

Given the cumulative-growth function, G(n), it is theoretically possible to calculate from the estimate made in 

year e what the estimate made in year e+k will be using 

equation 1: 

c(d,e+k)==c(d,e)xG(e+k-d)/G(e-d) (I) 

where k is the time elapsed between an early estimate 

year, e, and late estimate year, e+k, c(d,e) is the amount of 

oil or gas discovered in year d as estimated in year e, and 

c is the projected estimate. 

METHODS OF PROJECTING FIELD GROWTH 

The principles of field growth were developed for recoverable oil and were later applied to gas. Arrington 

(1960) wanted to evaluate the returns to recent exploration 

for the Carter Oil Company and needed factors to correct 

for the initial underestimation of sizes of new fields. He 

estimated the annual growth of a field between the eth and 

e+ 1st year after discovery to be 

}: c ( d,e + 1) 

d 

}: c (d,e) 

d 

where c(d, e), d, and e have the same meaning as in equation 1. In the formula above, the same fields appear in the 

numerator and in the denominator. The only difference is 

that in the numerator the size estimates were made when 

the fields were 1 year older. The underlying assumptions 

are that the amount of growth in any one year is proportional to the size of the field and that this proportionality 

constant changes as the field ages. 

Arrington's measure of the degree of development was 

the age of the field in years from the date of discovery. This 

measure is readily available and represents the simplest 

index of all the various types of development that a field 

can undergo. Arrington did not assume a functional form 

relating the annual growth factors to the age of the field. 

Marsh (1971) applied Arrington's method to the API 

and AGA series of estimated recoverable oil and gas by 

year of discovery. The published estimates were as of 

year end 1966, 1967, 1968, and 1969. Marsh was the first 

to estimate gas-field growth and according to his results 

oil fields grew more than gas fields. Marsh's estimates of 

oil and gas-field growth from pre-1970 discoveries are 

shown in table 1. 

Hubbert (1967, 1974) like Arrington was interested 

in assessing the size of recent discoveries. His method 

differed from Arrington's method in that Hubbert assumed a functional form for the cumulative-growth factors and estimated them directly from the API and AGA 

data. Hubbert (1974) assumed that the unproved recoverable oil and gas in a field decayed exponentially with 

time. His estimates of future oil and gas growth for pre1972 discoveries are shown in table 1. Hubbert's growth 

factors were later used by Mast and Dingler in 1975 to 

estimate indicated and inferred reserves (field growth) for 

pre-1973 discoveries (see table 1) and were published in 

the first U.S. Geological Survey national oil and gas 

assessment. 

Pelto (1973) assumed that growth proceeded in a regular way; namely, that each year a fixed fraction of the 

unproved recoverable oil in a field was credited to proved 

reserves-an assumption equivalent to Hubbert's. He used 

the API series of recoverable oil by year of discovery. 

Using a least-squares procedure he estimated the fully 

grown ultimate recovery from each discovery year and the 

fixed fraction. His estimate of the fixed fraction was 

0.1175, and so 11.75 percent of the unproved oil was 

added to proved reserves each year. A peculiarity of 

Pelto's results is that approximately two-thirds of the 

growth is in 1968 discoveries (the discovery year of the 

giant Prudhoe Bay oil field). His estimate of growth from 

pre-1971 discoveries is shown in table 1. 

The U.S. Geological Survey (Root, 1981) estimated 

future growth by applying the Arrington' method to the 

API and AGA data. More recently, the U.S. Geological 

Survey and Minerals Management Service published a revised set of estimates of inferred reserves for oil and gas 

fields discovered prior to 1987 (U.S. Department of the 

Interior, 1989). Because API and AGA annual series 

ceased publication with the 1979 edition, the data used for 

estimating growth of pre-1987 fields did not reflect the 

significant expansion of the oil and gas industry activity in 

the early 1980's during periods of high prices. Both estimates are shown in table 1. 

As part of the national energy strategy, Energy Information Administration ( l990b) projected expected future 

growth of pre-1988 discoveries (see table 1) using data 

from the oil and gas integrated field file (OGIFF). The oil 

and gas growth functions that were fitted to these data implied that fields would continue to grow for I 00 years 

after discovery because there are 1 00-year-old fields still 

growing. The National Petroleum Council also used the 

OGIFF data base along with the AGA series to estimate a 

functional form that included field age and the number of 

gas wells drilled since discovery. 
550 THE FUTURE OF ENERGY GASES 

Table 1. Estimates of expected oil and gas reserve growth in the lower 48 States, except 

as noted 

[BBO, billion barrels of oil; Tcf, trillion cubic feet; N/A, data not available] 

Growth 

Age and type of field 

Total Projected 

Pre-1970 fields-oil------ 9.6 BBO 

Pre-970 fields-gas------- 70.0 Tcf 

Pre-1971 fields-oil 31.5 BBO 

(including Alaska). 

Pre-1972 fields-oil------ 20.0 BBO 

Pre-1972 fields-gas ----- 165.0 Tcf 

Pre-1973 fields-oil------ 17.6 BBO 

Pre-1973 fields-gas----- !66.0 Tcf 

Pre-1979 fields-oil------ 22.8 BBO 

Pre-1979 fields-gas ----- !31.7 Tcf 

Pre-1987 fields-gas ----- 154.3 Tcf 

Pre-1987 fields-oil------ 15.3 BBO 

Pre-1987 fields-gas ----- 95.8 Tcf 

Pre-1988 fields-oil------ 51.0 BBO 

Pre-1988 fields-gas----- 265.0 Tcf 

Pre-1989 fields-gas----- 380.0 Tcf 

Pre-1990 fields-gas----- 203.0 Tcf 

Both the Potential Gas Committee and the Texas Bureau of Economic Geology estimated field growth using 

nonstatistical methods (see table 1). The Potential· Gas 

Committee's definition of probable reserves in known fields 

roughly corresponds to the increment in current provedreserves expected to be added to field size when a field is 

fully grown. The Potential Gas Committee used the same 

geologic methqds applied in the appraisal of undiscovered 

gas resources to .estimate probable reserves , in Jdentified 

fields (Pote_ntiaf d11s Co11_1mittee, 1987). The Te~#f:Burea.u 

of Economic Geology (Fisher, 1991) used a geolqgfc engineering approach to calculate the amount of gas fn compartments of reservoirs not in contact with a well bore. 

Studies based on the Texas experience were extrapolated to 

the national level. 

The many estimates of projected growth for the above 

methods of calculation are summarized in table 1. For the 

older estimates, actual growth through 1990 is also shown. 

Of the nine estimates shown in the table, the earliest four 

for both oil and gas have already been exceeded. Even 

within intensively drilled areas of the United States, field 

growth is regularly underestimated. 

Actual 1990 

29.9 BBO 

166.4 Tcf 

34.1 BBO 

28.1 BBO 

171.5 Tcf 

27.2 BBO 

171.5 Tcf 

20.7 BBO 

187.0 Tcf 

63.8 Tcf 

5.3 BBO 

63.8 Tcf 

N/A 

N/A 

N/A 

N/A 

Source of data 

Marsh (1971) 

Marsh (1971) 

Pelto (1973) 

Hubbert (1974) 

Hubbert (1974) 

Mast and Dingler (1975) 

Mast and Dingler (1975) 

Root (1981) 

Root (1981) 

Potential Gas Committee (1987) 

U.S. Department of Interior (1989) 

U.S. Department of Interior (1989) 

Energy Information Administration 

(1990) 

Energy Information Administration 

(1990) 

Fisher (1991) 

National Petroleum Council (1992) 

FIELD GROWTH OUTSIDE OF 

NORTH AMERICA 

DATA AND EVIDENCE ON NON ASSOCIATED GAS 

FIELD GROWTH 

The principal source of international oil and gas data 

is the field data base compiled by Petroconsultants, SA. 

This data, base covers all countries outside of the United l '· States anq Canada. Petroconsultants updates the field files 

quarterly. The field data contains estimates of ultimate oil 

and gas recovery, cumulative and annual production, and 

a number' of geologic and geographic characteristics on 

each field. 

One source of nonuniformity in the data is that there is 

no international standard definition of reserves. Generally, 

international field-reserve estimates are not tied to installed 

production facilities. Internationally there are fields with 

large reserves that have no installed production capacity. 

This is in contrast to the U.S. definition of proved reserves 

where reserves are computed on the basis of installed production capacity. 
A PRIMER IN FIELD-GROWTH ESTIMATION 551 

Another source of nonuniformity in the field-reserve 

data is unwillingness of the national companies or their 

governments to release information. For example, while the 

Petroconsultants' data base includes many fields in the 

former Soviet Union and Eastern Europe, most reserve estimates and field-production data were not available for these 

areas. Because there is not yet a long enough series of 

reliable data from these areas to show a pattern of field 

growth, the former Soviet Union and Eastern Europe were 

not included in this analysis. China was not included because there was little gas production. 

For our purposes, the study area is South America, 

Western Europe, the Middle East, Africa, South Asia, and 

Southwestern Pacific. As of the end of 1992, the ultimate 

recovery from known fields in the study area was reported 

to be 2,901 trillion cubic feet (Tcf) of gas and 1,001 billion 

barrels of oil (Bbo). 

Using a rule that a nonassociated gas field has a gas to 

oil ratio of at least 20 thousand cubic feet per barrel 

(Mcf/bbl), the 2,901 Tcf is classified into 1,049 Tcf of associated gas and 1 ,852 Tcf nonassociated gas. Some of the oil 

and gas fields have never produced. Of the 1,001 Bbo in the 

study area, 860 Bbo (86 percent) are in fields that have had 

some production. About 55 percent of the nonassociated 

gas is in gas fields that have never produced. 

Because information on fields that have never been 

produced is inevitably sketchy, the analysis was restricted 

to fields that have had some production. Figure 2 shows 

cumulative pre-1986 discoveries of produced nonassociated gas fields estimated in 1985, 1988, and 1992. The 1992 

" t- 600 w 

w 

u.. 

'::' 

CD 500 :::> 

u 

u.. 

0 

UJ 

z 4 00 

" __J 

__J 

a 

t- 300 u 

UJ 

0 " 

w 200 :;: 

t-

" __J 

:::> 

" 100 :::> 

u 

1901 1911 1921 19 31 

estimate of these fields is more than 150 Tcf greater than 

the 1985 estimate. A series of estimates of the amount of 

gas in gas fields that have had some production of oil or 

gas is shown in table 2 by year of discovery. For most 

discovery years, the estimate made in 1985 of ultimate recovery is less than the estimate made in 1992. 

EXAMPLE ANALYSIS OF NONASSOCIATED 

GAS FIELD GROWTH 

A growth function permits the calculation of later estimates of a field's size from earlier estimates. A measure of 

the accuracy of forecast of later estimates from the application of the growth function to earlier estimates is defined in equation 2. Among all possible growth functions, 

G(n), the one minimizing the error shown in equation 2 is 

called the least-squares growth function and is shown in 

figure 1. 

ERR(d,e,k)=( c ( d,e+k)-c( d,e+k) )

2 

SSE = ~ ERR ( d,e,k) 

d,e,k 

(2) 

where ERR(d, e, k) is the error function for a single-forecast estimate and SSE is the sum of all errors and the 

other symbols are defined as in equation 1. The leastsquares growth function in figure 1 was calculated for 

nonassociated gas in fields in the study area that have had 

some production. The calculations were only extended as 

1941 1951 1961 1 97 1 1 98 1 

YEAR OF 0 I SCOVERY 

0 1985 ESTI MATE o 1988 EST I MATE - 1992 EST IMATE 

Figure 2. Cumulative amounts of discovered gas reserves of productive nonassociated gas fields discovered before 1986 in South America, Western Europe, the 

Middle East, Africa, non-Communist Asia, and the southwestern Pacific, as recorded by Petroconsultants, SA, in 1985, 1988, and 1992. North field in Qatar, 

Persian Gulf, has been omitted because early estimates were reduced by 150 trillion cubic feet. 
552 THE FUTURE OF ENERGY GASES 

Table 2. Recoverable gas in nonassociated gas fields in South America, Western Europe, the Middle East, South Asia, and 

Southwestern Pacific that have had some production. 

[units, billion cubic feet. North Field of Qatar in Saudi Arabia not included] 

Discovery 

year 

Pre-1950 

1950 

1951 

1952 

1953 

1954 

1955 

1956 

1957 

1958 

1959 

1960 

1961 

1962 

1963 

1964 

1965 

1966 

1967 

1968 

1969 

1970 

1971 

1972 

1973 

1974 

1975 

1976 

1977 

1978 

1979 

1980 

1981 

1982 

1983 

1984 

1985 

1986 

1987 

1988 

1989 

1990 

1991 

1992 

1985 

34,917 

863 

9,822 

10,555 

1,196 

506 

2,455 

1,515 

74,180 

862 

100,433 

12,377 

4,272 

15,876 

7,156 

3,289 

12,251 

26,149 

3,706 

27,255 

15,152 

7,651 

31,967 

11,324 

12,067 

18,561 

2,947 

3,636 

17,910 

2,265 

1,293 

8,836 

1,814 

5,822 

4,867 

6,510 

625 

1986 

35,082 

863 

9,822 

10,495 

1,196 

506 

2,455 

1,515 

74,180 

862 

100,433 

12374 

4,273 

15,926 

7,156 

3,326 

12,353 

25,342 

3,590 

27,396 

15,224 

6,762 

31,862 

10,851 

12,287 

19,156 

2,952 

3,611 

27,665 

2,245 

1,076 

9,450 

1,811 

5,881 

4,904 

6,544 

1,377 

120 

1987 

35,215 

855 

9,396 

10,614 

1,036 

520 

2,374 

1,596 

74,159 

872 

94,273 

12,588 

5,103 

15,692 

7,711 

4,081 

13,215 

25,019 

3,820 

27,134 

13,944 

6,520 

31,922 

12,306 

12.433 

19,957 

3,178 

3,636 

33,682 

2,176 

1,131 

9,269 

2,147 

5,918 

4,708 

7,196 

1,508 

848 

53 

Year of estimate 

198S 

48,314 

754 

10,539 

10,714 

1,046 

412 

2,708 

2,086 

94,655 

865 

94,373 

17,061 

6,750 

17,550 

9,341 

4,322 

11,829 

26,154 

4,868 

27,328 

15,094 

6,905 

35,553 

13,864 

11,834 

20,067 

3,245 

3,189 

33,973 

3,591 

1,262 

9,246 

2,378 

24,899 

9,482 

8,070 

2,692. 

1,087 

2,419 

7 

1989 

50,501 

759 

10,624 

10,726 

1,055 

550 

2,762 

2,182 

94,689 

1,024 

95,431 

17,121 

6,957 

18,114 

9,406 

4,465 

11,903 

25,952 

6,641 

28,491 

13,216 

7,397 

35,758 

14,376 

12,248 

21,438 

3,505 

3,466 

33,915 

4,386 

1,618 

8,984 

2,271 

25,436 

3,836 

4,223 

3,510 

1,491 

5,623 

586 

75 

1990 

51,767 

760 

12,235 

10,816 

1,056 

549 

2,828 

2,192 

94,712 

1,025 

104,464 

17,142 

7,507 

18,330 

10,085 

4,310 

11,267 

26,208 

7,833 

29,546 

14,488 

8,118 

37,726 

14,606 

12,057 

21,437 

3,445 

3,287 

34,819 

4,335 

1,548 

8,983 

2,375 

25,545 

3,674 

4,352 

3,969 

1,401 

5,030 

556 

181 

30 

1991 

52,110 

595 

12,235 

10,872 

1,116 

551 

2,558 

2,164 

110,133 

1,059 

103,108 

17,204 

7,147 

24,545 

10,337 

4,320 

12,000 

32,816 

7,898 

29,796 

14,427 

8,127 

45,500 

14,723 

14,827 

23,531 

3,481 

3,281 

34,864 

4,375 

1,563 

10,159 

1,902 

9,097 

3,541 

4.239 

3,899 

1,403 

5,294 

746 

151 

335 

1992 

59.673 

595 

11,460 

10,872 

1,115 

546 

2,557 

2,163 

112,399 

1,073 

103,037 

16,425 

7,661 

24,531 

10,472 

4,375 

11,982 

27,266 

7,903 

33,109 

14,498 

8,139 

47,586 

13,717 

14,897 

24,407 

3,322 

3,358 

37,041 

3,992 

1,390 

8,116 

2,357 

9,868 

3,968 

4,290 

3,469 

1,966 

5,767 

935 

121 

335 

250 

0 
A PRIMER IN FIELD-GROWTH ESTIMATION 553 

far as 36 years because of the brief history of gas production in the study area. 

The irregularity of the least-squares growth curve (figs. 

I, 3) results from market fluctuations that affect field development as well as the physical characteristics of the fields. 

If it is assumed that, other things being equal, older fields 

will have a smaller percentage growth than younger fields, 

this assumption is expressed analytically in equation 3. 

G(n + 1) 

G(n) 

G(n) s----

G(n - 1) 

(3) 

The monotone growth function is defined here as the 

growth function that satisfies the monotone restriction of 

equation 3 and minimizes the error function in equation 2 

and is shown in figure 1. The growth curve calculated by 

the Arrington method described above is also shown in 

figure 1. 

All curves in figure 1 show the current estimated size 

of a field as a multiple of its initial estimated size. As an 

alternative to figure 1, the estimated size of the field at age 

36 (the limit of our data) could be shown as a multiple of 

the current estimated size (fig. 3). The reason for doing 

this is that growth curves that look very different in figure 

I sometimes follow similar growth patterns after the first 

few years. This is the case for the monotone and Arrington 

curves after 15 years, as shown in figure 3. 

For example, the expected growth 36 years into the 

future (to the year 2028) of nonassociated gas in producf- 4 Ul 

UJ 

\i 

UJ 

a 

a 2 3 

>-

CD 

0 

UJ 

0 

> 2 0 

UJ 

N 

Ul 

UJ 

f-

... 1 ::; 

1-

_J 

:J 

tive fields in the study area was calculated from the three 

growth curves of figure 1. The calculated growth for the 

Arrington function is 240 Tcf, for the least squares it is 

190 Tcf, and for the monotone it is 251 Tcf. These 

amounts are not representative of the total world _growth 

or even total study area growth for the next 36 years because the calculations were based on about 10 percent of 

the world's reported gas and less than 25 percent of the 

gas in the study area. The industry is still too immature to 

have generated data necessary to support a reliable 

growth-factor calculation. 

IMPLICATIONS OF FIELD-GROWTH 

ANALYSIS 

Estimated field reserves are typically limited to recoverable quantities of oil and gas in known reservoirs, which 

can be produced with some degree of confidence. Ultimate 

field-size estimates, on average, increase as fields are developed because field-development activities frequently 

extend the limits of the known reservoirs, find new reservoirs, or may improve recovery of the in-situ hydrocarbon 

resource. In the United States, estimated field reserves 

may represent only one-third of the remaining oil and gas 

in known fields. 

In recent years, growth of known fields in the United 

States has been the dominant source of annual additions to 

proved reserves. The same growth phenomenon is demonstrated in producing fields outside the United States and 

0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 

0 ARRINGTON 

YEARS SINCE DISCOVERY 

+ LEAST SQUARES -- MONOTONE 

Figure 3. Three separate functions, as discussed in text, showing estimated fully 

grown ultimate field size as a multiple of current field size. Data for producing 

nonassociated gas fields in South America, Western Europe, the Middle East, Africa, non-Communist Asia, and the southwestern Pacific. Data from Petroconsultants, SA, 1985-1992. 
554 THE FUTURE OF ENERGY GASES 

Canada. The infancy of the industry in many foreign countries, however, precludes a comprehensive forecast of expected additions to reserves from growth in known fields 

in these areas. For new discoveries outside of the United 

States and Canada, field production can be delayed for 

years or even decades by lack of infrastructure to produce 

and transport the product to markets. In such cases, the 

initial field size estimates may have little relation to the 

size of the field used for production-facility design. 

For the analyst trying to characterize field growth, there 

are some caveats that should be pointed out before applying 

one of the techniques described herein. Any series of ultimate field-size estimates that reflect field growth also generally indicate field-development activity, which is driven 

by economics and market conditions. Consequently, fieldgrowth functions will reflect the economic conditions faced 

by the industry. The longer the series of estimates the more 

likely that the data will span a boom and bust cycle and 

will, on average, be representative of future conditions. 

If the time period between field discovery and first 

production is consistently excessive, as in a remote region, 

a more accurate index of field development might be the 

number of years since first production rather than the age 

of a field since discovery. Finally, field-growth patterns 

will also reflect the quality of the resource. Fields containing primarily heavy oil or having low-permeability gas 

reservoirs will have very different development patterns 

than conventional oil and gas fields. Therefore, nonconventional fields should be analyzed separately. 

REFERENCES CITED 

American Petroleum Institute, American Gas Association, and 

Canadian Petroleum Association, 1967-1980, Reserves of 

crude oil, natural gas liquids, and natural gas in the United 

States and Canada as of December 31: Washington, D.C., 

American Petroleum Institute, v. 25-34. 

Arrington, J.R., 1960, Size of crude reserves is key to evaluating 

exploration programs: Oil and Gas Journal, v. 58, no. 9, 

p. 130-134. 

Energy Information Administration, 1990a, U.S. oil and gas reserves by year of field discovery: Department of Energy 

(DOE/EIA-0534), 137 p. 

Energy Information Administration, 1990b, The domestic oil and 

gas recoverable resource base-Supporting analysis for the 

national energy strategy: Department of Energy SRINES/90-

05, 56 p. 

Fisher, W.L., 1991, Future supply potential of U.S. oil and natural gas: Society of Exploration Geophysicists, Leading Edge 

of Exploration, December, p. 15-21. 

Hubbert, M.K., 1967, Degree of advancement of petroleum exploration in United States: American Association of Petroleum Geologists Bulletin, v. 51, no. 11, p. 2207-2227. 

Hubbert, M.K., 1974, U.S. energy resources, a review as of 

1972, pt. I, in A national fuels and energy policy study: 

U.S. 93rd Congress, 2d session, S~nate Committee on Interior and Insular Affairs, Committee Print, Serial No. 93-

40(92-75), 267 p. 

Marsh, R.G., 1971, How much oil are we really finding?: Oil and 

Gas Journal, v. 69, no. 14, p. 100-104. 

Mast, R.F. and Dingler, J., 1975, Estimates of inferred and indicated reserves for the United States by states, in Miller and 

others, Geological estimates of undiscovered recoverable oil 

and gas resources in the United States, U.S. Geological Survey Circular 725, p. 73-78. 

National Petroleum Council, 1992, The potential for natural gas 

in the United States: Washington, D.C., National Petroleum 

Council, v. I, 190 p. 

Pelto, C.R., 1973, Forecasting ultimate oil recovery, in Symposium on Petroleum Economics and Evaluation, published by 

the Society of Petroleum Engineers of AIME, Dallas Section, p. 45-52. 

Potential Gas Committee, 1987, Potential supply of natural gas 

in the United States (December 31, 1986): Potential Gas 

Agency, Colorado School of Mines, 119 p. 

Root, D.H., 1981, Estimation of inferred plus indicated reserves 

for the United States, in Dolton, G.L. and others, Estimates 

of undiscovered recoverable conventional resources of oil 

and gas in the United States: U.S. Geological Survey Circular 860, p. 83-87. 

U.S. Department of the Interior, 1989, Estimates of undiscovered 

conventional oil and gas resources in the United States-A 

part of the Nation's energy endowment: U.S. Geological 

Survey and the Minerals Management Service, 51 p. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Gas Hydrates as a Potential Energy ResourceA Review of Their Methane Content 

By Keith A. K venvolden 1 

CONTENTS 

Abstract .......................................................................... 555 

Introduction .................................................................... 555 

Gas-hydrate Resource Estimates Before 1980 .............. 557 

Gas-hydrate Resource Estimates Since 1980 ................ 558 

Convergence of Gas-hydrate Resource Estimates ........ 559 

Recovery of Methane .................................................... 559 

Conclusions .................................................................... 560 

References Cited ............................................................ 560 

ABSTRACT 

Gas-hydrate deposits are found in sediments less than 

2,000 m deep in high-latitude regions associated with p~rmafrost, and beneath the ocean in outer continental margins. Because gas hydrates are globally widespread and 

contain methane within the solid hydrate structure of water, 

the potential amount of hydrate-methane present worldwide 

is very large. World estimates of the methane content of gas 

hydrates range from 5xl02 to 1.2xl06 trillion cubic feet 

(Tcf) (1.4x1013 to 3.4x1016 m3) for permafrost regions and 

from l.lx105 to 2.7x108 Tcf (3.1x1015 to 7.6x1018 m3) for 

deep oceanic sediments. These estimates are speculative 

and uncertain. Nevertheless, at the present time there is a 

convergence of ideas regarding the size of this potential 

worldwide resource, placing it at about 7x105 Tcf (2x1016 

m3) of methane. If this number is approximately correct, 

'J,.!.S. Geological Survey, MS 999, 345 Middlefield Rd., Menlo 

Park, CA 94025. 

there is about twice as much carbon in gas hydrates ~s is 

present in all known fossil-fuel deposits. Such large deposits of methane make gas hydrates attractive as a potential 

energy resource for the future. Uncertainties about mode of 

occurrence and the lack of applicable production techniques, however, augur that . wide-scale expJoitation, if 

proven feasible, will not take place until sometime in the 

21st century. 

INTRODUCTION 

Natural-gas hydrates are solid, ice-like substances 

composed of rigid cages of water molecules that enclose 

molecules of gas, mainly methane. Chemically speaking, 

these substances ~re water clathrates of methane, where 

clathrate refers to the cage structure of the water molecules. These deposits of solidified water and methane are 

commonly called either methane clathrates, gas clathrates, 

methane hydrates, or gas hydrates. The maximum amount 

of methane that can occur in a methane hydrate is fixed by 

the clatJ:!rate geometry. In an ideally saturated methane hydrate, the molar ratio of methane to water is nearly 1 :6. 

This molar ratio is equal to a volumetric ratio at standard 

temperature and pressure (STP) of about 164:1 (Davidson 

and others, 1978). 

The worldwide locations of known and inferred gas 

hydrates are shown in figure 1, and the following discussion comes from Kvenvolden (1988). The cold surface 

temperatures in polar regions promote the occurrence of 

permafrost, and the resulting cold temperatures at depth in 

permafrost regions lead to conditions appropriate for gashydrate deposits. Gas hydrates are known to be present at 

the Messoyakha gas field of the western Siberian platform 

(Makogon and others, 1972; Collett, this volume) and are 

555 
556 THE FUTURE OF ENERGY GASES 

believed to occur in other permafrost areas of northern 

Russia, including the Timan-Pechora province, the eastern 

Siberian craton, and the northeastern Siberian and Kamchatka areas (Cherskiy and others, 1985). 

Permafrost-associated gas hydrates are also present in 

the North American Arctic (Kvenvolden and Grantz, 

1990). Well-log responses consistent with the presence of 

gas hydrates were obtained in the Mackenzie Delta (Bily 

and Dick, 1974; Judge, 1982), Sverdrup Basin, Arctic 

Platform and Arctic Islands (Davidson and others, 1978; 

Judge, 1982; Judge and Majorowicz, 1992), and on the 

North Slope of Alaska (Collett and others, 1990). At a 

well between the Kuparuk River and Prudhoe Bay oil 

fields of the North Slope, pressure-core-barrel samples 

provided conclusive evidence for the presence of gas hydrates (reviewed by K venvolden and McMenamin, 1980). 

In addition to the onshore regions of permafrost in the 

Arctic, offshore permafrost is known to occur on the Beaufort Sea shelf of Canada (Neave and others, 1978; Weaver 

ARCTIC 

• 

Q 

;j~o. PA CIF/C 

0 ~~?i~·,;__ 

INDIAN~ ,: , 

OCEAN IJ d'ti OCEAN 

and Stewart, 1982). Also, offshore permafrost probably occupies a part of the vast continental shelf of Siberia (Bell, 

1983). Studies by Rogers and Morack (1980) on subsea 

permafrost and sea-level history have led to the inference 

that offshore permafrost may persist beneath any part of the 

Arctic shelf shoreward from about the 90-m isobath. 

Hence, the distribution of gas hydrates associated with offshore permafrost is expected to be similar to that of gas 

hydrates associated with onshore permafrost. 

The combined information from Arctic gas-hydrate 

studies shows that in permafrost regions, gas hydrates may 

exist at subsurface depths ranging from about 130 to 2,000 

m. Gas hydrates may also occur in Antarctica, but few 

data are available (Hitchon, 1974; MacDonald, 1983); 

land-temperature profiles suggest that gas hydrates could 

exist to depths as great as 2,000 m. 

The presence of gas hydrates in outer continental and 

insular margin sediments has been inferred mainly from 

the occurrence on marine seismic profiles of a pronounced 

OCEAN 

• 3D 0 

~o:· 

OCEAN 

OCEAN 

"" ... 

Figure 1. Worldwide locations of known and inferred gas hydrates in regions of continental permafrost (squares) and in oceanic 

sediments (dots). Diamonds mark locations where gas-hydrate samples have been recovered. Dashed lines in Antarctica indicate continental edge of ice shelves. Modified from Kvenvolden (1988) with information from Kvenvolden and others (1993). 
GAS HYDRATES AS A POTENTIAL ENERGY RESOURCE-A REVIEW OF THEIR METHANE CONTENT 557 

reflection that coincides with the predicted boundary at the 

base of the gas-hydrate stability zone. This reflection is 

commonly called a bottom-simulating reflection, or BSR, 

because it nearly parallels the topography of the sea floor. 

BSR's have been mapped at depths below the sea floor 

ranging from about 100 to 1,100 m (Kvenvolden and McMenamin, 1980; Dillon and others, this volume). The 

upper limit of the gas-hydrate zone in outer continental 

margin sediments is ordinarily the sea floor. 

Samples of gas hydrates have been recovered at 14 

oceanic locations, providing positive proof of natural 

gas-hydrate occurrence (fig. 1 ). Deep-ocean drilling has 

recovered gas hydrates offshore from Peru, Costa Rica, 

Guatemala, Mexico, southeastern United States, and westem United States, at two locations offshore from Japan, and 

in the Gulf of Mexico. Shallow-sediment coring (piston and 

gravity cores) has recovered gas hydrates in sediment from 

the Black Sea, Caspian Sea, offshore from northern California and in the Gulf of Mexico, and at two locations in the 

Sea of Okhotsk (Kvenvolden and others, 1993). 

The preceding discussion demonstrates that gas-hydrate deposits are globally widespread and are limited to 

the uppermost 2,000 m of the sediment column. Because 

gas hydrates contain a potentially large amount of methane 

within 2,000 m of the Earth's surface, they are attractive 

as a possible energy resource for the future. This report 

reviews the estimates that have been made of the methane 

content of gas hydrates and makes the following points. 

1. The amount of methane in gas hydrates is certainly 

large, but all of the estimates that have been 'made are 

speculative. . 

2. A convergence of current ideas suggests that the 

amount of methane in gas hydrates worldwide is about 

7x105 trillion cubic feet (Tcf) or 2xi016 m3. (These values are equivalent to lxi0 19 g methane carbon or lxi04 

gigaton (Gt) methane carbon (1 gigaton= I 09 metric 

ton=I015 g)). In this paper Tcf units are used, with metric 

equivalents given in the tables and summaries. 

3. Present uncertainties about mode of occurrence of 

gas hydrates and about applicable production technologies 

limit the feasibility of immediate wide-scale exploitation. 

4. If these uncertainties can be overcome, gas-hydrate 

exploitation may become a reality sometime in the 21st 

century. 

GAS-HYDRATE RESOURCE ESTIMATES 

BEFORE 1980 

Estimates made before 1980 of the amount of methane 

in natural gas hydrates are highly speculative due to incomplete knowledge of gas-hydrate occurrences and poor methods of estimating reserves in known occurrences. The 

following discussion is taken from a detailed analysis by 

the Potential Gas Committee (1981) of the potential supply 

of natural gas as of December 1980. Conventional methods 

of estimating gas resources are not applicable to gashydrate deposits because (1) on conventional well logs, gas 

hydrates have the same characteristics as permafrost, (2) 

flow tests require a means of disrupting equilibrium conditions in order to dissociate the gas hydrates to verify their 

presence, (3) reservoir permeability has thus far been found 

to be very low, and (4) the hydrate-gas/free-gas ratio cannot 

be fully determined from core samples or porosity measurements (Barraclough, 1980). Nevertheless regional and 

world estimates of gas-hydrate resources have been calculated (table I). Trofimuk and others ( 1977) attempted to 

incorporate many complex factors into their calculations, 

including regional and world coefficients of past and 

present temperatures, sediment thicknesses, percent of organic material, and percent of methane production and 

retention. 

World estimates for the amount of methane in gashydrate deposits range from 5x 102 to 1.2x I 06 Tcf for permafrost areas and from l.lxi05 to 2.7xl08 Tcf for oceanic 

sediments. The estimates in table 1 show considerable variation, but oceanic sediments seem to be a much greater 

resource of hydrate methane than continental sediments 

because in oceanic sediments greater production of microbial methane occurs and the gas-hydrate stability zone is 

more extensive. The estimates by Dobrynin and others 

(1981) are considerably higher than the others. Their calculations are "rough estimates" based on permafrost coverage and zones of gas-hydrate stability in oceanic 

sediments without apparent regard for distributions of sedimentary basins or sources of methane. Their estimates 

provide an overly optimistic upper limit. 

None of these estimates (table I) seem to account for 

reservoir quality. Proved and currently recoverable world 

resources of conventional methane are 2.3xi03 to 2.7x103 

Tcf, and the estimated total remaining recoverable methane is 7.9x103 to 9.2xl03 Tcf (Parent, 1980). If only 1 

percent of gas-hydrate methane is within porous and permeable strata, then the most conservative estimate for recoverable hydrate methane is still more than 1.1 x 103 Tcf, 

or one-half of the proved and currently recoverable conventional gas resources. Also the above estimates do not 

consider possible accumulations of free gas trapped beneath the gas-hydrate layers. 

Estimates of methane in gas-hydrate deposits of the 

United States (table 2) were extrapolated from the world 

estimates (table 1). Based on Russian estimates for methane in gas hydrates of Siberia, Mciver (1981) calculates 

that permafrost areas in Alaska have about 23 Tcf of hydrate methane. Gas-hydrate resources in permafrost areas 

of the United States may contain from 1.1 x 101 to 2.5x 104 

Tcf of methane. Gas-hydrate resources in continental shelf 

and slope areas of the United States represent about 7 percent of the total world resource of hydrated methane if it 

is assumed that 35 percent of oceanic gas hydrates occur 
558 THE FUTURE OF ENERGY GASES 

Table 1. World estimates of the amount of methane in gas hydrates in continental and oceanic settings (from the Potential Gas 

Committee, 1981 ). 

Volume of methane 

Reference 

(trillion cubic feet) (cubic meters) 

Continental 

5.0xl02 

l.lx103 

2.0xl03 

1.2xl06 

l.lx105 

(1.8 to 8.8)x105 

2.7x108 

1.4x1013 

3.1xl013 

5.7x1013 

3.4x1016 

Oceanic 

3.1 X 1015 

(5 to 25)xl015 

7.6xl018 

Meyer (1981) 

Mciver (1981) 

Trofimuk and others (1977) 

Dobrynin and others ( 1981) 

Mciver ()981) 

Trofimuk and others (1977) 

Dobrynin and others (1981 ) 

in these areas (Potential Gas Committee, 1981). Thus estimates of methane in gas hydrates in oceanic sediments 

along continental margins of the United States range from 

2.7xl03 to 6.7x106 Tcf. . 

GAS-HYDRATE RESOURCE ESTIMATES 

SINCE 1980 

As discussed above, estimates made during the 1980's 

of the amount of methane in gas hydrates produced a wide 

range of values with the upper limit of 2.7x108 Tcf being 

unrealistically large. An increased understanding of gas-hydrate occurrence since then has resulted in estimates that 

are in the lower range of previous values. For example, 

Claypool (K venvolden and Claypool, 1988) estimated the 

amount of methane in oceanic sediments by determining 

the area of the world ocean in which sediment with 1 percent or more organic carbon is accumulating (10x106 km2). 

Assuming 0.5 km as the average thickness of the gas-hydrate stability zone, an average porosity of 50 percent with 

gas hydrates occupying 10 percent of the available porosity, 

and a gas-hydrate yield of 160 volumes of gas at STP per 

volume of hydrate, the amount of methane present in oceanic gas hydrates is calculated to be about 1.4x 106 Tcf. 

This estimate of 1.4x I 06 Tcf could be refined downward by taking into consideration the fact that most of the 

sediment in the estimated area probably contained insufficient organic carbon to generate the volumes of methane 

required to occupy 10 percent of the available porosity 

with gas hydrates. The estimate could also be refined upward by taking into account that sediment accumulation in 

upwelling areas would have significantly more methane 

than is allowed for in the average values used. Such reTable 2. Estimates of the amount of methane in gas hydrates of 

the United States (from the Potential Gas Committee, 1981). 

Volume of methane 

(trillion cubic feet) 

l.lxl01 

2.3x101 

4.2x101 

2.5x10 14 

2.7x103 

(4.2 to 21)xlo5 

6.7x106 

Reference 

(cubic meters) 

Continental (Alaska) 

3.1xl011 

6.5x10 11 

1.2xl0 12 

7.1x10 14 

Meyer (1981) 

Mciver (1981) 

Trofimuk and others (1977) 

Dobrynin and others ( 1981) 

Oceanic (shelf and slope) 

Mciver (1981) 

(1.2 to 6.1)x10 14 Trofimuk and others (1977) 

Dobrynin and others (1981) 

finements are not justified, however, on the basis of the 

present state of understanding. 

Kvenvolden and Grantz (1990) attempted to estimate 

the extent of gas hydrate in the outer continental margin of 

the Arctic Basin by extrapolating information from the 

amount of gas hydrate offshore of northern Alaska as inferred from marine seismic records. Taking into account 

areal extent (5.25x 1 o5 km2), thickness of the gas-hydrate 

zone (40 m), average porosity (30 percent), and gashydrate yield (140 volumes of gas at STP per volume of 

hydrate), they calculated a total of about 3.5x104 Tcf of 

methane in sediment of the outer margin of the Arctic 

Basin. The length of this margin is about 5 percent of the 

total length of continental margins worldwide. If oceanic 

gas hydrates in general are distributed as they are inferred 

to be in the Arctic, then the total amount of methane in 

oceanic gas hydrates would be about 7x105 Tcf (Kvenvolden, 1988). This estimate is a factor of two less than 

that ma<;ie by Claypool but falls within the range of values 

(1.8x105 to 8.8xi05 Tcf) determined by Trofimuk and others (1977). These recent estimates, however, are about two 

orders of magnitude smaller than that by Dobrynin and 

others (1981) of 2.7x108 Tcf. 

MacDonald ( 1990) used data from Cherskiy and others (1985) to estimate roughly the areal extent, thickness, 

and volume of the gas-hydrate stability zone for four 

major regions in northern Russia. A porosity of either 2 or 

4 percent was assumed depending on the age of the sediments containing gas hydrates. The volume actually occupied by gas hydrate was assumed to be I percent. On the 

basis of these assumptions, MacDonald (1990) .calculated 

that 2.3x104 Tcf of methane are stored in gas hydrates in 

the permafrost regions of Siberia and 0.3x 104 Tcf of methane are present in continental gas hydrates of the North 

American Arctic, giving a total of 2.6x104 Tcf of methane 

in gas hydrates of the world's permafrost regions. A higher 
GAS HYDRATES AS A POTENTIAL ENERGY RESOURCE-A REVIEW OF THEIR METHANE CONTENT 559 

value might actually be appropriate if Antarctica were included in the estimate. 

For oceanic gas hydrates, MacDonald (1990) assumed 

that the average thickness of the gas-hydrate stability zone 

is 0.5 km and that the total volume of sediment in this zone 

between water depths of 200 and 3,000 m is 31.3x106 km3 

of which 12.5x106 km3 are available for gas hydrate formation. If only 1 percent of the total sedimentary pore space 

contains gas hydrates, then the total volume of gas hydrate 

is 1.25x106 km3. This total volume corresponds to 7.1x105 

Tcf of methane if the gas-hydrate structure is 90 percent 

filled. This estimate does not include gas hydrates in sediments at water depths greater than 3,000 m. The total resource base of methane in continental and oceanic gas 

hydrates would therefore be 7.4x105 Tcf. 

CONVERGENCE OF GAS-HYDRATE 

RESOURCE ESTIMATES 

Estimates of the amount of methane in gas hydrates 

are still speculative and uncertain. Although it is generally 

appreciated that gas hydrates occur worldwide (fig. 1 ), detailed geologic knowledge of their occurrence is incomplete, contributing to the wide range of estimates. 

Nevertheless, since 1988 there has been a convergence of 

ideas regarding the amount of methane in the gas-hydrate 

deposits of the world. Current estimates of the amount of 

methane in gas hydrates are in rough accord at 7 .4x 105 

Tcf or 2.1 x 1016 m3 (MacDonald, 1990) and 7x 105 Tcf or 

2x1016 m3 (Kvenvolden, 1988), with 1.4x106 Tcf or 

4x1016 m3 (Kvenvolden and Claypool, 1988) being only a 

factor of 2 larger. If these estimates are valid, then the 

amount of methane in gas hydrates is almost two orders of 

magnitude larger than the estimated total remaining recoverable conventional methane (about 9xl03 Tcf or 2.5x1014 

m3

) and about a factor of two larger than the methane 

equivalent of all known fossil-fuel deposits (coal, oil, and 

natural gas). 

RECOVERY OF METHANE 

Although naturally occurring gas hydrates apparently 

contain large amounts of methane, this methane cannot be 

considered a resource unless it can be recovered. To date 

the gas industry has been slow to develop methodolo~ies to 

recover methane from gas hydrates. Three principal methods are being considered: thermal stimulation, depressurization, and inhibitor injection (Holder and others, 1984 ). 

In thermal stimulation, the gas-hydrate-bearing strata are 

heated in order to increase the local temperature enough to 

cause gas hydrates to dissociate. In depressurization, the 

pressure in the gas-hydrate deposit is lowered by pumping 

to cause gas-hydrate dissociation; heat for the gas-hydrate 

dissociation in the depressurization process is provided by 

the natural geothermal heat flow. Injection of inhibitors, 

agents such as methanol which cause gas hydrates to dissociate, shifts the pressure-temperature equilibrium (phase 

boundary) so that the gas hydrates are no longer stable at 

in-situ pressure-temperature conditions. 

Of these three production methodologies, depressurization combined with hot-water injection appears to be the 

most practical where free gas is trapped beneath the gas 

hydrate (Holder and others, 1984 ). That free gas is trapped 

beneath the gas hydrate has yet to be established with certainty (Kvenvolden, this volume). Gas hydrates will become a potential energy resource when it can be shown that 

the energy required to release methane from the hydrate 

itself is significantly less than the thermal energy of the 

methane that can be recovered from the dissociated gashydrate deposits. Circulation of warm surface water into 

gas-hydrate deposits and horizontal drilling techniques provide possible future approaches to the exploitation of hydrated methane. 

The production of methane from gas hydrates requires 

that the deposit occur in geologic contexts wherein the elements of a conventional gas deposit are present; that is, in 

association with a reservoir of adequate porosity and permeability, with a methane source, and with a seal to form a 

trap. Dissociated gas hydrate can serve as one source of 

methane; migrated methane from below the gas-hydrate 

zone is another possible source. Development of the Messoyakha gas field in western Siberia during the past 25 

years has proven that methane can be recovered from naturally occurring gas hydrates (Makogon, 1981; Collett, this 

volume), but the methanol injection methods used for production proved to be prohibitively expensive. Recovery of 

gas hydrates in pressurized core barrels at the Arco-Exxon 

N.W. Eileen State No. 2 wildcat well on the North Slope of 

Alaska confirmed the presence of gas hydrates in the region 

of the Prudhoe Bay and Kuparuk River oil fields (Kvenvolden and McMenamin, 1980). 

It has recently been estimated that about 40 Tcf 

( 1.1 xI 012 m3) of methane are present in gas hydrates of 

this region (Collett, 1992). This amount of methane is 

about 1.4 times that in conventional reservoirs in the same 

region, but is only 9 percent of the conventional North 

America gas reserves (about 440 Tcf or 12.5xi012 m3). 

This estimate is also comparable to the majority of previous 

estimates that were predicted for methane in gas hydrates in 

all of Alaska (table 2). If methane from gas hydrates is ever 

to be recovered commercially in· the United States, larger 

accumulations will have to be identified and exploited. Initial production, however, is likely to come from the North 

Slope of Alaska where the industrial infrastructure for handling gas is already in place. Methane first produced from 

gas hydrates on the North Slope will likely be used for 

repressurization of waning oil fields rather than as a source 
560 THE FUTURE OF ENERGY GASES 

of fuel. Although methane from gas hydrates should be 

considered a potential energy resource, wide-scale recovery 

of methane from gas hydrates will probably not be accomplished until the 21st century (Sloan, 1990). 

CONCLUSIONS 

Natural gas hydrates are globally widespread and contain a very large amount of methane that is trapped within 

the solid-water hydrate structure. World estimates made 

before 1980 of the amount of methane in gas hydrates 

range from 5x102 to 1.2x!06 Tcf (1.4x!013 to 3.4xi016 

m3) for permafrost regions and from l.lxl05 to 2.7x108 

Tcf (3.lxi015 to 7.6xi018 m3) for deep oceanic sediments. 

These speculative estimates are based on overall volumetric considerations with limited field verification. The upper 

limits of these ranges are probably unrealistic because no 

account is taken of the need for adequate sources of methane. Since 1980 ideas from two independent approaches 

regarding the size of this potential worldwide resource 

converge at about 7xi05 Tcf (2xi016 m3) of methane. A 

third approach yielded an estimate that is only a factor of 

two larger. If these estimates are approximately correct, 

then gas hydrates are an attractive potential energy source 

for the future. But uncertainties in mode of occurrence and 

lack of applicable production techniques are formidable 

problems that must be solved before wide-scale exploitation can take place. 

REFERENCES CITED 

Barraclough, B.L., 1980, Gas energy review-Gas from natural 

gas hydrates: American Gas Association (edited by H.J. 

Moll), v. 7, no. 10, p. 1-5. 

Bell, P.R., 1983, Methane hydrate and the carbon dioxide question, in Clark, W.C., ed., Carbon dioxide review 1982: New 

York, Oxford University Press, p. 401-406. 

Bily, C., and Dick, J.W.L., 1974, Naturally occurring gas hydrates in the Mackenzie Delta, N.W.T.: Bulletin of Canadian 

Petroleum Geology, v. 32, p. 340-352. 

Cherskiy, N.V., Tsarev, V.P., and Nikitin, S.P., 1985, Investigation and prediction of conditions of accumulation of gas resources in gas-hydrate pools: Petroleum Geology, v. 21, p. 

65-89. 

Collett, T.S., Kvenvolden, K.A., and Magoon, L.B., 1990, Characterization of hydrocarbon gas within the stratigraphic interval of gas-hydrate stability on the North Slope of Alaska, 

U.S.A.: Applied Geochemistry, v. 5, p. 279-287. 

Collett, T.S., 1992, Potential of gas hydrates outlined: Oil and 

Gas Journal, v. 90, no. 25, p. 84-87. 

Davidson, D.W., El-Defrawy, M.K., Fulgem, M.O., and Judge, 

A.S., 1978, Natural gas hydrates in northern Canada: National Research Council of Canada, Proceedings 3rd International Conference on Permafrost, v. 1, p. 938-943. 

Dobrynin, V.M., Korotajev, Yu. P., and Plyuschev, D.V., 1981, Gas 

hydrates-A possible energy resource, in Meyer, R.F., and 

Olson, J.C., eds., Long-term energy resources: Boston, Pitman, p. 727-729. 

Hitchon, B., 1974, Occurrence of natural gas hydrates in sedimentary basins, in Kaplan, I.R., ed., Natural gases in marine sediments: New York, Plenum Press, p. 195-225. 

Holder, G.D., Kamath, V.A., and Godbole, S.P., 1984, The potential of natural gas hydrates as an energy resource: Annual 

Review of Energy, v. 9, p. 427-445. 

Judge, A.S., 1982, Natural gas hydrates in Canada, in French, 

M.H., ed., Proceedings of the 4th Canadian Permafrost Conference 1981, Roger J.E. Brown Memorial Volume: National 

Research Council of Canada, p. 320-328. 

Judge, A.S., and Majorowicz, J.A., 1992, Geothermal conditions 

for gas hydrate stability in the Beaufort-Mackenzie areaThe global change aspect: Palaeogeography, Palaeoclimatology, Palaeoecology (Global and Planetary Change Section), 

v. 98, p. 251-263. 

Kvenvolden, K.A., 1988, Methane hydrate-A major reservoir of 

carbon in the shallow geosphere?: Chemical Geology, v. 71, 

p.41-5l. 

Kvenvolden, K.A., and Claypool, G.E., 1988, Gas hydrates in 

oceanic sediment: U.S. Geological Survey Open-File Report 

88-216, 50 p. 

Kvenvolden, K.A., and Grantz, A., 1990, Gas hydrates of the Arctic Ocean region, in Grantz, A., Johnson, L., and Sweeney, 

J.F., eds., The Arctic Ocean Region: Boulder, Colorado, Geological Society of America, The Geology of North America, 

Vol. L, p. 539-549. 

Kvenvolden, K.A., and McMenamin, M.A., 1980, Hydrates of 

natural gas-A review of their geological occurrences: U.S. 

Geological Survey Circular No. 825, 11 p. 

Kvenvolden, K.A., Ginsburg, G.D., and Solovyev, V.A., 1993, 

Worldwide distribution of subaquatic gas hydrates: GeoMarine Letters, v. 13, p. 32-40. 

MacDonald, G.T., 1983, The many origins of natural gas: Journal 

of Petroleum Geology, v. 5, p. 341-362. 

MacDonald, G.T., 1990, The future of methane as an energy resource: Annual Review of Energy, v. 15, p. 53-83. 

Makogon, Yu. F., 1981, Hydrates of natural gas: Tulsa, Okla., 

Pennwell Publishing, 237 p. 

Makogon, Yu. F., Trebin, F.A., Trofimuk, A.A., Tsarev, V.P., and 

Cherskiy, N.V., 1972, Detection of a pool of natural gas in a 

solid (hydrated gas) state: Doklady Academy Science USSR, 

Earth Science Section, v. 196, p. 197-200. 

Mciver, R.D., 1981, Gas hydrates, in Meyer, R.F., and Olson, J.C., 

eds., Long-term energy resources: Boston, Pitman, p. 713-

726. 

Meyer, R.F., 1981, Speculations on oil and gas resources in small 

fields and unconventional deposits, in Meyer, R.F., and 

Olson, J.C., eds., Long-term energy resources: Boston, Pitman, p. 49-72. 

Neave, K.G., Judge, A.S., Hunter, J.A., and MacAulay, H.A., 

1978, Offshore permafrost distribution in the Beaufort Sea as 

determined from temperature and seismic observations: Geological Survey of Canada, Current Research, Part C, Paper 

78-1C, p. 13-18. 

Parent, J.D., 1980, A survey of the United States and total world 

production, proved reserves, and remaining recoverable re-
GAS HYDRATES AS A POTENTIAL ENERGY RESOURCE-A REVIEW OF THEIR METHANE CONTENT 561 

sources of fossil fuels and uranium: The Institute of Gas 

Technology, Chicago, Illinois, 140 p. 

Potential Gas Committee, 1981, Potential supply of natural gas in 

the United States (as of December 31, 1980): Golden, Colorado, Potential Gas Agency, Colorado School of Mines, 119 p. 

Rogers, J.C., and Morak, J.L., 1980, Geophysical evidence of 

shallow nearshore permafrost, Prudhoe Bay, Alaska: Journal 

of Geophysical Research, v. 85(B9), p. 4845-4853. 

Sloan, E.D., 1990, Clathrate hydrates of natural gas: New York, 

Marcel Dekker, 641 p. 

Trofimuk, A.A., Cherskiy, N.Y., and Tsarev, V.P., 1977, The role 

of continental glaciation and hydrate formation on petroleum 

occurrences, in Meyer, R.F., ed., Future supply of naturemade petroleum and gas: New York, Pergamon Press, p. 919-

926. 

Weaver, J.S., and Stewart, J.M., 1982, In-situ hydrates under the 

Beaufort Sea Shelf, in French, M.H., ed., Proceedings of the 

4th Canadian Permafrost Conference 1981, Roger J.E. Brown 

Memorial Volume: National Research Council of Canada, p. 

312-319. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Use of Seismic Data in Estimating the Amount of 

In-Situ Gas Hydrates in Deep Marine Sediment 

By Myung W. Lee1

, Deborah R. Hutchinson2, William P. Dillon2, John J. Miller1

, 

Warren F. A gena 1

, and Barbara A. Swift2 

CONTENTS 

Abstract ·································----------·----··················------- 563 

Introduction ................................................................... 564 

Geologic Setting and the Bottom-Simulating 

Reflector ····--·-·-·--·----------······················-----·--·----············· 564 

Seismic Data and Processing ....................................... 566 

True-Amplitude Processing ................................... 566 

Velocity and Amplitude Analysis .......................... 566 

Results ·····················----------·-·--------------···········---------------- 568 

Velocity .................................................................. 568 

Amplitude .............................................................. 571 

Relation Between Velocity and Amplitude ........... 571 

Summary ................................................................ 572 

Physical Basis for Modeling Hydrates ......................... 573 

Models .......................................................................... 574 

Model !-Porosity and Hydration Boundaries ..... 575 

Model 2-Porosity Boundary'and Constant 

Hydration ............................................................... 575 

Model 3-Porosity and Lithologic Boundary ....... 576 

Model 4-Sediment Substitution .......................... 576 

Discussion ..................................................................... 578 

Conclusions ·············································-----------·-········· 579 

Acknowledgments ........................................................ 580 

References Cited ........................................................... 580 

1

U.S. Geological Survey, P.O. Box 25046 MS 934, Denver, CO 

80225. 2

U.S. Geological Survey, Gosnold Bldg., Quissen Campus, Woods 

Hole, MA 02543. 

ABSTRACT 

The bulk volume of gas hydrates in marine sediment 

can be estimated by measuring interval velocities and reflection amplitudes of hydrated zones from true-amplitudeprocessed multichannel seismic-reflection data. In general, 

neither velocity nor amplitude information alone is adequate to estimate hydrate concentration. We propose a method that uses reduction in amplitude (amplitude blanking) 

calibrated by interval-velocity data to quantify hydrate concentrations in the Blake Ridge area of the U.S. Atlantic 

continental margin. Once calibration has been performed 

throughout the region, only reflection amplitudes are needed 

for estimating bulk-hydrate concentrations. This method is 

especially beneficial when applied to local areas where only 

single-channel seismic surveys are available (no interval 

velocities), but where at least one multichannel seismic line 

is available for initial calibration. -

The model, which gives the best estimates for the 

Blake Ridge, is based on the observation in this region 

that amplitude blanking is associated with relatively low 

interval velocities. In the model, there is a replacement of 

normal sediment with "representative hydrated sediment." 

Representative hydrated sediment is a sediment of defined 

matrix density and porosity with pore space filled by a 

mixture of water and hydrate. The proportion of water to 

hydrate in the representative sediment is one of the variables in the model; it can be calculated using an equation 

in which velocity is estimated from the seismic data and 

known properties of pure hydrate, and in which porosity 

inferred from a velocity/porosity relationship. Once these 

calculations have been performed, the model is calibrated, 

and the porosity and hydrate proportions of the representative sediment are fixed. 

563 
564 THE FUTURE OF ENERGY GASES 

These parameters can then be combined with reflection amplitudes (blanking) to determine bulk-hydrate concentrations. For example, a small area near Deep Sea 

Drilling Project (DSDP) site 533 indicates that the amount 

of gas hydrates is about 5 percent in total volume when 

interval velocity alone is used as a criterion and about 8 

percent when amplitude information (calibrated by an average interval velocity) is used. This latter estimate is corroborated by the only available measurement from DSDP 

site 533. 

INTRODUCTION 

Below a few hundred meters of water depth in the 

world's oceans, sea-floor sediment lies in the pressure/temperature zone of phase stability for gas hydrates. Gas hydrates are ice-like crystalline solids that are formed when 

cage of water molecules surrounds a guest gas molecule. 

Evidence of their existence has come from recognizing a 

bottom simulating reflector (BSR) on seismic profiles that 

marks the base of the zone of gas hydrates occurrence and 

from sampling by the Deep Sea Drilling Project (DSDP) 

and Ocean Drilling Program (ODP) (Kvenvolden and Barnard, 1983; Shipley and Didyh, 1982; Suess and others, 

1988). In most naturally occurring gas hydrates, the guest 

molecule is methane. 

Even though large volumes of hydrates apparently exist 

within the upper several hundred meters below the sea 

floor, no quantitative approaches are known for estimating 

the amount of in-situ gas hydrates. Estimates of the global 

quantity of methane in hydrates have been presented by 

many researchers (Dobrynin and others, 1981; Mciver, 

1981; Kvenvolden, 1988; Sloan, 1990 and references therein); these estimates differ by as much as two orders of 

magnitude. A limitation of these estimates is the assumption of in-situ conditions and thermodynamic state. Hence, 

these assessments are neither quantitative nor accurate because they are not based on observable information. 

Estimating the amount of gas hydrates contained in 

marine sediment is a challenge. Hydrates contain perhaps 

600,000 to one million Tcf (trillion cubic feet) of methane 

(Kvenvolden, 1988), or approximately 35,000 to 65,000 

times the U.S. gas consumption in 1989. Therefore, hydrates are a potential source of energy, although methods of 

extracting gas from hydrates have not yet been developed. 

This large volume may be significant to climate change. 

Methane (CH4) has 3. 7 times the global warming effect of 

carbon dioxide on a molar basis (or 10 times on a weight 

basis, Lashof and Ahuja, 1990). Although CH4's average 

residence time in the atmosphere is only about 10 years, it 

is oxidized to C02, which continues to cause global warming (Lashof and Ahuja, 1990). Finally, the dissociation of 

hydrates in sediment (for example, by lowering sea level, 

which then Jowers the pressure in the underlying sediment 

and brings some of the hydrates out of their stability zone) 

may be one cause of slope failure on continental margins 

during episodes of peak glaciation (Dillon and others, 1991, 

Paull and others, 1991). 

Gas hydrates are known to increase the interval velocity of sediments (Stoll, 1974; Tucholke and others, 1977; 

Dillon and Paull, 1983) by an amount that is proportional to 

the amount of hydrate (Pearson and others, 1983). This 

relation was used by Tucholke and others (1977) to explain 

an observed range in velocity from 1.6 to 1.9 km/s as the 

result of the variable thicknesses of hydrated sediments. 

Sheridan and others (1983) estimate that near DSDP site 

533 (fig. 1 ), as much as 20 to 30 percent of the sedimentary 

section should have been gas hydrates to produce an average velocity of 2 km/s, although such large amounts of 

hydrate were not recovered during drilling. 

Another indicator of gas hydrates is the amplitude reduction or blanking typically observed above the BSR in 

reflection profiles from regions of known hydrates. Shipley 

and others (1979) related the marked decrease of amplitude 

above the BSR to a reduction in impedance contrast across 

sedimentary interfaces caused by the presence of hydrates. 

Dillon and others (1991) also observed amplitude blanking 

from true-amplitude seismic sections, and they ascribe this 

effect to hydrate formation. These studies imply that. amplitude information can be used as an indicator of hydrate 

concentration. 

We propose a quantitative method for estimating the 

amount of gas hydrates in marine sediment based on measurable acoustic properties of seismic-reflection data. Our 

approach uses both the kinematics (interval velocity) and 

the dynamics (seismic amplitude) of the wave field; more 

specifically, the increase in velocity and decrease in reflection amplitude observed in regions where hydrates are 

present. 

GEOLOGIC SETTING AND THE 

BOTTOM·SIMULATING REFLECTOR 

The continental margin of the southeastern United 

States is a zone of depositional transition between the actively building carbonate platform of the Bahamas and the 

terrigenous or clastic-dominated shelf-slope-rise configuration of eastern North America (Dillon and Popenoe, 1988). 

The region off North and South Carolina is the southern 

limit of the dominantly terrigenous continental margin. In 

this region, contour-following bottom currents since the 

Oligocene have built a drift deposit of hemipelagic sediment that extends southeastward away from the continental 

slope, and forms the Blake Ridge (fig. 1). Seismic profiles 

over the Blake Ridge and the continental rise just to its 

north are prominently marked by a large-amplitude reflection that approximately parallels the sea floor, known as the 

BSR (Markl and others, 1970; Ewing and Hollister, 1972; 
ESTIMATING THE AMOUNT OF GAS HYDRATES IN DEEP MARINE SEDIMENT 565 

Tucholke and others, 1979; Shipley and others, 1979). The 

BSR is probably caused by a large impedance contrast at 

the base of the hydrate stability zone, which juxtaposes 

sediment containing gas hydrates with sediment lacking gas 

hydrates but possibly containing free gas (Miller and others, 1991). 

0 50KM 

A primary objective of DSDP site 533 on the Blake 

Ridge (fig. 1) was to sample gas hydrates in a region of a 

well-developed BSR. This hole penetrated 399 m beneath 

the sea floor and terminated in middle Pliocene silty mud 

(Sheridan and others, 1983). Gas pockets, disrupted sediment, and frothing characterized parts of the recovered 

33° 

Figure 1. Bathymetry of southeastern U.S. continental margin, location of multichannel seismic-reflection profiles, DSDP 

sites 103, 104, 390, and 533. DSDP site 533 was drilled to sample gas hydrate. N.C., North Carolina; S.C., South Carolina; 

bathymetric contours in meters. Dot pattern shows extent of bottom-simulating reflector (BSR). Modified from Dillon and 

Popenoe (1988). 
566 THE FUTURE OF ENERGY GASES 

cores. The only direct evidence for gas hydrates was found 

at a subbottom depth of 238 m, where a layer several centimeters thick contained frothy sediment with white mat-like 

crystals that rapidly disappeared when exposed to atmospheric conditions (Kvenvolden and Barnard, 1983). 

Gas pockets severely hampered the measurement of 

physical properties; bulk density was estimated from 1.67 

to 1.74 g/cm3 and porosity from two intervals was estimated at 57 to 60 percent. The BSR was estimated to be 

about 200 m below the bottom of the hole, or about 600 m 

below the sea floor (Sheridan and others, 1983). Chemical 

analysis shows that the gas is derived through microbiological processes rather than thermogenic processes and 

consists almost entirely of methane. The high rate of sedimentation has ensured the preservation of enough organic 

matter for the bacterial production of methane (Kvenvolden and Barnard, 1983). 

SEISMIC DATA AND PROCESSING 

The location of the five multichannel seismic profiles 

used for this investigation are shown in figure 1. They 

were recorded in the early to mid-1970's using tuned airgun arrays of 1,000 to 2,000 in3 volume. Four of the lines 

provide 36-fold coverage with 50-m common midpoint 

(CMP) intervals. Gilliss line 2 is a 12-fold recording (fig. 

1). All profiles, except Gilliss line 2, were recorded with 

48-channel streamers, 3.6 km long, containing nonlinear 

group spacing. Gilliss line 2 was recorded with a linear 

1.2-km-long streamer. 

TRUE-AMPLITUDE PROCESSING 

To optimize the quantitative analysis of hydrated sediment, a relative true amplitude processing technique with 

wavelet deconvolution was applied to all profiles. The processing was performed by. the automatic editing method 

based on the median amplitude in a CMP gather (Lee and 

Hutchinson, 1990) with only a spherical spreading correction applied. Other amplitude corrections that compensate 

for effects such as attenuation and transmission loss were 

not included in this relative true amplitude processing, 

because these other effects may introduce seismic artifacts 

that impede the identification of hydrated sediment. Wavelet deconvolution was done by the variable norm deconvolution method (Gray, 1979). A representative source 

signature from deep water (two-way traveltimes of approximately 4 s) was derived, and an inverse filter was calculated and applied along each line. Source signature variations 

due to the gun depth, streamer depth, and gun failure were 

compensated for by applying second-zero-crossing predictive deconvolution before stack. The justification of this 

kind of approach, which applies the same inverse filter for 

the whole profile instead of applying separate deconvolution filters to each gather, comes from studies done by Dragoset and others (1987). Examples of wavelet-processed 

seismic data with 6/8 to 40/50 Hz band-pass filtering are 

shown in figure 2. In this figure, 10 consecutive CMP's are 

shown for USGS line 32 (fig. 2A) and Teledyne TD2HG 

(fig. 28). Both sections show almost symmetrical waterbottom reflections (peak amplitude) and well-defined 

trough reflections at the BSR. Because of the stacking process, the higher frequency component of data has been lost. 

However, the improvement of signal-to-noise ratio and almost identical wavelets among different seismic lines due 

to the wavelet processing warrant reliable amplitude analyses of seismic data in the Blake Ridge area. Another example of the wavelet and relative true amplitude-processed 

data for part of USGS line 32 is shown in figure 3. 

VELOCITY AND AMPLITUDE ANALYSIS 

Detailed_ velocity measurements via stacking analysis 

were made every 100 CMP's, or about every 2.5 km along 

profile. Interval velocities determined in this fashion were 

1001 1010 

.2 -+--+-t---1-+-+-+-t--+-+-

-~ r))))' ',, 

' 

) WAT 

A 

.s-++-t-14-++-H-+-

- --f---f- -r-- r---t- t---t-t---

A 

CMP 

1121 1130 

3.4 

B 

Figure 2. Wavelet-processed seismic sections. Ten consecutive 

CMP's (common midpoints) are shown; BSR, bottom-simulating 

reflector. A, USGS line 32; B, TD2HG. 
CMP 

1124 1070 1016 962 908 854 800 

4.0 

506 

4.2 . ••.•• . .. ..••••. . . . . . ••• • . . . .. •••• . . . . . • •. .. .. . . •• • •• .. . . . •• .• . . .. .•••• • . . . . .•• • .. .. ..• . ••• . . .. •. • • • . .. . ··•••· . . . . • . • . •... . . ••• 

460 

\o.o' I . . .. .. .. 0 0 0 •••• • • I 0 I . ... ... 0 0 0 • ••••• , I I I I •• • • 0 I I 0 ••• • •• • I 0 I • • • ••• I 0 0 • ••• • •• 0 0 •• ••• • • 0 0 I •••• • • 0 I I •• • • • • 0 I I I • ••• 

414 

4.4 

368 

322 

4.6 

0 

w 

(/) 

w 

276 Cl 

~ ...1 

w 

:a 

i= 

c.. 230 :a 

<( 

4.8 184 

138 

5.0 92 

46 

5.2 

5 KM 

Figure 3. True-amplitude-processed seismic profile for part of USGS line 32. Note the spatial variation of blanking above the BSR (bottom-simulating reflector) and the highamplitude BSR. CMP, common midpoint. 

tr1 

en 

...., 

-

~ 

~ -z 

Cl 

...., 

:I: 

tr1 

> 

~ 

0 

c.: 

z 

...., 

0 

'T1 

Cl 

> en 

:I: 

....:: 

t1 

::0 

en 

~ 

-z 

t1 

tr1 

tr1 

't! 

~ 

> 

::0 

z 

tr1 

en 

tr1 

t1 

-

~ tr1 

z 

...., 
568 THE FUTURE OF ENERGY GASES 

difficult to estimate in regions of amplitude blanking because reflections are weak and laterally discontinuous. 

Consequently, in these areas, interval velocities calculated 

from stacking velocities are not consistently representative 

of the same geologic interval. We felt a more useful approach was to focus on the average acoustic properties of 

hydrated sediment-that is, to measure the average velocity in a zone that extended from the sea floor downward to 

the BSR, and in another zone about 300 milliseconds (ms) 

above the BSR downward to the BSR. Velocities are average interval velocities calculated from CMP gathers that 

were selected on the basis of a prominent BSR, the quality 

of iso-velocity plots of routine stacking velocities, and the 

seismic character (primarily blanking) of the stacked data. 

Our amplitude analysis was also done in these same 

two zones: either the interval between the sea floor and the 

BSR, or the 300-ms thick section immediately overlying 

the BSR. Amplitude changes are based on calculations of 

the median reflectance, which we define as the absolute 

value of the reflection coefficient, or the envelope amplitude calibrated by the reflection coefficient. The reflection 

coefficient can be estimated from the behavior of the 

water-bottom multiples in the seismic data. Our analysis 

shows that the water-bottom reflection coefficient decreases with increasing water depth (Lee and others, 1991 ). The 

median reflectance calibrated by the reflection coefficient 

also systematically decreases with increasing water depth. 

Thus, we correct the median reflectance to a reference 

water depth, which is arbitrarily set at 3-s two-way time(s) 

in this analysis. 

The details of amplitude variation near the BSR can be 

examined using plots similar to those shown in figure 4. In 

these plots, each dot represents the amplitude in an 8-ms 

window for five consecutive CMP's. The solid line is the 

five point median of the average amplitude of five consecutive CMP's. In other words, the solid line is the running 

average of reflection amplitudes over a moving window 

that is 32 ms in duration vertically by five CMP's horizontally. The decibel (dB) scale was computed on the basis of 

the most convenient reflection coefficient for the plots. We 

use 0.4 for observing the combined Blake Ridge data, but 

we use a more convenient value (0.1) for the models; therefore, we can get an absolute value of the reflection coefficient (that is, reflectance) directly from the plot. Although 

the magnitude of reflectance varies with the degree of interference and frequency content on band-pass-filtered seismic 

sections such as those used in this study, it is a useful 

quantity in comparing relative reflection strength between 

seismic lines or along the same line. 

The velocity and amplitude analyses can be combined 

via inversion theory by estimating the detailed interval velocity based on seismic amplitude and phase (Lindseth, 

1979; Cook and Schneider, 1983). Seismic inversion involves computing velocity values from seismic amplitude, 

assuming a constant bulk density for the subbottom sediments. Results from DSDP site 533 showed that lithology 

and bulk density, where measured, changed little downhole between about 50 m and 400 m (Sheridan and others, 

1983); hence the assumption of constant density is probably valid at least for the upper 400 m of the sub-sea-floor 

section. Because seismic data generally lack low-frequency information (less than 5 Hz), the inversion method provides band-limited impedances, or velocities, from which 

only local velocity variations can be estimated. To get the 

absolute interval-velocity values, the missing low-frequency component of velocity was provided by the detailed 

analysis of stacking velocity, according to the method of 

Lindseth (1979). The results of the inversion for USGS 

line 32 are given in figure 5. 

RESULTS 

VELOCITY 

The marked difference in elastic properties between 

gas hydrates and liquid water is the physical basis for our 

analysis of the acoustic properties of hydrated sediment. 

The acoustic properties of gas hydrates are similar to those 

of ice. The compressional velocity of naturally occurring 

biogenic (methane) gas hydrates is about 3.3 km/s (Sloan, 

1990) and its density is about 0.9 g/cm3, whereas the velocity of the interstitial water is about 1.5 km/s and the 

density is 1.0 g/cm3. The compressional velocity of hydrate-bearing sediment is therefore higher than that of 

water-bearing sediment for a given porosity. Because the 

velocity of gas hydrates is greater than the interstitial 

water, the cementation of sediments by gas hydrates increases the velocity of the sediment for a given porosity. 

Because the hydrate formation substantially increases the 

rigidity of the sediment, a more pronounced effect is expected on the shear-wave velocity for hydrated sediment. 

However, little data exist for shear-wave velocity in hydrate-bearing sediment. We thus restrict our analysis of interval velocities to estimates based on compressional-wave 

information. 

Average interval velocities versus two-way traveltime 

through subbottom sediment at representative CMP's for 

six of the multichannel seismic lines in the Blake Ridge 

area are shown in figure 6. In this figure, each Jetter denotes the average interval velocity between the sea floor 

and the BSR calculated for several CMP's from each line. 

For comparison, the average interval velocity versus subbottom depth, based on DSDP drilling results reported by 

Carson and others (1986), is indicated by the solid line; 

the dots indicate average interval velocities versus subbottom depth derived from refraction data along the western 

North Atlantic continental rise (Houtz, 1974). The average 

velocity measured by Houtz (1974) is higher than that determined by Carson and others (1986) for drill cores and is 
ESTIMATING THE AMOUNT OF GAS HYDRATES IN DEEP MARINE SEDIMENT 569 

generally higher than the interval velocities estimated from 

the multichannel reflection data. The higher average velocity of the refraction data of Houtz (1974) probably reflects 

acoustic anisotropy of marine sediment, because most of 

the propagation path for the Houtz data is parallel to the 

bedding planes. Our analyses use interval velocities based 

on virtually vertically traveling waves of multichannel reflection returns. 

Figure 6 shows that the average interval velocities 

in the Blake Ridge area are similar to those of marine 

m 

~ 

0 

-10 

w -20 

0 

z 

~ () 

~ -30 

LL 

w 

a: 

-40 

-50 

0 

-10 ' 

w -20 () 

z 

g 

w 

_.J 

LL 

w 

a: 

-30 

WB 

'· " z 

S2 

z 

BSR 

/ 

A 

WB 

" 

:5. ,. co! 

LL '• 

0 :' 

,i ~ . .... o .. :' ': I ;f· · ··. N ·· ... 

···,,I .~,: ._ 

': i 

4.5 5.0 5.5 

BSR 

" z 

S2 

z 

:5 

co 

LL 

.; 0 

w ... :· z 

2 

. . .. · . ~ ··, . : . . .... 

.. / 

·~· .. ·,. .. : :: . ~ I 

,, ... 

-40 :··.: .. ·.·· 

. ~ . -~ 

... . ~ 

..... 

. ,' 

6.0 

TIME, SEC. 

CMP 890-894 

! .. . :. ·~. 

6.5 7.0 

CMP 1 000-1 0004 

0.4 

0.1 

0.025 

0.006 

7.5 

0.4 

0.1 

0.025 

0.006 

0.001 

-50~--k_-L~--~~~--~~----~~~~~~~~~~~~~~~ 

5.5 7.5 8.0 B 4.5 5.0 6.0 

TIME, SEC. 

6.5 7.0 

Figure 4. Graphs showing amplitude analysis for selected CMP (common midpoint) intervals for USGS line 32 (shown in 

fig. 3). Each dot represents the amplitude of an 8-ms window and the solid line represents a five point running median of 

five consecutive CMP's. WB, water bottom. A, CMP's 890-894; B, CMP's 1000-1004. 

w 

() 

z 

~ () 

w 

_.J 

LL 

w 

a: 

w 

() 

z 

~ () 

w 

_.J 

LL 

w 

a: 
CMP 

1124 1070 1016 962 908 854 

4.0 

2.5 

4.2 

SEAFLOOR 2.4 

2.3 

4.4 

2.2 

2.1 

4.6 ~ 

0 2.0 E 

~ w 

~ en 

w 1.9 § :::::IE 

i= 4.8 w 1.8 > 

1.7 

~.0 

1.6 

1.5 

5.2 

5 KM 

Figure 5. Detailed interval velocities created by linear inversion of data shown in figure 3. CMP, common midpoint; time given in seconds; velocity given in kilometers per 

second. 

Ul 

-...J 

0 

....., 

::z:: 

m 

"1'1 

c:: 

....., 

c:: 

;;d 

m 

0 

"1'1 

m 

z 

m 

;;d 

0 

-< 

0 

;... 

Vl 

m 

Vl 
ESTIMATING THE AMOUNT OF GAS HYDRATES IN DEEP MARINE SEDIMENT 571 

--- 1---t--' -- --t-1- 1----- -t--·1--t--- -t-t---

-t-1---- ------~-- t--t-------

t-1-- -t--- ~- --- 1-t-- --t-- 1---r--

19~-+-r+-~-+-r~t-~~~+-~-+~+-~-+L~ I~ 

- ----------- -!---- lu -~-J ---

t--- -+-+-+-+--+ -= =~ o I - ------ __ 4_ -- -f+ ~ 1.8~-+-r+-~-+-r+-~~~~+-~-+~+-~~~ "' 1--t--t--- 1---t-t---t--t-1 ~~ pFI- B - V g +-1-t--tro--riF I~ F Vv--1--8--l--+-!--

9 -1---'--'--- --1--t- -1--+--+· - - t--hl<:- - ··t::e!7'1---

~ 17r-~t---+·-~-~--r--~---+'---t--~~-~t+~~~~~~~~-+---~-~--J+ __ -~-- -~-c--,.. 1.---'IC I~ c - --·- -- -+-+-+-t--1-+-+-+-6--r~---'"' ...E R 

--t--+--t--t-e--lv---1>4v--+-+ ~-+--E::-1·-+ +---- --- ---- -,----~~-~-t--t-- r~ ---

16 ._......... ~ 

+-+---t-+~-1-+-!--+~ 

-l----t--t-+-+- !--+-++-+-+ -+--~---+---+ --+---t-+-t--+-1-t--1--- 1

-----

+--t---t-t-+ j-+--t---t--1--+ 1--t--t---1---+ +-+-+--+--1 r=:=:= 15~~~~~~-L~L-~-L~~~-L-L~~~~ 

02 04 06 08 1.0 

TWO-WAY TRAVELTIME, SEC. 

Figure 6. Average interval velocity (in kilometers per second) 

determined by conventional stacking-velocity analysis versus 

two-way traveltime (in seconds). Solid line is average curve by 

Carson and others (1986) and dots are average velocity by Houtz 

(1974). Each letter represents values of average velocity between 

the sea floor and bottom-simulating reflector for common midpoints along six seismic profiles. A, B, C, D, E, and F denote 

TD2HI, TD2HG, BTl, BT8, Gilliss line 2, and USGS line 32, 

respectively. 

sediment estimated by Carson and others (1986). In the 

Blake Ridge area, the BSR typically occurs at about 600 

ms two-way subbottom tniveltime. If hydrates constitute a 

significant component of the Blake Ridge sediment, a noticeable increase of interval velocity would be anticipated 

in the sedimentary section above the BSR. However, we 

found no significant increase of average interval velocities 

on any of the seismic profiles (within the limitations imposed by the maximum 260 m/s uncertainties discussed 

later in the "Relation Between Velocity and Amplitude" 

section). Possible explanations for this are described 

below. 

I. The average concentration of gas hydrates in sediment is small, so the effect of gas hydrates on the seismic 

velocity measured by conventional stacking velocity analysis of multichannel seismic data may not be detectable. The 

gas hydrates could be finely disseminated throughout the 

sediment, and thus the change in bulk physical properties 

would be minimal. 

2. The occurrence of hydrated sediment is highly localized in thin layers or in patches, so it does not significantly 

affect the average velocity of subbottom deposits. 

3. The length of streamer or detector offset (approximately 3.6 km) is not large enough to resolve small increases of interval velocity in deep water in the range of 3- to 5-s 

two-way traveltimes (2,250-3,750 m). 

4. Localized differences in stratigraphy and lithology, 

data acquisition, and processing techniques might obscure 

true subbottom velocity relations. For example, the interval 

velocities for Gilliss line 2 (letter E, fig. 6) are always less 

than the average curve by Carson and others ( 1986), whereas the interval velocities for USGS line 32 (letter F, fig. 6) 

are mostly greater than the average velocity even though 

these two lines are closely spaced parallel seismic lines (fig. 

1). This discrepancy could be partly due to the difference in 

field acquisition, that is, using a 1.2-km streamer for Gilliss 

line 2 and a 3.6-km streamer for USGS line 32. 

So far, our analysis suggests average interval velocities 

from multichannel data are not diagnostic in estimating hydrate concentrations in the Blake Ridge area. 

AMPLITUDE 

Amplitude variations associated with the presence of 

gas hydrates are pronounced in the Blake Ridge area. Figure 3 shows the amplitude of reflected energy along part 

of USGS line 32. A low-amplitude, or blanking, zone is 

just above the BSR; the thickness of this zone of blanking 

varies spatially. Amplitude blanking above the BSR is 

common throughout the area and suggests that wherever a 

BSR is recorded, a corresponding amplitude blanking zone 

will be detected immediately above it. This does not imply 

that all blanking zones correspond to hydrated sediment. 

The average seismic amplitude immediately above the 

BSR is small, as shown in figure 4; the reflectance of this 

zone is less than 0.01. The zone of blanking is wider for 

CMP's 1000-1004 (fig. 4B), than for CMP's 890-894 (fig. 

4A), in agreement with the seismic section shown in figure 

3. The blanking has a transitional character for CMP's 

1000-1004, but it is a sharp change for CMP's 890-894. 

The average amplitude for the section between the water 

bottom and the BSR is about -30 dB, which is a reflectance of about 0.0125, for CMP's 1000-1004 and about 

-24 dB (reflectance of 0.025) for CMP's 890-894. If the 

amplitude blanking indicates the presence of gas hydrates, 

then figures 3 and 4 suggest that a thicker zone of hydrated sediment occurs near CMP 1000 than near CMP 890. 

Also, the differences in reflectance may be related to the 

amount of hydrate present in the sediment. 

RELATION BETWEEN VELOCITY 

AND AMPLITUDE 

To assess the relation between amplitude blanking and 

interval velocity, a composite plot, shown in figure 7, for 

the interval velocity derived from stacking velocities versus 

median reflectance (using a reference reflectance of 0.1) for 
572 THE FUTURE OF ENERGY GASES 

MEDIAN REFLECTANCE 

- . 1- ··+-+-1---t-+-t--+· ;·--- ·+-+-

-c-f--- -- - Hc--+-+-+-+-+-H-t-t--t--+-i 

-· . - -+-+-+-+-f-+-+--+-+ - ---- -

- -- -- ·+-- - r---r--- . -+-· -· - Lc. 

u -t--+-+-t-t---+-t--+-1 

H--+-+-1f--+~1-t-+"' · - 13· --r--- -~·---t-t--+-t-t-+--l 

~- * lo::- ·-

r--~~--~-~r--- --~~---r-r--

(/) 1 9 * ~ . f-f-1--- - +- .. ~~-- -- .E' -r-r- --+-1---+-+--l 

~:· H-+-+-+--+--1--~r-- - 1--IF- - - - --t-l-+·-1---+-+- --f--1--

o 1--+--++-H-41-'l!"t---+--t-Hrl---+-+--t--t-t-t-t-- - -+-1-+-l s A IFI 

~ 18~-+~~·~+-~1(~\~~~-r,_+-~-f-+-r+-+-~_, "' I~ H-+-l*r+-+-+- ~-----r;:r-- ---- E 

.'" 

" 1.7 h

1

,.rt-+-+-GH-+-r+--l-H-t-t-++-HH-+-+++-H--1 

H-+---+-1--t-+-t-- r--- r-'--

+--+-t-t-+-+--+- ·-f-- - .. t-- -· .. ,- - - -· t- -. - ;- .. 

f--t---·- r-r--- 1.6 ~-++++---hl-f-+-+-+-+-H-t-+,_+-~H-+-+-H 

1---+-+-+-+-t-t -+-++-H-+--+++-++ -+-+-H-+-t---+·-

H-+-t---+--t-+-t--t-+-+ +-+--l--t-1---t -f-- -1---- - _,_ 

15 ~~_L~-~5-0L-~~--10LO~L-~--1~5-.0~~~--20L.0~~~~-250 

MEDIAN REFLECTANCE (dB) 

Figure 7. Relation between average interval velocities (from 

stacking velocities) estimated from a zone about 300 ms above 

the BSR (bottom-simulating reflector) downward to the BSR 

and median reflectance in this zone. Each letter represents values from CMP's (common midpoints) on six seismic profiles: 

A, B, C, D, E, and F represent TD2HI, TD2HG, BTl, BT8, 

Gilliss line 2, and USGS line 32, respectively. Asterisks (*) 

represent the theoretical relation between velocity (in kilometers per second) and relative median reflectance (or blanking) 

measured in decibels derived from model 4. Circled point C is 

the velocity-reflectance value closest to DSDP site 533. 

a window about 300 ms above the BSR was prepared. The 

maximum amplitude variation for a given interval velocity 

is about 15 dB at an interval velocity of about 2,000 m/s, 

and the interval velocity changes between 1,700 m/s and 

about 2,100 m/s for the median reflectance of 0.025 (about 

-13 dB point). 

Many factors can contribute to the large scatter of interval velocity versus median reflectance. These factors are 

described below. 

1. Lateral variations in stratigraphy, lithology, and hydrate concentration in the Blake Ridge area are probably 

not large, but small variations could certainly contribute to 

the observed scatter. 

2. Differences in the source's original frequency content can affect median reflectances. 

3. A bulk bias in the reflection amplitude may exist for 

each line because of inaccurate water-depth corrections in 

the median reflectance calculations. 

4. Difficulties in picking arrival times can affect estimated interval velocity determinations. 

5. Variable length-of-time windows used in the velocity 

analysis can affect interval velocities because there are 

no laterally continuous reflection events to guide velocity 

picks. 

6. Because of deep water and low interval velocities of 

hemipelagic sediment, the streamer length used may not be 

sufficiently long to extract accurate interval velocity measurements from stacking or root-mean-square velocities, resulting in a lack of resolution. 

The accuracy of picking root-mean-square velocities 

was in the range of 10 m/s. Based on the first-order theoretical equation by Hajnal and Sereda (1981 ), the uncertainty 

of a 10 m/s root-mean-square velocity introduces a maximum uncertainty of interval velocity of 260 m/s. However, 

numerical computations indicate that the uncertainty of interval velocity is typically in the range of 70 m/s. Also, 

factors 4 and 5 easily introduce 50 m/s velocity changes by 

slightly changing the reflection arrival times. The overall 

uncertainty for the interval velocity is difficult to estimate, 

but the interval velocities shown in figure 7 contain large 

uncertainties. The important observation from figure 7 is 

that the average interval velocity of the section immediately 

above the BSR, which is presumably mostly hydrated 

sediment, varies between 1,700 m/s to 2,000 m/s and the 

median reflectance varies between 0.05 and 0.01. This observation is used to build our working model for estimating 

the amount of gas hydrates in deep marine sediment. 

A second method to compare velocity and reflection 

amplitude inverts the amplitude information for velocity, as 

shown for USGS line 32 in figure 5. This f}gure reveals that 

the high-amplitude BSR reflection arises from the presence 

of a low-velocity layer (green color at the BSR level), an 

observation consistent with the presence of free gas trapped 

beneath the base of the hydrate stability zone, which is 

delimited by the BSR (Dillon and Paull, 1983). In the section above the BSR, the region near CMP 890 shows a 

thicker low-velocity zone (green above the BSR) than the 

region near CMP's 1000-1100; this difference implies that 

less hydrate exists near CMP 890 than CMP 1100. This 

result agrees qualitatively with the amplitude blanking (fig. 

4) near CMP 890, which has a smaller reflectance (representing less hydrate concentration) than that near CMP 

1000 (representing more hydrate concentration). 

SUMMARY 

Based on the analysis of six seismic profiles from the 

Blake Ridge area, we can make the following statements: 

1. The amplitude of seismic reflections within the hydrate stability zone is generally much lower in the area 
ESTIMATING THE AMOUNT OF GAS HYDRATES IN DEEP MARINE SEDIMENT 573 

where there is an observed BSR. Accordingly, amplitude 

blanking may be a useful seismic attribute related to the 

presence of gas hydrates. 

2. On the basis of stacking-velocity data, the average 

interval velocities of subbottom sediment between the sea 

floor and the BSR are similar to the average interval velocity of nonhydrate-bearing marine sediment. This observation implies that even though hydrated sediment 

is present in the Blake Ridge area, the amount of gas 

hydrates may be small. It is important to keep in mind, 

however, that the interval velocities are based on rootmean-square velocities, which are associated with large 

uncertainties (as much as 260 m/s). 

3. Although precise velocities are difficult to determine, the velocity structure derived by the inversion method shows a close correlation to the pattern of median 

reflectance (for example, compare figs. 3 and 5). Thus, we 

believe that these parameters may be fundamentally related, and we propose seismic amplitude can be used to estimate the amount of gas hydrates in the Blake Ridge area. 

4. The interval velocity of the lower part of the section varies between 1,700 m/s and 2,000 m/s and the median reflectance varies between 0.05 to 0.01. 

PHYSICAL BASIS FOR MODELING 

HYDRATES 

How the presence of gas hydrates affects seismic velocity of slope sediment is not currently known. Timur 

( 1968) first proposed a three-phase time-average equation 

to explain the velocities of compressional waves in various consolidated rocks measured at permafrost (subzero) 

temperatures. Pearson and others (1983) applied the equation to hydrated rock and concluded that it qualitatively 

explains the known sonic properties of hydrated sediment 

in consolidated media. They used the following threephase time-average equation for the velocity: 

where 

v 

p 

Q>{1- S) Q>S {1- Q>) 

----+-+---

vw vh vm 

(I) 

V Pis compressional velocity of the hydrated sediment, 

vh is compressional velocity of the pure hydrate, 

V w is compressional velocity of the fluid, 

V m is compressional velocity of the matrix, 

Q> is porosity (as a percent), and 

S is concentration of hydrate in the pore space (as a 

percent). 

Several workers have demonstrated that the observed 

velocity behavior of normal (that is, unhydrated) rocks is 

not always consistent with the predictions of the timeaverage model. Four of the conditions causing discrepancies are: (1) if the rock is unconsolidated or lightly 

cemented (Wyllie and others, 1958), (2) if the rock contains a significant amount of organic material (Timur, 

1968), (3) if the rock contains a significant amount of clay 

(Castagna and others, 1985; Eberhart-Phillips and others, 

1989), and ( 4) if the rock contains secondary porosity, 

such as fractures (Wyllie and others, 1958). The fourth 

condition pertains to crystalline or other consolidated 

rocks and is not relevant to most slope sediments. The first 

three conditions, however, apply to sediments on the 

Blake Ridge-they are unconsolidated, contain about 50 

percent clay, and have organic carbon content that ranges 

from 0.5 to 1.4 percent (Sheridan and others, 1983; K venvolden and Barnard, 1983 ). To accommodate these conditions, some workers have applied correction factors to the 

time-average equation (Asquith and Gibson, 1982; Castagna and others, 1985). 

The interval velocities computed from the time-average or modified time-average equations did not fit the observed interval velocities obtained from DSDP samples in 

the Blake Ridge area. We propose an equation of interval 

velocities for marine hydrated sediments using the approach of Nobes and others (1986), who computed the interval velocities of marine sediment by a weighted mean 

of the time-average equation (Wyllie and others, 1956) 

and Wood equation (1941 ). The Wood equation is approximately valid for particles in suspension, and is defined as: 

where 

V is compressional velocity of sediments, 

p is bulk density of sediments, 

Pw is density of the fluid, and 

Pm is density of the matrix. 

(2) 

Like the three-phase time-average equation, the Wood 

equation for hydrated sediments can be written as: 

where 

Ph is density of the pure hydrate. 

The proposed equation for the interval velocity for hydrated deep marine sediment is a weighted mean of equations 

1 and 3; that is, 

v 

p 

WQ>{1-S) 1-WQ>{1-S) ----- + ------

VI V2 

(4) 

where VI is the Wood velocity, V 2 is the Wyllie velocity, 

and W is a weighting factor. When S=O, in the case that 

there is no hydrate, equation 4 is identical to the equation 

of Nobes and others (1986). As the porosity decreases, 

equation 4 approaches the three-phase time-average equation of Pearson and others ( 1983). 
574 THE FUTURE OF ENERGY GASES 

The relationship between compressional velocity and 

porosity for unconsolidated sediment sampled by DSDP 

on the U.S. Atlantic continental rise (table 1) is shown in 

figure 8 together with theoretical curves of Wood (1941), 

Wyllie and others (1958), and equation 4 with W=l and 

S=O. The matrix velocity is set equal to the value of the 

velocity for zero porosity and 65 percent clay content, 

4.37 krnls (Castagna and others, 1985). For higher porosity rocks, equation 4 is closer to the Wood equation, 

whereas for lower porosity rocks, equation 4 is closer to 

the time-average equation. As indicated in figure 8, equation 4 with W = 1.0 fits the observed interval velocities 

quite well for porosities greater than about 40 percent. 

Therefore, we used W=l.O for our model. 

- ----+--+-+-1--1--1--l--f-1-l-1--1---l ---,H-+-1--1-+--f---cl--l 

~ -- ------ -

-----------

----- ----

4.0 ~ -- -.- ---1---1- -~--=~~-=-~~+---__j~-1-1--1 -~= -1-+-

r-~r-- 1-1-f-- -f-f--~ - -r-- - -

3.5 =l 1\-,+:-,+---+~-1-~ --\ --- -- -- --

-- -\-\ -- -- ----- --

r-r-----\-t-' \, \1-l-----l-+-+.c--l- +~--1--l--f-+---i-f-+ -

\ -1--i-t---t----l 

~ 3.o I ,_,\\t-+-\"d--hrio--+-- - - --- - - _ - -- ,_ _ 

2 I ':. \.," be- ~ - ,--'Y.i--~ 8 '---t-·- - ---' ,c 4-~H- uJ \ \11' }. > 2.5 \ ' 

---

---

---- --t---t----t--1--t-+--1 

a' \: -.------~;;:-- .. -- - - -- --- -- -

1-- - --j\-, ,_:: - -t-+-t-1 

- ---1--\ -- - --l\i!'---1--ol-~~- I -I- Tt\1---: -~~ ' ' -K_-- --1---r:-~-- - r:--=~-

~~--~~~~~~ ~~. -• ~ -1-1---1-

f---- " l' .• l~ - -~r----..--- - -1--

1- I '- o 'Iii'.., ·- -t---1~'-------i''-d---1--/---t---l 1- --+-+-f-4- -1---1-"1"'-'~of--!tl· I~ .. ·L~ ·~~lo:...~-- h-1---.-l--1---1--~'-"f'--1-+---l 

1.5 1- - +- +-++~--l---+-~:_l~~~~~~~f-~~~~~~~~·~~~ttj -- :::::::. 

i---i--1---1---t--1---l--1---~ 

1---t-l--t--1---l--l--1---t-l--1 +-+---1--1--l---t-- --- -- --- --

1-r-- -+-+---t-+-H-+-+-1-j--l---1--l--1---1-W-- ---c-c-i----+-t--1 

1-r-- ---t-H-l--++-+-1-- 1---l---1-W-1---1--l--1-1 +-+-+---ic-cPOROSITY,% 

Figure 8. Relation between compressional velocity, in kilometers per second, and porosity (symbols), in percent, for unconsolidated sediment on the U.S. Atlantic continental rise from 

DSDP sites listed in table I and predicted curves (solid lines) 

for velocity-porosity relations calculated using the Wood (1941) 

equation (curve a), time-average equation (curve b), and average equation (curve c)-see text for discussion. Source of porosity-velocity values is DSDP CD-ROM data set, NGDC-03, 

produced by NGDC with support from the U.S. Science Support Program of the Joint Oceanographic Institutions, Inc. 

Table 1. The location of DSDP sites on Atlantic continental rise. 

[Compressional velocity and porosity of sediment sampled at these 

DSDP sites were used in this analysis] 

DSDP site Latitude Longitude 

101 25° II' 55" N 74° 26' 18" w 

103 30o 27' 4" N 75° 34' 59" w 

104 30° 52' 20" N 74° 19' 38" w 

105 34° 53' 43" N 69° 10' 23" w 

384 40° 21' 38" N 51° 39' 47" w 

385 37° 22' 10" N 60° 9' 26" w 

390 30o 8' 32" N 7~0 6' 44" w 

390a 30° 8' 32" N 76° 6' 44" w 

391a 28° 13' 36" N 75° 37' 0" w 

391c 28° 13' 36" N 75° 37' 0" w 

417a 25° 6' 37" N 68° 2' 28" w 

418a 25° 2' 5" N 68° 3' 26" w 

418b 25° 2' 4" N 68° 3' 27" w 

A knowledge of both velocity and density is required 

to understand and model reflections. To derive density, we 

can use the weighted average of constituent components. 

That is, 

where 

Pp is bulk density of the hydrated sediment, 

Ph is density of the pure hydrate, 

Pw is density of the fluid, and 

Pm is density of the matrix. 

MODELS 

(5) 

If amplitude blanking is a seismic attribute related to 

gas hydrates concentration in slope sediment, can a relation between interval velocity, reflection amplitude, and 

hydrate concentration be established? To answer this question, we investigated simple one-dimensional models. Our 

objective was to construct a model in which amplitude 

blanking increases as interval velocity (and therefore hydrate concentration) increases, in accordance with the observations presented earlier. Significant blanking must also 

occur at relatively low interval velocities. 

For the first three models, we assume that hydrate 

forms only in the pore spaces of the sediment. In other 

words, 0 percent hydrate means no hydrate exists in the 

pores, 50 percent hydrate means 50 percent of the pore 

space is filled by hydrate, and 100 percent hydrate means 

all of the available pore space is filled by hydrate. We then 
ESTIMATING THE AMOUNT OF GAS HYDRATES IN DEEP MARINE SEDIMENT 575 

define a geologic boundary (reflecting horizon) across 

which porosity and (or) lithology change(s). The velocity 

of the sediment on either side of the boundary can be calculated for all values of hydrate concentration (0-100 percent) using the average equation (equation 4). The density 

of the sediment can be derived using the weighted proportions of the constituent components (equation 5). Typical 

values for parameters in the average equation are given in 

table 2. From the velocity and density values, the normal 

incidence reflection coefficient at the boundary without 

hydrate cementation is: 

R 

p2V2-p1VI 

P1 V 1 + P2 V 2 

(6) 

where R is the reflection coefficient; subscript 1 denotes the 

upper medium, and subscript 2 denotes the lower medium. 

Likewise, the reflection coefficient across the boundary 

with hydrate concentration is: 

R 

(p2)'(V2)'- (p1)'(V1)' 

(p1)'(V1)'+ (p2)'(V2)' 

(7) 

where Rh and the prime indicates the properties of the 

sediment containing hydrate. 

The amplitude ratio y, which is a m·easure of the 

amount of blanking, is therefore: 

y (8) 

The best-fit model is one in which y decreases from 1 to 

some small value as interval velocity and hydrate concentration increase. The highest value of y corresponds to 

when the amount of hydrate present is too small to affect 

the reflection coefficient. The lowest value of y corresponds to when the amount of hydrate is high enough, 

both above and below the horizon, that concentration occurs and the reflection across the horizon is blanked. In 

summary, the amplitude ratio is a comparison between the 

value of the reflection coefficient from a boundary within 

sediment that is hydrated and the value of the reflection 

coefficient from a boundary within the same sediment that 

is lacking hydrate. 

MODEL I-POROSITY AND HYDRATION 

BOUNDARIES 

This model causes a reflection at a boundary that is 

both a porosity and hydrate discontinuity. Figure 9 shows 

the velocity, density, and amplitude ratio with respect to 

Table 2. Physical property values used in the model study. 

[Values for Pm and V m vary as specified in the text] 

Pm = 2.7, 2.73 g/cm3 

Ph= 0.9 g/cm3 

Pw = 1.0 g/cm3 

V m = 4.37, 4.8 km/s 

vh = 3.3 km/s 

Vw = 1.5 kmls 

(jl = 45 - 62.5 percent 

(matrix density) 

(hydrate density) 

(water density) 

(matrix velocity) 

(velocity of pure hydrate) 

(velocity of water) 

(porosity) 

the hydrate concentration for an upper layer and lower 

layer characterized by the values given below, and other 

parameters given in table 2. 

Q> 1 =50 percent, Q>2=45 percent, V m=4.37 km/s, 

and Pm=2. 7 g/cm3 

This results in two layers of sediment with the same lithology (matrix density and velocity) that differ only in porosity percent. Hydrate fills the pores in the same percentage 

above and below the boundary, so that the end result is 

slightly more hydrate in the upper layer (highest porosity) 

than in the lower layer. Figure 9 shows an amplitude decrease (blanking) that is proportional to the hydrate concentration (dashed curve), but the amplitude loss is very 

small. For example, a I 00 percent filling of the pore space 

by hydrate, which indicates 50 percent hydrate in the sediment of the upper layer and 45 percent hydrate in the 

lower layer, the amplitude ratio is still greater than 0.5. 

The interval velocity at 100 percent saturation approaches 

about 3.8 km/s and densities are decreasing with increasing concentration because of the hydrate's low density. 

This model predicts only a small amount of blanking, 

which is quite different from what is shown by the real 

data as shown in figure 7. 

MODEL 2-POROSITY BOUNDARY AND 

CONSTANT HYDRATION 

Model 2 is similar to model 1 in causing a reflection 

to occur at a porosity boundary with Q>2=60 percent and 

Q> 1 =50 percent, but in this model, we assume that the total 

amount of hydrate is constant across the boundary. For example, with total hydrate equal to 25 percent of the sediment, layer 1 would have 42 percent of the pore space 

filled (0.42x0.6=0.25), whereas layer 2 would have 50 percent filled (0.5x0.5=0.25) The result of this model indicates a decrease of amplitude at the reflection boundary, 

but the rate is much slower than that of model 1. 
576 THE FUTURE OF ENERGY GASES 

0.8 

0.6 

0 

~ 

~ 

~ 

~ 

~ 0.4 

0. 2 

0. 0 

--- ---- --- -"----::. 

-------,--1-·-

/ 

v2 ...... 17 

7 -::<: ./ / 

v v 

/ / 

~~ t-# ', "~'>(/?; ---- - J(.o~; 

-,-9~n r'/ -- / --- // ' )f/ 

---- --w e----"" --

1', 

7 ' ' 

V/ 

/V 

V/ 

/ v --- --

/ 

v1 

,II '2-

t,/ 

---

-- ---

1---

4 .0 

3.4 

I 2.8 ~ 

Ui 

z 

w 

0 

5 

~ ~ 

~ 2.2 0 

1.6 

1.0 

g 

w 

> 

~ 40 W M 100 

HYDRATE CONCENTRATION(%) RELATIVE TO THE PORE SPACE 

Figure 9. Computed velocity and density (solid lines) and amplitude blanking (dashed line) relative to percent of gas hydrate filling pore spaces of sediment above and below a reflecting 

interface defined as a porosity boundary. V and p denote compressional velocity and density, respectively; subscripts 1 and 2 

denote upper medium and lower medium, respectively (4>1=50 

percent, <j> 2=45 percent). In this model, the amount of hydrate 

above and below the interface varies directly with porosity. 

MODEL 3-POROSITY AND LITHOLOGIC 

BOUNDARY 

This model assumes that a reflection occurs at a lithologic boundary characterized by a change in both matrix 

velocity, matrix density, and porosity. We assume that hydrate concentration is proportional to the porosity across the 

boundary, which means that the relative concentration of gas 

hydrates with respect to the porosity is the same. As in 

model 1, this means that if the same percentage of pore 

space is filled in layer 1 as in layer 2, resulting in different 

total hydrate concentrations. The justification for using different matrix velocities can be understood by considering the 

difference of clay content in marine sediment. In this model 

the lower layer has less clay content than the upper layer. We 

use the following acoustic properties for this model: 

For upper layer 

Vml=4.37 km/s 

Pm1=2.7 g/cm3 

<j> 1= 60 percent 

For lower layer 

V m2=4.8 km/s 

Pm2=2.73 g/cm3 

<j>2=50 percent 

Similar to model 1, model 3 predicts an amplitude decrease 

with respect to increasing hydrate concentration, but the 

amplitude blanking is too small compared to our observation. For example, at 100 percent concentration of hydrate, 

the amplitude ratio is only 0.87. 

If we interchange the porosity values of model 3, that 

is, <j> 1 =50 percent and <j>2=60 percent, there is higher amplitude blanking. However, the amount of blanking is still 

less than our observation. For example, at 100 percent 

concentration, the amplitude ratio is about 0.55. 

Each of the three models is feasible in terms of hydrate cementation processes, but none predicts a high-amplitude decrease as interval velocity increases. 

MODEL 4-SEDIMENT SUBSTITUTION 

Model 4 differs from the others because instead of 

simply adding hydrate to the pores of the preexisting sediment, it replaces normal sediment with representative hydrated sediment. This model is introduced to account for 

the observed high-amplitude blanking with low interval 

velocities. The representative hydrated sediment has its 

own characteristic density, velocity, porosity, and hydrate 

percentage values. These values are determined from the 

equations presented earlier and will differ for each region 

studied. The normal sediments are considered to be unhydrated, and they are defined by a reflecting horizon, which 

results from differing lithology (density and velocity) and 

porosity (as in model 3). With 50 percent replacement by 

the representative hydrated sediment, 50 percent of the 

sediment above the horizon (layer 1) will be replaced, and 

50 percent of the sediment below the horizon (layer 2) 

will be as well. The important difference between this 

model and models 1-3 is that, as representative hydrated 

sediment replaces unhydrated normal sediment, the reflecting boundary disappears at 100 percent replacement arid 

only representative hydrated sediment occurs. 

To illustrate the blanking effect by model 4, we can 

use any kind of representative hydrated sediment. We 

choose sediment with an average 57.5 percent porosity because this is what we get by solving the regression equation 4 for porosity using the lowest observed velocity 

(about 1,700 m/s from fig. 7). The lowest measured velocity represents the best estimate for unhydrated sediment. A 

porosity of about 60 percent was also measured in three 

samples from DSDP site 533 and therefore porosity of 

57.5 percent seems appropriate for the Blake Ridge area. 

We get 27.5 percent hydrate concentration in the pore 

space by solving equation 4 for S (hydrate concentration) 

using <J>=57.5 percent (porosity) and V2 of approximately 

2,000 m/s (compressional velocity of hydrated sediment), 

which was taken as the highest average velocity for hydrated sediment in the Blake Ridge area (fig. 7). The highest velocity should indicate sediment with the highest 

amount of hydrate. If we had used V p=2,100 m/s, the hy-
ESTIMATING THE AMOUNT OF GAS HYDRATES IN DEEP MARINE SEDIMENT 577 

drate concentration would be 34 percent. We prefer to use 

the lower, more conservative estimate. The uncertainty in 

hydrate concentration could be as high as 25 percent in 

this example. Therefore we have used interval velocity 

data to determine (calibrate) a representative hydrated sediment, which can be combined with amplitude ratios to 

give bulk-hydrate concentrations as described below. 

The velocity (Vhs) and density (Phs) of the representative hydrated sediment in the model are from equations 4 

and 5 with the acoustic parameters for model 1: Vhs=2.016 

km/s, Phs= I. 707 g/cm3. The acoustic properties of the unhydrated sediment are: V1=1.625 km/s, p1=1.638 g/cm3, 

<1>1=62.5 percent, V2=1.768 km/s, p2= 1.808 g/cm3, 

<!>2=52.5 percent 

Figure I 0 illustrates the amplitude ratio versus the 

percent substitution of representative hydrate sediment. In 

other words, 0 percent representative hydrated sediment 

refers to no hydrate present; 40 percent refers to the sub1 0 

' ' 

' ' 

' 

' 

08 

06 

Q 

~ u.J 

0 

:J 

t:: 

..J 

"-:; 

..: 04 

r02 

00 

0 

' 

' ' -- ' 

,~1:-

'~ ----'--.~ \ '?v...., 

','6 

' 

' 

' 

' 

' ' 

~ _, 

._v2, - -c.---

---l"--v1 ~ 

_J ' 

;I ' 1 ' ' 

20 40 60 80 

REPRESENTATIVE HYDRATED SEDIMENT,% 

3.2 6.3 9.5 12.7 

BULK HYDRATE,% 

-r------ -

-r----

f---

' 

' ' 

40 

34 

~ 28 ~ 

en 

z 

Lll 

0 

a: 

0 

! 2.2 ~ 

g 

1 .6 

1 .0 

Lll 

> 

100 

15.8 

Figure 10. Computed velocity and density (solid lines) and amplitude decrease (dashed line) relative to percent of representative hydrated sediment (57 .5 percent porosity rock with 27.5 

percent of the pore space filled by gas hydrates) that replaces 

unhydrated marine sediment across a porosity boundary. V and p 

denote compressional velocity and density, respectively (<!> 1=62.5 

percent, <Pz=52.5 percent). In this example, the amount of hydrate 

above and below the interface is identical. 

stitution of 40 percent representative hydrated sediment 

into both the upper and lower layers; and I 00 percent refers to complete replacement of the upper and lower layers 

by representative hydrated sediment. The dashed line in 

figure 10 shows that the amplitude blanking is proportional to the amount of the representative hydrated sediment. 

At 100 percent replacement, the amplitude ratio is 0, 

which is a total blanking, because all unhydrated sediment 

is replaced by the representative hydrated sediment, and, 

therefore, the reflection horizon no longer exists. The 

highest velocity in this model is 2.02 km/s, which is the 

compressional velocity of the representative hydrated sediment. This model predicts significant blanking with a low 

interval velocity. 

Amplitude blanking proportional to the amount of representative hydrated sediment in terms of relative median 

reflectance and interval velocity is shown in figure 7. This 

predicted curve is consistent with the observations in as 

much as it falls within the scatter of the data and the maximum and minimum reflectance and velocity values coincide with the maximum and minimum observed values. 

Two independent lines of evidence support the results 

of model 4. First, we used velocity information (fig. 7) to 

calculate a porosity of 57.5 percent for the model (equation 

4). This value is essentially identical to that measured in 

DSDP site 533 in an interval near the bottom of the hole 

(Sheridan and others, 1983). Second, point C (fig. 7), is less 

than the I 00 m/s away from the modeled curve, which is 

well within the accuracy of the velocity pick. This point is 

the reflectance/velocity value from line BTl closest to 

DSDP site 533, which is the only place near Blake Ridge 

where the model can be realistically calibrated. 

Once the properties of the representative hydrated sediment are calculated from interval velocity information 

and the weighted equation of the time-average and the 

Wood velocities, amplitude ratios (blanking) can be used 

alone to determine total bulk hydrate concentrations. For 

example, with an amplitude reflectance at DSDP site 533 

of 0.042 (which corresponds to an amplitude ratio of 0.5), 

we end up with approximately 52 percent sediment substitution (fig. I 0). This corresponds to 8 percent bulk hydrate 

(0.52x0.275x0.575=0.08), where the representative sediment in characterized with 57.5 percent porosity and 27.5 

percent hydrate. Using interval velocity data separately, 

from DSDP site 533, the average interval velocity is 1,800 

m!s (the midpoint between the points where curves V 1 and 

V 2 cross the I ,800 m/s value). This correlates to a bulkhydrate concentration of 5 percent in total volume 

(0.33x0.275x0.575=0.052). If the interval velocity at 

DSDP site 533 had been the same as that used in the representative hydrated sediment calibration, the bulk concentrations calculated separately from interval velocity and 

amplitude ratio would be the same. 

At DSDP site 533, methane gas was sampled and presumed to indicate the existence of disassociated gas hydrates. A single measurement yielded 13 volumes of gas 
578 THE FUTURE OF ENERGY GASES 

(at standard pressure and temperature conditions, or STP) 

to 1 volume of sediment (Kvenvolden and Barnhard, 

1983 ). Because gas hydrates concentrates methane in the 

ratio of about 160 volumes of gas (at STP) to 1 volume of 

sediment (K venvolden, 1988), the resulting value for the 

bulk volume of gas hydrates in the sediment is 131160, or 

about 8 percent, which agrees with the 5 to 8 percent prediction from model 4. Whether 8 percent is a maximum or 

only an average concentration remains uncertain, because 

it is the only measurement available from DSDP site 533. 

In summary, the amplitude information provides good 

estimates of the percent of representative hydrated sediment substituted above and below a reflecting horizon, but 

it cannot determine the concentration of gas hydrates in 

the pore spaces. Hence, amplitude information alone produces large uncertainties for the bulk volume of hydrate in 

the sediment. Interval velocity, however, yields a small 

range of values for bulk volume of gas hydrates regardless 

of the large differences in percent of representative hydrated sediment. Calibrating the bulk volume of hydrate deduced from amplitude information with the bulk volume 

calculated from velocity information provides the critical 

step in the model for determining the appropriate concentration of hydrate in the pore space. 

DISCUSSION 

We have proposed a model for quantitatively estimating the bulk volume of gas hydrates in the zone above the 

BSR. The model (model 4) relates amplitude blanking, 

seismic velocity, concentration of gas hydrates in pore 

spaces, and the concentration of representative hydrated 

sediment above and below a reflecting interface. Our results are consistent with the amplitude blanking and average interval velocities measured in the Blake Ridge area 

from multichannel seismic data and with the observation 

that a small amount of gas hydrates occurs at DSDP site 

533. This method, therefore, provides a technique for classifying and mapping gas-hydrate concentrations using a 

grid of seismic-reflection profiles. Estimates of the volume 

of hydrate (or methane) contained within the sediment 

above the BSR can be made from the hydrate concentrations. A preliminary estimate for the Blake Ridge area is 

66xi06 m3 of hydrate, or approximately 370 Tcf of gas in 

all sediment beneath each one square km of the sea floor 

(Dillon and others, 1991). A separate technique can be 

used for placing limits on the thickness of the free-gas 

zone beneath the hydrate (Miller and others, 1991). Together, these methods offer the first quantitative approaches to estimating the total amount of hydrate and gas 

locked in shallow subbottom ocean sediment. 

A troublesome aspect of our modeling exercise is that 

models based on the physical principle of hydrate filling 

intergranular pore-space (models 1 to 3) fail to explain 

why large blanking is associated with relatively low interval velocities in the Blake Ridge area. A couple of possible implications of this observation are: 

1. The average equation (equation 4) that relates the 

physical properties of the sediment and the hydrate is incorrect. Although it is beyond the scope of this paper to 

evaluate this possibility, other studies have supported the 

general validity of the time-average equation (equation 1) 

for gas hydrates in consolidated sediments (Pearson and 

others, 1983). 

2. Our supposition that hydrates nucleate and fill pore 

spaces is oversimplified. One mechanism for hydrate formation in sediments is that growth proceeds from disseminated to massive occurrences; another mechanism is that 

hydrates grow by recrystallization and annealing during 

pressure and temperature changes that accompany glaciation and eustacy (Sloan, 1990). To what extent physical or 

chemical processes control hydrate occurrence in sediments is an unsolved problem in understanding gas hydrates and warrants additional study. 

3. Our one-dimensional seismic modeling is too simple to explain the observations. For example, the models 

assume second-order (abrupt) boundaries for reflection interfaces, but the real boundaries may well be transitional. 

Because the reflection characteristics of a transitional layer 

(Justice and Zuba, 1986) are quite different from reflections of simple boundaries, additional amplitude decrease 

might be associated with transitional boundaries. We also 

assumed that whole layers are uniformly cemented by gas 

hydrates, but the cementation can vary spatially. Accordingly, three-dimensional modeling, including scattering, 

provides better approximations of reflection amplitude for 

hydrated sediments. 

Our preferred model, model 4, is unsatisfying in that 

sediment substitution probably does not occur in nature. 

However, almost nothing is known about the details of the 

natural occurrence of gas hydrates-how they are distributed in the pores, how they cement the grains, whether 

they are disseminated or concentrated in veins and nodules, and so on. We present this model because it is the 

only description that fits our current understanding about 

hydrates in deep marine sediment. That we do not know 

what the model means simply opens new directions for 

research in the physical and chemical occurrence of hydrates in sediment. 

Even though this model cannot be fully explained in 

terms of reflection seismology, our estimation method is 

based on the physical property of hydrated sediment that 

cementation in the pore space increases the interval velocity of marine sediment. Because our estimation method 

uses seismic amplitude firmly constrained by the observed 

interval velocities, the proposed method is valid and accurate in terms of amount of hydrate. 

Our preferred model can be applied to reflection data 

sets in other regions as long as certain conditions are met. 
ESTIMATING THE AMOUNT OF GAS HYDRATES IN DEEP MARINE SEDIMENT 579 

First, processing of the reflection data must preserve relative amplitudes that are calibrated relative to the reflection 

coefficient of the sea floor, and that are corrected for any 

water-depth dependence of the reflection coefficient. Amplitude preservation and calibration are inherently more 

difficult on single-channel data than on multichannel data, 

because the first multiple or other information for computing the reflection coefficient may be lacking in singlechannel data. 

Second, velocity estimates from the region of interest 

are required.· The average lowest velocity of sediment is 

used to calculate porosity (equation 4), and the average 

highest velocity of hydrated sediment is used, with porosity, to calculate the hydrate concentration. 

Third, amplitudes must be scaled to a reference reflectance. The largest reflectance for the data from the Blake 

Ridge is estimated as 0.1 (fig. 7) and, therefore the dB scale 

is based on this reference reflectance. This reference reflectance was chosen after all reflection profiles were examined, and it is a function of both the locality of the seismic 

_ profiles and the data-processing procedure. The choice of 

reference reflectance for dB scale conversion is subjective, 

but as long as a reasonable value is chosen, estimates of the 

amount of hydrate will not be affected. The reference reflectance (not the dB scale) is important for comparing amplitudes among different geographic locations and different 

seismic-acquisition and processing methods. 

Fourth, the source of hydrate should be known. Most 

methane in hydrates is biogenic and formed by bacterial 

action at low temperatures. However, some hydrate is 

thermogenic, forms at relatively high temperatures, and 

contains gases such as ethane and propane (Sloan, 1990). 

The measured compressional velocity of pure biogenic hydrate is 3.3 krn/s, whereas that of pure thermogenic hydrate is 3.8 km/s (Pandit and King, 1983). This difference 

will affect hydrate concentrations estimated in equation 4. 

Fifth, different geologic regions will almost certainly 

require different representative hydrated sediment to be 

used in the model. To select a representative hydrated sediment, choose the velocity of unhydrated sediment as the 

velocity corresponding to the highest median reflectance 

(0.1 or 0 dB in is study). For Blake Ridge (fig. 7), this 

velocity is 1,700 m/s. Estimate the average porosity of the 

ordinary marine sediment using this velocity (1,700 m/s) 

and equation 4. The average porosity for the hydrate zone 

can also be taken from drill-hole data. For the Blake 

Ridge area, both methods indicate a porosity of about 60 

percent. Estimate the highest velocity for the hydrated sediment in the area. We used a conservative estimate of 

2,000 m/s (fig. 7). Calculate the amount of hydrate concentration by substituting this upper velocity value and the 

estimated porosity into equation 4. For the Blake Ridge 

area, we calculate the concentration of gas hydrates in the 

pore spaces is 27.5 percent. Based on the above procedure, 

the representative hydrated sediment in the Blake Ridge 

area for our model is chosen as a sediment having 57.5 

percent porosity with a gas hydrates concentration of 27.5 

percent in the pore space. Now, simply using amplitude 

ratios (blanking), bulk-hydrate concentrations can be determined, such as for DSDP site 533 where the amplitude 

ratio of 0.5 gives a bulk-hydrate concentration of 8 percent 

(fig. I 0). 

CONCLUSIONS 

The primary effect of hydrate concentration on the 

acoustic properties of marine sediment is an increase in 

interval velocity. The quantitative analysis of interval velocity can be used to estimate the bulk volume of in-situ 

gas hydrates. Another seismic attribute of hydrate concentration is amplitude blanking. This phenomenon is observed in single-channel as well as multichannel seismic 

profiles. Our model assumes that the degree of amplitude 

blanking is related to the amount of gas hydrates filling 

the pore spaces of the sediment. 

We propose a method of estimating the amount of insitu gas hydrates in deep marine sediment using amplitude 

information above the BSR. Because amplitude blanking 

is a relative quantity, the estimation method must be calibrated against interval velocities. This method is based on 

measuring the degree of blanking in seismic models generated by the bulk mixture of sediment consisting of both 

representative hydrated sediment and normal (unhydrated) 

sediment. The properties of the representative hydrated 

sediment can be calculated from interval-velocity information and the weighted equation of the time-average and the 

Wood velocities. Seismic amplitudes can then be directly 

computed and related to the bulk volume of gas hydrates 

in the sediment. The mechanism by which blanking occurs 

remains unexplained. The models that simply fill pore 

spaces with hydrate underestimate the amount of blanking. 

Our preferred model (model 4, sediment substitution) is 

difficult to reconcile with known natural processes. This 

emphasizes the need for research on how the physical and 

chemical presence of hydrates in sediments alters the bulk 

properties of those sediments. 

In the Blake Ridge area, the best-fit model describes a 

representative hydrated sediment consisting of sediment 

with 57.5 percent porosity in which 27.5 percent of the 

pore spaces are filled by gas hydrates. This representative 

hydrated sediment replaces unhydrated normal sediment 

across a reflection boundary between two layers, the upper 

layer with 62.5 percent porosity and the lower layer with 

52.5 percent porosity. This model can be applied to other 

areas by selecting reasonable values for the hydrated and 

unhydrated sediments. We emphasize that the observed 

amplitude must be carefully calibrated by interval velocities before it can be used alone to determine bulk-hydrate 

concentrations. 
580 THE FUTURE OF ENERGY GASES 

ACKNOWLEDGMENTS 

We would like to thank David Scholl and Michael 

Max for very helpful and numerous comments on the earlier version of the manuscript. We thank T. Shipley and T. 

Brocher for very constructive comments and suggestions. 

This work was funded by the U.S. Department of Energy 

and U.S. Geological Survey. 

REFERENCES CITED 

Asquith, G., and Gibson, C., 1982, Basic well log analysis for 

geologists, in Methods in Exploration Series: Tulsa, Okla., 

American Association of Petroleum Geologists, 216 p. 

Carson, R.L., Gangi, A.F., and Snow, K.R., 1986, Empirical reflection travel time versus depth and velocity versus depth 

functions for the deep-sea sediment column: Journal of Geophysical Research, v. 91, p. 8249-8266. 

Castagna, J.P., Batzle, M.L., and Eastwood, R.L., 1985, Relationship between compressional-wave and shear-wave velocities 

in clastic silicate rocks: Geophysics, v. 50, p. 571-581. 

Cook, D.A., and Schneider, W.A., 1983, Generalized linear inversion of reflection seismic data: Geophysics, v. 48, p. 665-

676. 

Dillon, W.P., Booth, J.S., Paull, C.K., Fehlhaber, K., Hutchinson, D.R., and Swift, B.A., 1991, Mapping sub-seafloor 

reservoirs of a greenhouse gas-methane hydrates, in 

Kumar, M., and Maul, G.A., eds., Proceedings of international symposium on marine positioning: Marine Geodesy 

Committee, Marine Technology Society, Washington D.C., 

p. 545-554. 

Dillon, W.P., Fehlhaber, K., Lee, M.W., Booth, J.S., and Paull, 

C.K., 1991, Methane hydrate in sea floor sediments off the 

southeastern U.S.-Amount and implication for climate 

change, NE/SE Geol. Soc. Am. Meeting, Baltimore, March 

14-16, 1991, 1991 Abstracts with Programs, p. 22. 

Dillon, W.P., and Paull, C.K., 1983, Marine gas hydrates, IIGeophysical evidence, in Cox, J.L., ed., Natural gas hydrates-properties, occurrence, and recovery: Boston, Butterworth Publishers, p. 73-90. 

Dillon, W.P., and Popenoe, P., 1988, The Blake Plateau basin and 

Carolina trough, in Sheridan, R.B., and Grow, J.A., eds., The 

Atlantic Continental Margin-U.S.: DNAG Geology of 

North America 1-2, p. 19-55. 

Dobrynin, V.M., Korotajev, Yu. P., and Plyuschev, D.V., 1981, Gas 

Hydrate-a possible energy source, in Mayer, R.G., and Olson, J.C., eds., Long term energy resources: Boston, Pitman, 

p.727-729. 

Dragoset, B., Hargreaves, N., and Lamer, K., 1987, Air-gun 

source instabilities: Geophysics, v. 52, p. 1229-1251. 

Eberhart-Phillips, D., Han, D.H., and Zoback, M.D., 1989, Empirical relationships among seismic velocity, effective pressure, 

porosity, and clay content: Geophysics, v. 54, p. 82-89. 

Ewing, J.l., and Hollister, C.H., 1972, Regional aspects of deep 

sea drilling in the western North Atlantic: Initial report of the 

deep sea drilling project II, p. 951-973. 

Gray, W.C., 1979, Variable norm deconvolution: Palo Alto, Calif., 

Stanford University, Ph.D.Thesis. 

Hajnal, Z., and Sereda, LT., 1981, Maximum uncertainty of interval velocity estimates: Geophysics, v. 46, p. 1543-1547. 

Houtz, R., 1974, Preliminary study of global sediments sound 

velocities from sonobuoy data, in Hampton, L., ed., Physics 

of sound in marine sediments: New York, Plenum Press, 

p. 519-535. 

Justice, H.J., and Zuba, C., 1986, Transition zone reflections and 

permafrost analysis: Geophysics, v. 51, p. 1075-1086. 

Kvenvolden, K.A., 1988, Methane hydrate-A major reservoir of 

carbon in the shallow geosphere: Chern. GeoL, v. 71, p. 41-

71. 

Kvenvolden, K.A., and Barnard, L.A., 1983, Gas hydrates of the 

Blake Ridge, Site 533, Deep Sea Drilling Project Leg 76: 

Initial report of the deep sea drilling project 76, p. 353-365. 

Lashof, D.A., and Ahuja, D.R., 1990, Relative contributions of 

greenhouse gas emissions to global warming: Nature, v. 344, 

p. 529-531. 

Lee, M.W., and Hutchinson, D.R., 1990, True-amplitude processing techniques for marine, crustal-reflection seismic data: 

U.S. Geological Survey Bulletin 1897, 22 p. 

Lee, M.W., Agena, W.F., and Swift, B.A., 1991, An analysis of 

a unique seismic anomaly in Georges Bank basin, Atlantic 

Continental Margin: U.S. Geological Survey Open-File 

Report 91-138, 25 p. 

Lindseth, R.O., 1979, Synthetic sonic logs-a process for stratigraphic interpretation: Geophysics, v. 44, p. 3-26. 

Mark), R.G., Bryan, G.M., and Ewing, J.l., 1970, Structure of the 

Blake-Bahama Outer Ridge: Journal of Geophysical Research, v. 75, p. 4539-4555. 

Mciver, R.D., 1981, Gas Hydrate, in Mayer, R.G., and Olson, 

J.C., eds., Long term energy sources: Boston, Pitman, p. 713-

726. 

Miller, J.J., Lee, M.W., and von Huene, R., 1991, An analysis of 

seismic reflection from the base of a gas hydrates zone, offshore Peru: American Association of Petroleum Geologists 

Bulletin, v. 75, p. 910-924. 

Nobes, D.C., Villinger, H., Davis, F.F., and Law, L.K., 1986, Estimation of marine sediment bulk physical properties at depth 

from seafloor geophysical measurements: Journal of Geophysical Research, v. 91, p. 14033-14043. 

Pandit, B.I., and King, M.S., 1983, Elastic wave velocities of 

propane gas hydrates, in Cox, J.L., ed., Natural gas hydrates-properties, occurrence and recovery: Boston, Butterworth Publishers, p. 49-61. 

Paull, C.K., Ussler, W. III, and Dillon, W.P., 1991, Is the extent of 

glaciation limited by marine gas hydrates?: Geophysical Research Letters, v. 18, p. 432-434. 

Pearson, C.F., Halleck, P.M., McGuire, P.L., Hermes, R., and 

Mathews, M., 1983, Natural gas hydrates; a review of in situ 

properties: Journal of Physical Chemistry, v. 87, p. 4180-

4185. 

Sheridan, R.B., Gradstein, P.M., and others, 1983, Site Reports 

and underway data: Initial reports of the deep sea drilling 

project 76, p. 35-80. 

Shipley, T.H., and Didyh, B.M., 1982, Occurrence of methane 

hydrates offshore southern Mexico: Initial Report of the Deep 

Sea Drilling Project 66, p. 547-556. 

Shipley, T.H., Houston, M.H., Buffier, R.T., Shaub, F.J., McMillen, K.J., Ladd, J.W., and Worzel, J.L., 1979, Seismic evidence for widespread possible gas hydrates horizons on 
ESTIMATING THE AMOUNT OF GAS HYDRATES IN DEEP MARINE SEDIMENT 581 

continental slopes and rises: American Association of Petroleum Geologists Bulletin, v. 63, p. 2204-2213. 

Sloan, E.D., Jr., 1990, Clathrate hydrates of natural gases: New 

York, Marcel Dekker, 641 p. 

Stoll, R.D., 1974, Effect of gas hydrates in sediments, in Kaplan, 

I.R., ed., Nature of gases in marine sediments: New York, 

Prenum press, p. 235-248. 

Suess, E.R., von Huene, R. and others, 1988, Introduction, objectives, and principal results, LEG 112, Peru Continental Margin: Proceedings of the Ocean Drilling Program, initial 

reports 112, p. 5-44. 

Timur, A., 1968, Velocity of compressional waves in porous media at permafrost temperature: Geophysics, v. 3, p. 584-595. 

Tucholke, B.E., Bryan, G.M., and Ewing, J.I., 1977, Gas hydrate 

horizons detected in seismic-profile data from the western 

North Atlantic: American Association of Petroleum Geologists Bulletin, v. 61, p. 698-707. 

Wood, A.B., 1941, A text book of sound: New York, Macmillan, 

578 p. 

Wyllie, M.R.J., Gregory, A.R., and Gardner, G.H.F., 1958, An 

experimental investigation of factors affecting elastic wave 

velocities in porous media: Geophysics, v. 23, p. 459-493. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Biogenic Gas: Controls, Habitats, and Resource Potential 

By Dudley D. Rice 1 

CONTENTS 

Abstract ......................................................................... 583 

Introduction ................................................................... 583 

Biogenic Gas Generation ............................................. 584 

Conditions for BiogenicGas Generation ...................... 585 

Conditions for Biogenic Gas Accumulation ................ 586 

Depth and Timing of Biogenic Gas Generation .......... 587 

Characteristics of Biogenic Gas ................................... 587 

Occurrences of Ancient Biogenic Gas ......................... 589 

Favorable Habitats for Biogenic Gas Accumulations ... 590 

Deltas ..................................................................... 590 

Deep-Water Clastic Settings .................................. 594 

Shelf Setting . .. . .. .. . . .. .. .. ... ...... ....... .. ... ...... .. . .... .. ....... 594 

Clastic Shelf .................................................... 594 

Carbonate Shelf ............................................... 596 

Nonmarine Settings ............................................... 597 

Coal Swamps ................................................... 597 

Coastal Plains .................................................. 598 

Resource Potential of Biogenic Gas ............................ 599 

Deltas ..................................................................... 599 

Deep-Water Clastic Settings .................................. 599 

Shelf Settings . ... ... . . ..... .. .. . .. .... .. .... .. . . ... .. ... ... ... .. . ... .. 599 

Nonmarine Settings ............................................... 600 

Summary and Conclusions ........................................... 601 

Acknowledgments ·································:······················ 602 

References Cited .. . ...... ...... ... .. . ..... . ... .. . ....... ..... ...... ... . .. .. 602 

ABSTRACT 

As much as 20 percent of the world's natural-gas resource is estimated to have been generated by the decom1

U.S. Geological Survey, Box 25046, Federal Center, Denver, CO 

80225. 

positiOn of organic matter by anaerobic microbes at low 

temperatures. This gas is commonly referred to as biogenic 

gas. Most biogenic gas was generated early in the burial 

history of sediments. Some biogenic gas was also generated 

in relatively recent geologic time and is associated with 

groundwater flow. 

The factors that favor significant generation of biogenic 

gas are anoxic conditions, low sulfate content, low temperature, abundant organic matter, and sufficient pore space for 

the microbes to thrive. Conditions beneficial for the accumulation of biogenic gas include stratigraphic or early 

structural traps, adequate seals, low permeability, low pressure, early dissolution of the gas, and formation of gas hydrates. Rapid sediment deposition is critical to both the 

generation and the accumulation of biogenic gas generated 

during the early stage. 

Biogenic gas is distinguished by its molecular and isotopic composition. The hydrocarbon fraction is generally 

more than 99 percent methane, and the diagnostic isotopic 

composition of the methane component is as follows: 613C 

values are generally lighter than -55 parts per thousand 

(permil), and 6D values are usually in the range of -150 to 

-250 permil. This isotopic composition indicates that the 

methane generally resulted from C02 ~eduction. 

Significant accumulations of ancient biogenic gas have 

been discovered in Africa, Asia, Europe, North America, 

and South America. These accumulations occur in Mississippian and younger rocks, at burial depths as much as 

4,600 m. They are associated with a variety of rock types 

(carbonate, clastic, and coal), and occur in a variety of marine and nonmarine depositional settings generally characterized by rapid deposition. 

INTRODUCTION 

Hydrocarbon resources are enormous, but not infinite, 

and they are not evenly distributed throughout the world 

583 
584 THE FUTURE OF ENERGY GASES 

(Masters and others, 1991). Most of the conventional hydrocarbon resources occur in the Eastern hemisphere and 

in a few major petroleum provinces, such as in the Middle 

East and West Siberia. Because oil exploration is in an 

advanced stage in many countries, few discoveries of large 

oil accumulations are expected. In contrast, significant gas 

discoveries are likely because exploration for natural gas 

is at a less advanced stage. A better understanding of the 

processes that result in the generation and accumulation of 

nat~ral gas will increase the probability of successful future exploration. 

Natural gas in commercial accumulations is formed 

from organic matter and results from two distinct processes (fig. 1). At shallow burial depths and low temperatures, 

methane-rich gas is generated by decomposition of organic 

matter by microorganisms. This gas is referred to as biogenic. In contrast, thermogenic gas is generated mainly 

from organic matter by thermal degradation and cracking 

processes that occur at higher temperatures and extended 

duration of heating. Most gas produced from commercial 

oil and gas fields is probably of thermal origin. Abiogenic 

gas, which is derived from inorganic precursors in the 

deep earth, is not a major contributor to commercial gas 

accumulations. 

This paper is an evaluation of biogenic gas that was 

generated in the geologic past and which can represent a 

significant component of some commercial gas accumulations. Although biogenic gas generation is observed and 

has been studied in many present-day settings, the occurI 

w 

a: 

::J 

f-

<( 

a: 

w 

0.. 

~ 

UJ 

f--

0 

z 

<( 

w 

~ 

i= 

STAGE 

IMMATURE 

(diagenesis) 

MATURE 

(catagenes•s) 

j POST-MATUR' 

(metamorph•sm) 

PRIMARY 

PRODUCT 

DRY GAS 

OIL 

WET GASCONDENSATE 

DRY GAS 

HYDROCARBONS 

GENERATEDFigure 1. Major stages of hydrocarbon generation. Biogenic gas 

is generated at low temperatures and at relatively shallow depths. 

renee of biogenic gas accumulations in ancient sequences 

is not well documented, even though these accumulations 

represent an important and commonly overlooked energy 

resource. The objectives of this paper are to (1) review the 

process of biogenic gas generation, (2) discuss the conditions necessary for its generation and accumulation, (3) 

address the depth and timing of biogenic gas generation, 

(4) characterize the composition of biogenic gas, (5) describe worldwide occurrences of biogenic gas including 

favorable habitats for its generation and accumulation, and 

(6) assess the resource potential of biogenic gas. 

BIOGENIC GAS GENERATION 

Biogenic gas is produced by the decomposition (coupled oxidation-reduction reactions) of organic matter by 

microorganisms. The breakdown of organic matter leading 

to methanogenesis is performed by a diverse microbial 

population (Mah and others, 1977). Methanogens, assigned 

to the Archaea domain (Woese and others, 1990), only operate during the final stages of anaerobic decomposition of 

organic matter and depend on other microbes to convert 

the original complex organic compounds into simple 

compounds. 

Two primary pathways have been identified for the 

generation of biogenic gas: carbon dioxide (C02) reduction and fermentation. A detailed description of these pathways is provided by Schoell (1980), Woltemate and others 

(1984 ), Whiticar and others ( 1986). Most species of methanogens have the ability to generate methane by C02 reduction (Marty, 1992), which is· the main pathway for 

biogenic gas in commercial accumulations. Fermentation 

is performed by a few species of methanogens by the decarboxylation of several nutrients (substrates), the most 

common being acetate. During fermentation, the methyl 

group is converted to methane (CH4) and the carboxyl 

group is converted to C02, which can also be reduced to 

methane. 

C02 reduction and fermentation have been shown to 

operate simultaneously, but the biogenic gas resulting from 

each is quantitatively more important at different times. 

The two pathways are commonly independent of depositional environment, and can be seasonally or temperature 

controlled (Jenden and Kaplan, 1986; Martens and others, 

1986; Burke and others, 1988; Coleman and others, 1988; 

Schoell and others, 1988). 

On the basis of isotopic composition, most ancient 

biogenic gas accumulations have probably resulted from 

C02 reduction, whereas both C02 and fermentation are 

operating in recent environments. Jenden and Kaplan 

(1986), Coleman and others ( 1988), and Schoell ( 1988) 

speculated that burial depth and age of the sediments may 

be the major factors regulating the relative significance of 

the two pathways. That is, young, fresh, near-surface sedi-
BIOGENIC GAS: CONTROLS, HABITATS, AND RESOURCE POTENTIAL 585 

ments can generate biogenic gas by either C02 reduction 

or fermentation. However, most of this early generated gas 

is probably lost to the atmosphere soon after generation 

and is not retained as a major component of commercial 

accumulations. In contrast, older, altered, more deeply buried sediments generate biogenic gas mainly by C02 reduction; this gas has a better chance of being trapped and is 

therefore the major contributor to ancient accumulations. 

In addition, substrates with methyl resulting from microbial decomposition of organic matter may be available for 

fermentation only in young, fresh, shallow sediments, 

whereas C02 utilized for reduction can be provided by 

several sources, as will be discussed later. The change 

from fermentation to C02 reduction with increasing depth 

has been demonstrated in recent sediments by Jenden and 

Kaplan ( 1986) and Risatti ( 1987). 

Rock sequences containing biogenic gas accumulations 

are far removed from the original environment in which the 

gas was generated. However, much is known about modern 

settings that can be used in interpreting methanogenesis in 

ancient sequences. The recent marine environment is particularly useful for analogy because C02 reduction is the 

primary biogenic gas pathway in this setting as well as for 

most ancient biogenic gas accumulations. Although many 

ancient biogenic gas accumulations occur in freshwater sequences, they were generated by C02 reduction and the 

process is similar to that in the marine environment. 

Organic-rich, marine sediments pass through three 

main stages of respiratory metabolism that lead to methanogenesis-aerobic respiration, sulfate reduction, and C02 re- · 

duction (fig. 2). These three stages yield progressively less 

energy, and the change from one stage to another is due to 

changes resulting from microbial activity. The main evidence that microbial methanogenesis results from the progression of these metabolic stages comes from geochemical 

studies of interstitial waters in marine sediments as summarized by Claypool and Kaplan (1974), Rice and Claypool 

(1981 ), and Claypool and K venvolden (1983 ). These studies are important because the geochemical data suggest that 

methanogenesis continues to depths of at least several hundred meters, and not just a few centimeters as indicated by 

the decreasing quantity of bacteria and other microorganisms with increasing depth in shallow sediments (Zobel! 

and Anderson, 1936). 

C02 needed for reduction to generate methane is available from several sources. A low-temperature, shallow C02 source is the oxidation of organic matter by microbiological 

processes (sulfate reduction and fermentation). A higher 

temperature, deeper source of C02 is the thermal decarboxylation of organic matter (Tissot and Welte, 1984 ). A third 

possible source of C02 for reduction is the alteration of 

thermogenic hydrocarbons generated at greater depths. Several sources of C02 are probably required to provide sufficient quantities to maintain methane generation at a rate 

high enough to form significant biogenic gas accumulations. 

DISSOLVED 

SPECIES 

COLUMN 

1 

c 

41 

E 

""0 

41 

"' 

WATER- SEDIMENT METABOLIC 

COLUMN PROCESSES 

(biogeochemical zones) COLUMN 

} 

photo-

"""•'''l 

aerobic g respiration~ 

a: 

w 

< 

(.) 

iii 

0 

a: 

.W anaerobiC<{ 

respirationz 

< 

j 

Figure 2. Diagrammatic cross section of organic-rich, marine environment showing succession of microbial processes that lead to 

biogenic methane generation. From Rice and Claypool (1981 ). 

Substrates used for fermentation are derived from the 

successive breakdown by microorganisms of more complex organic substrates of the organic matter into smaller 

fragments until acetate is reached (Mechalas, 1974). 

CONDITIONS FOR BIOGENIC 

GAS GENERATION 

The generation of biogenic gas is regulated by several 

key factors (table 1). These requirements, which must be 

maintained for a sufficient period of time for the generation of significant amounts of biogenic gas to take place, 

are as follows: 

I. Anoxic environment-Methanogens are obligate 

anaerobes that are widely distributed in anaerobic environments and cannot tolerate any oxygen (Wolfe, 1971 ). 

2. Low-sulfate environment-In fresh-water or brackish-water environments, methanogenesis generally commences after oxygen is depleted. However, in the marine 

environment where significant quantities of sulfate occur, 
586 THE FUTURE OF ENERGY GASES 

Table 1. Factors that control biogenic gas generation and accumulation. 

Factors that control biogenic gas generation 

Anoxic environment 

Low-sulfate environment 

Low temperature 

Abundant organic matter 

Type and state of organic matter 

Sufficient pore space 

High rate of deposition 

Factors that control biogenic gas accumulation 

Physical state of gas (dissolved, free, hydrate) 

Early structures and stratigraphic traps 

Seals and timing 

Low-permeability reservoirs 

Pressures 

High rate of deposition 

sulfate must be significantly reduced (>80 percent) before 

methane generation can begin (Nikaido, 1977). Although 

the two processes are not strictly exclusive, sulfate-reducing bacteria are more competitive for available electrons 

or H2; therefore, methane generation is restricted in the 

presence of sulfate (Oremland and others, 1982). 

3. Low temperature-The temperature range for the 

growth of methanogenic bacteria is from mesophilic conditions (>25°C) to extremely thermophilic conditions ( <9rC) 

(Konig, 1992). The optimum temperature range for generation is from 35 to 45°C (Zeikus and Winfrey, 1976), just 

below the temperature at which thermogenic hydrocarbon 

generation commences (Tissot and Welte, 1984). 

4. Abundant organic matter-Organic matter is necessary for methanogenesis and the metabolic processes that 

precede and support it. Organic matter is generally concentrated in finer grained sediments, and minimum total 

organic carbon (TOC) values of about 0.5 percent are generally required, on the basis of analyses of documented 

biogenic-gas-bearing sequences. Clayton (1992), however, 

has demonstrated that only 0.12 percent TOC is required 

for a free-gas phase of biogenic gas. 

5. Type and state of organic matter-Hunt (1979) stated that the decomposition of lignins, a major component 

of type III (oxygen-rich) organic matter, by microbial activity is slow and inefficient. Therefore, type II (hydrogenrich) organic matter may be the type of organic matter 

preferred by microorganisms for methanogenesis. However, this paper will document that most ancient biogenic gas 

was probably generated from type III organic matter. Generation from mostly type III organic matter may be the 

result· of the type of organic matter available in habitats 

favorable for biogenic gas generation and accumulation. 

6. Pore space-Methanogens, which have an average 

size of 1!-lffi (H. Konig, oral commun., 1989) require pore 

space to exist, which is limited in fine-grained sediments 

where organic matter is usually concentrated. The microbes 

generally cannot survive in a fully compacted and dewatered shale at depths of 2 km where the average pore size is 

2 nanometers (Diamond, 1970). However, fractures in finegrained, organic-rich rocks can provide space for the microbes to operate. Coarser grained rocks, such as sandstones, have larger pore sizes, and methanogens can survive 

in them at greater depths if C02 is available. 

7. Rate of sediment deposition- Rate of sediment 

deposition is a critical factor in controlling not only the 

generation but also the accumulation of biogenic gas. If 

the depositional rate is too low, organic matter is destroyed by oxidation and any generated biogenic gas is 

lost to the atmosphere. In contrast, if the deposition rate is 

too high, the organic matter is preserved, but diluted, and 

the sediments pass too quickly through the zone of optimum temperature and depth for biogenic gas generation. 

In general, the generation of biogenic gas is favored by 

rates of deposition ranging from 200 to 1,000 m/m.y. 

(Clayton, 1992). However, the generation of biogenic gas 

is also influenced by geothermal gradients. 

CONDITIONS FOR BIOGENIC 

GAS ACCUMULATION 

The accumulation of biogenic gas depends not only on 

the generation of significant quantities of gas, but also on 

its entrapment, commonly at relatively shallow depths. 

Necessary conditions for accumulation, as summarized in 

table 1, are as follows: 

1. Physical state-In marine settings, biogenic gas is 

retained in solution in interstitial pore waters because of 

the higher hydrostatic pressures caused by the overlying 

water column (Rice and Claypool, 1981). This dissolution 

serves as a holding mechanism until sediments are buried 

deeper, and traps and seals are formed. 

A free-gas state results when gas generation exceeds 

solubility or when exsolution is caused by reduction of the 

hydrostatic pressure. Exsolution can be a consequence of 

falling sea level or uplift and erosion. 

In deep-sea sediments and areas of permafrost (high 

pressures and low temperatures), biogenic gas can become 

incorporated into a three-dimensional crystal framework of 

water referred to as a gas hydrate. Hydrates can trap enormous volumes of gas (K venvolden and McMenamin, 

1980) and can also serve as a seal for gas occurring below 

the hydrate. 

2. Early structures and stratigraphic traps-Because 

biogenic gas is generated early in the burial history, the 

formation of early structures and (or) stratigraphic traps is 

important for entrapment. Stratigraphic traps created by 

abrupt lateral facies changes, such as barrier islands, channels, carbonate buildups, and offshore bars, are excellent 
BIOGENIC GAS: CONTROLS, HABITATS, AND RESOURCE POTENTIAL 587 

traps for biogenic gas. In addition, early structures, such as 

growth faults resulting from rapid sediment loading at 

time of deposition in prograding deltas (Galloway, 1986), 

are helpful in trapping biogenic gas. 

3. Seals and timing-Effective seals are typically 

thick, laterally continuous, ductile rocks with high capillary entry pressures. Although many rock types can serve 

as seals, the most effective seals are evaporites (salt and 

anhydride), fine-grained clastic rocks, and organic-rich 

rocks (Downey, 1984). Because biogenic gas reservoirs 

are commonly interbedded with organic-rich shales, the 

shales serve as both the source and seal. 

Another type of seal for biogenic gas is early formed 

continuous layers of diagenetic carbonate cement. The carbonate results from the precipitation of COz by oxidation 

of methane under both aerobic and anaerobic conditions 

(Whiticar and Faber, 1986). Hovland and others (1987) 

have documented the relatively recent, widespread formation of carbonate-cemented sediments on the sea floor in 

the North Sea and in other marine settings. These impervious seals undoubtedly formed in the geologic past in association with biogenic gas generation. 

Diffusion of natural gas, in particular methane, can result in substantial volume loss, if the process takes place 

over a significant period of geologic time (Leythaeuser 

and others, 1982, 1983). Ancient biogenic gas was generated in relatively recent geologic time and thus has had 

relatively less time for diffusive loss than thermogenic hydrocarbons. 

4. Low permeability-Low-permeability reservoirs are 

commonly at considerable depths where diagenetic processes have resulted in porosity reduction. At shallow 

depths, and in the zone of biogenic gas generation and accumulation, low permeability is usually the result of small 

grain size at the time of deposition, such as in silts, chalks, 

and coalbeds. 

5. Pressures-Many ancient biogenic gas accumulations occur at shallow depths and are underpressured with 

respect to normal hydrostatic pressure gradients. This underpressuring, which slows down diffusion, is the result of 

removal of overburden, cooling of the rock sequence, dilation of pore volume, and decrease of temperature (Dickey 

and Cox, 1977). Erosion and resulting underpressuring are 

commonly coincident with the exsolution of the gas from 

marine pore waters. 

In areas of rapid deposition, such as deltas, biogenicgas-bearing intervals are commonly overpressured. The 

abnormal pressure is caused by undercompaction of shales 

that had little time to undergo normal dewatering and 

compaction (Chapman, 1980). 

6. Rate of sediment deposition-In addition to aiding 

biogenic gas generation, the rate of deposition is important 

to the accumulation of biogenic gas. Adequate traps and 

seals are generally formed when sediments have undergone at least some compaction and dewatering at depths 

of several hundred meters. When traps and seals are 

formed quickly by rapid deposition, less biogenic gas is 

lost to the atmosphere. In addition, rapid deposition results 

in thicker sequences of sediments, which slow down the 

diffusion of the gas. 

DEPTH AND TIMING OF BIOGENIC 

GAS GENERATION 

Biogenic gas can be generated during two different 

stages-early and late. Biogenic gas is formed early in 

shallow (<I km), young sediments and is subsequently buried after generation ceases. The generation and preservation 

of this early-stage biogenic gas are favored by rapid deposition. During this time, space is available in the finer 

grained, organic-rich sediments for the microbes to carry on 

the various processes leading to methanogenesis. Also, 

young, shallow organic matter is relatively fresh and easily 

decomposed by the microorganisms. Most accumulations 

of ancient biogenic gas were probably generated during this 

early stage. 

Some biogenic gas may also have been generated in 

the recent geologic past (tens of thousands to a few million years ago) (late stage) in association with active 

groundwater flow (Rice, in press). Because of their welldeveloped fracture (cleat) system, coalbeds are commonly 

aquifers (Kaiser and others, 199 I), which provide a favorable environment for microbial activity. This late-stage 

biogenic gas generation can take place in coalbeds of any 

rank, provided that the requirements described previously 

have been met. Late-stage biogenic gas generation may 

also take place in other organic-rich rock types that serve 

as aquifers because of enhanced permeability. 

Belyaev and others (1977) retrieved methanogens 

from core samples of Pliocene and Quaternary clays, silts, 

and sands at depths of 29 to 135 m. The methanogens 

were reported to be actively producing methane by COz 

reduction. This is the only study in which recent methanogenesis has been documented in ancient sediments. Additional field studies are needed to resolve the magnitude of 

late-stage biogenic gas generation. 

CHARACTERISTICS OF BIOGENIC GAS 

Gaseous hydrocarbons generated during the different 

stages of hydrocarbon generation have distinct chemical 

and isotopic compositions. Biogenic gas consists mainly 

of methane, except in low-pH environments, such as nonmarine or brackish water, where C02 is also a significant 

component. The trace amounts of C2+ alkanes commonly 

detected in biogenic gases in laboratory studies or in modern environments were probably generated by microbial 

activity (Davis and Squires, 1954; Vogel and others, 1982; 
588 THE FUTURE OF ENERGY GASES 

Oremland and others, 1988). Of the C1 through C5 alkanes 

in biogenic gases from the marine environment, generally 

less than 0.1 percent are C2+ alkanes, and the amount of 

c2+ is directly proportional to temperature, age, and organic-matter content of the sediments (Claypool, 1974). 

These heavier hydrocarbons have a complicated history; 

they are products of microbial activity at shallow depths 

and of low-temperature thermal processes at greater 

depths. Ancient biogenic gas can be associated with even 

greater amounts of heavier hydrocarbon gases because of 

migration and mixing of thermogenic hydrocarbons from 

deeper, more thermally mature intervals. 

However, because methane-rich gases have other 

origins besides biogenic processes, the isotopic composition (613C and 6D) of the methane provides the 

best evidence for the origin of the gas. (o13C(permil)= 

13 12 13 12 . (( C/ Csample/ C/ Cstandard)-1)x1,000, relative to PDB 

(Peedee belemnite) standard, and OD(permil)=((D/Hsample/ 

D!Hstandard)-1 )x 1 ,000, relative to SMOW (standard mean 

ocean water) standard.) In general, methane in ancient 

biogenic gas is isotopically light (methane o13c values in 

the range of -55 to -90 permil) because of enrichment of 

the light isotope 12C by microorganisms. In contrast, o13C 

values for thermogenic methane, are generally heavier 

than -50 permil (Schoell, 1983). 

Biogenic gases can be further differentiated on the 

basis of the two principal pathways that result in their 

generation in modern environments (Schoell, 1980; 

Wo1temate and others, 1984; Jenden and Kaplan, 1986; 

Whiticar and others, 1986; and Burke and others, 1988) 

(fig. 3). However, no absolute ranges can be given for 

the o13c and oD values for methane resulting from these 

two pathways. Biogenic methane resulting from C02 reduction is generally isotopically light in carbon (methane 

o 13c values ranging from -55 to -110 permil) and is enriched in deuterium (OD values ranging from -150 to 

-250 permil). In contrast, fermentation-derived methane 

can be isotopically heavier in carbon (613C values ranging from -40 to -70 permil) and is depleted in deuterium 

(OD values ranging from -250 to -400 permil). However, 

the source of hydrogen for biogenic methane is the associated water, which is variable in isotopic composition 

(Jenden and Kaplan, 1986; Whiticar and others, 1986). 

As a result, the 6D values for biogenic methane are dependent upon formation-water 6D, as well as the biochemical pathway. 

On the basis of documented occurrences, C02 reduction is the main pathway for ancient biogenic gas generation. The isotopic composition of the methane formed 

earliest by C02 reduction is controlled by the o13C of the 

original C02 substrate. The isotopic composition of methane formed later is a reflection of the net effect of the 

addition and removal of C02. The isotopic fractionation 

between the methane and C02 remains relatively constant 

at about 70±10 permil (Claypool and Kaplan, 1974; Jen-

-120 

-100 

-80 

8 

~ 

0 -60 

t') 

~<() 

-40 

·20 

0 

-550 -450 -350 -250 -150 -50 

SD1 (Otoo) 

Figure 3. Methane carbon isotope ratio (o 13C) versus methane deuterium isotope ratio (OD). General fields for biogenic gases generated by fermentation and C02 reduction and for thermogenic gases 

are from Whiticar and others ( 1986). Other areas are for biogenic 

gases from favorable habitats as discussed in text. Data for deepwater clastic setting, Italy, from Mattavelli and Novelli (1988). 

Rockies, Rocky Mountains. 

den and Kaplan, 1986). Biogenic methane as heavy as -40 

permil can be produced by the reduction of isotopically 

heavy carbon dioxide (Jenden and Kaplan, 1986). As indicated before, the two main sources of C02 for reduction 

are from microbial processes (sulfate reduction and fermentation) and thermal decarboxylation of kerogen. Both 

of these sources yield isotopically light C02 (613C values 

ranging from -20 to -25 permil) and yield isotopically 

light biogenic methane. If the sediments are organic rich 

and C02 is plentiful, then the resulting biogenic methane 

is isotopically light throughout its generation history. 

However, if the sediments are lean in metabolizable organic matter, then the biogenic methane (both the accumulated product and the methane being generated) becomes 

isotopically heavier with time because the isotopically 

light C02 is used first for reduction. 

The net effect is that ancient biogenic gases generally 

show a systematic trend of becoming isotopically heavier 

and chemically wetter with depth (Fuex, 1977; Mattavelli 

and others, 1983; Rice, 1984). This trend is the result of 

the gradual mixing of minor amounts of thermogenic 

methane and C2+ gases with isotopically light methane of 

biogenic origin. 

Gases of thermogenic origin can usually be distinguished from biogenic gases by the methane component 

being isotopically heavier and containing significant 

amounts of heavier hydrocarbon gases (Schoell, 1983 ). 

Fermentation-derived methane can overlap in carbon isotopic composition with thermogenic gases (fig. 3). However, thermogenic gases are generally chemically wetter, and 

fermentation-derived methane is depleted in deuterium. 
BIOGENIC GAS: CONTROLS, HABITATS, AND RESOURCE POTENTIAL 589 

Finally, oil has been reported in association with gases 

having characteristics of biogenic gas (Rice, 1980; Faber, 

1987; Jenden and others, 1988). The oil has probably migrated from deeper, more mature intervals. 

Geologic history is also important in interpreting the 

occurrence of ancient biogenic gas. Biogenic gases usually 

occur at relatively shallow depths, at low levels of thermal 

maturity, and in relatively young sediments. 

OCCURRENCES OF ANCIENT 

BIOGENIC GAS 

Data that permit recognition of ancient biogenic gas 

accumulations are available only for those accumulations 

shown on figure 4 (conterminous United States) and figure 

5 (world) and summarized in table 2. 

All of the listed biogenic gas occurrences generally 

meet the criteria of being primarily methane (C2+ alkanes 

<2 percent of C1 through Cs alkanes) that is isotopically 

light in carbon (methane &Be values more negative than 

-55 perrnil). On the basis of methane &D values, most of 

the methane in these occurrences was derived by C02 

reduction. 

800 Km 

Most biogenic gas was probably generated from type 

III organic matter. Although type II organic matter is easier to degrade by microbial activity, type III organic matter 

is more commonly present in settings characterized by 

rapid deposition. 

Accumulations of ancient biogenic gas occur in relatively young sequences. The majority of biogenic gas accumulations occur in Cretaceous and younger sequences, 

although there are documented occurrences of Jurassic age 

in the North Sea and of late Paleozoic (Mississippian and 

Pennsylvanian) age in the Cherokee and Forest City basins 

of Kansas, United States. In addition, biogenic gas is common in Carboniferous coalbeds at shallow depths in many 

parts of the world (Rice, in press). 

Ancient biogenic gas accumulations occur in a variety 

of depositional settings and rock types as summarized in 

table 2. They have been reported in both marine (deltaic, 

interdeltaic, shelf, deep-water clastic, and pelagic) and nonmarine (fluvial, lacustrine, coastal plain, and coal swamp) 

settings. In addition, they have been documented in clastic 

and carbonate rocks, and coals. The distribution of known 

biogenic gas accumulations in a variety of depositional settings and rock types indicates that undiscovered biogenic 

gas resources are probably widespread. 

Gulf of Mexico 

Figure 4. Locations of ancient biogenic gas accumulations in conterminous United States. Identification and details of accumulations 

are listed in table 2. 
590 THE FUTURE OF ENERGY GASES 

... 

~~----------t-----------+-----------4-----------~----------~----------~ 

120" 120" 

Figure 5. World map showing locations of ancient biogenic gas accumulations. Identification and details of accumulations are listed in 

table 2. Accumulations in conterminous United States (diagonal-line pattern) are shown in figure 4. 

FAVORABLE HABITATS FOR BIOGENIC 

GAS ACCUMULATIONS 

Although biogenic gas generated in the geologic past 

has been documented in diverse depositional settings and 

rock types, several habitats are considered to be particularly favorable for the generation and accumulation of biogenic gas. These habitats, in order of relative importance, 

are deltas, deep-water clastic settings, shelves (both clastic 

and carbonate), and nonmarine settings (particularly coal 

swamps). The factors that make each of these habitats favorable for the generation and accumulation of biogenic 

gas are discussed below, along with examples where ancient accumulations have been documented. In all of the 

favorable habitats, rapid rate of deposition appears to be 

the major, common factor controlling the generation and 

accumulation of biogenic gas. 

DELTAS 

Cenozoic deltas have provided a very favorable setting 

for the generation and accumulation of hydrocarbons, both 

biogenic and thermogenic. Biogenic gas has been identified in the following Cenozoic deltaic sequences: Baram, 

Mahakam, Niger, offshore Gulf of Mexico, and Poland 

(Carpathian foredeep) (fig. 6, table 2). The Baram, Mahakam, Niger, and offshore Gulf of Mexico deltas also 

contain large resources of thermogenic hydrocarbons, 

whereas deltaic sedimentary rocks in Poland produce 

mainly biogenic gas. Other Cenozoic deltas, as shown on 

figure 6, may also contain biogenic gas accumulations. 

Deltas occur where rivers meet the coast and large 

quantities of land-derived sediment are deposited. Rapid 

sediment deposition in these deltas was usually accompanied by rapid subsidence. As documented in the Gulf of 

Mexico and Niger deltas, the sedimentation rates were 

high throughout Tertiary time, but were especially high 

during late Tertiary and Pleistocene time (Woodbury and 

others, 1973; Bustin, 1988). The fact that rapid deposition 

and subsidence is common to most deltas makes them an 

ideal habitat for the generation and accumulation of biogenic gas. 

Because of rapid sedimentation rates, deltas are normally characterized by the seaward progradation of the 

shoreline, resulting in a lateral facies shift through time 

(fig. 7). As a result, younger nearshore marine and nonmarine sandstones interbedded with shales, which serve as 

the major reservoir and seal units, overlie older, deeper 

water shales that are more concentrated in organic matter. 
BIOGENIC GAS: CONTROLS, HABITATS, AND RESOURCE POTENTIAL 591 

Table 2. Occurrences of ancient biogenic gas. 

[Numbers in parentheses in "Location" column correspond to numbered locations on figure 5. b 13c 1 and 1\D 1 are isotope compositions of methane (C 1) component of gas. See 

text for explanation of organic matter types. ---, not determined] 

Location Habitat Reservoir Depth ol3c1 1\01 Organic References 

age (meters) (permil) (permil) matter type 

Brunei 

Baram Delta (I) Delta Tertiary 1,600--2,600 -55 to -64 Type III This paper; Rijks 

(1981) 

Canada 

Quebec (2) Glacial drift Pleistocene 70 -60 Fuex (1977) 

Southeastern Alberta (3) Clastic Shelf Cretaceous 300-1,000 -60 to -68.3 Type III This paper; Fuex 

(1977); Rice and 

Claypool (1981) 

China 

Pearl ( 4 ), Qiantang (5), and Estuarine/marine Quaternary 30-40 -68.3 to -78.7 Zhang and Chen (1985) 

Yangtze Rivers (6) 

Qaidam basin (7) Fluvial/lacustrine Pleistocene 65-1,380 -58 to -80 Type III Gu and others (1988) 

Colombia 

(Offshore) (8) Tertiary 3,213-3,304 -69.3 This paper 

Denmark 

(9) Glacial/marine Pleistocene 0-117 -63.6 to -89.2 -177 to -228 Type II Jorgensen and others 

( 1990); Laier and 

others (1992) 

Germany 

Molasse basin (10) Nonmarine/delta! Tertiary 900-2,000 -64 to -72.2 -192 to -216 Schoell (1980) 

marine 

Hungary 

Pannonian basin (II) Nonmarine/delta! Tertiary <1,000 -65to-81 Koncz (1983) 

marine 

Indonesia 

Mahakam delta (12) Delta Tertiary -55 to -69.7 -177 to -264 Type III This paper; Combaz 

and de Matharel 

(1978) 

Italy 

Apennine foredeep (13) Deep-water clastic Tertiary 140-4,600 -60to-76 -171 to -223 Type III Schoell (1980); 

Mattavelli and others 

(1983); Mattavelli and 

Novelli (1988) 

Japan 

(14) Marine or lagoonal Tertiary and 100--2,000 -64 to -75 -148 to -239 Nakai (1960); Nakai 

basin Pleistocene and others (1974) 

Nigeria 

Niger delta (15) Delta Tertiary 650 -55 Type III This paper; Bustin 

(1988) 

Poland 

Carpathian foredeep ( 17) Delta/marine Tertiary 275-2,447 -60.7 to 71.2 -177 to -208 Type III Kotarba and others 

(1987); Kotarba 

(1992) 

Trinidad 

(Offshore) (18) Tertiary <3,350 -64 to -71 Faber and Stahl 

(197711978) 

Table continued on following page. 
592 THE FUTURE OF ENERGY GASES 

Table 2. Occurrences of ancient biogenic gas-Continued. 

[Numbers in parentheses in ''Location'' column correspond to numbered locations on figure 5. l)l3c 1 and llD1 are isotope compositions of methane (C 1) component of gas. See 

text for explanation of organic matter types. ---, not determined] 

Location Habitat Reservoir 

age 

Central Rocky Mountains, Carbonate shelf Cretaceous 

Colorado and Kansas (19) 

Cherokee and Forest City 

basins, Kansas (20) 

Marine Carboniferous 

Cook Inlet, Alaska (21) FluviaUcoal swamp Tertiary 

Eastern Gulf of Mexico (22) Delta/marine Miocene 

Illinois basin (23) Glacial drift Pleistocene 

Northern Rocky Mountains, 

Montana and South 

Dakota (24) 

Offshore Gulf of Mexico 

(25) 

Powder River basin, 

Wyoming (26) 

Sacramento basin, Calif. 

(27) 

San Luis basin, Colorado 

(28) 

South-central Washington 

(29) 

Caspian Depression (30) 

North Aral (31) 

West Siberia (32) 

Stravapol (33) 

Coastal and clastic 

shelf 

Delta 

Coal swamp 

Nonmarine 

Cretaceous 

Pleistocene 

Tertiary 

Tertiary 

Nonmarine/fluvial Tertiary 

Nonmarine with 

igneous activity 

Coastal plain 

Tertiary 

Tertiary 

Tertiary 

Cretaceous 

Cenomanian 

Tertiary 

Depth lll3cl 

(meters) (permil) 

United States 

322-842 -55 to -65.4 

127-551 -48.3 to -65 I 

910-1,650 -56 to -63 

490-595 -62 to -66 

8-99 -68 to -91 

170-830 -63.5 to -72.3 

llD1 Organic References 

(perrnil) matter type 

-222 to -225 Type II This paper; Rice (1984) 

-201 to -246 Jenden and others 

(1988) 

Type III Claypool and others 

(1980) 

This paper; Mink and 

others (1988) 

-214 to -240 Type III Schoell (1980); 

-234 to -245 

Coleman and others 

(1988) 

Type III This paper; Rice and 

Claypool (1981 ); Rice 

and others ( 1990) 

458-3,600 -56.7 to -67.4 -182 to -191 Type III This paper; Dow (1978); 

110-122 

1,055 

300 

220-486 

Rice (1980); Rice and 

Threlkeld ( 1983) 

-53.8 to -56.5 -307 to -3332 Type Ill This paper 

-61.3 -187 Type III Jenden and Kaplan 

-69.7 to -70.2 

(1989) 

Rice and Claypool 

(1981) 

-63.6 to -88.2 -255 to -2773 Type III This paper 

Former U.S.S.R. 

327-391 -61 to -65 Galimov (1968) 

320-476 -64 to -72 Galimov (1968); Avrov 

and Galimov (1968) 

684-1,275 -58 to -654 Type III Y ermakov and others 

-46 to -504 (1970); Alekseyev 

(1974); Galimov 

(1988) 

214-1,076 -66 to -75 Alekseyev and others 

(1972) 

I Gases with methane o 13c values heavier than -55 perrnil are interpreted to be biogenic on the basis of li 13c values of C02 and llD values of formation water. 

2Methane 1\ l3c and 1\D values of gas and 1\D values of associated water indicate that gases were generated mainly by C02 reduction. 

3Methane 1\D values indicate generation by fermentation pathway. 

4oifferent methane l)13c values given for gases from same reservoirs. See text for discussion .. 

Usually the shallow, younger reservoir section is thermally immature with respect to hydrocarbon generation, 

whereas the deeper shales are thermally mature and are 

the source rocks for thermogenic hydrocarbons (fig. 7; 

Dow, 1978). 

The sediments in deltas are derived from land areas 

and the associated organic matter is usually terrestrial in 

origin (type III). Because of the high rates of sedimentation, the organic matter is diluted, but minimum TOC values of 0.5 percent are usually present. In addition, the 

immature sediments that served as the source for the biogenic gas are in such close association with reservoir 

rocks that long-distance migration is not required for biogenic gas. For example, in the offshore Gulf of Mexico, 

TOC values in all facies are generally less than I percent 

(Dow, 1978). The alternating sandstone and shale facies 

deposited in the middle to outer neritic zone is the most 

productive reservoir facies for both biogenic and thermogenic hydrocarbons; the shales of this facies contain 

mostly type lii organic matter (>0.5 percent TOC) (Dow, 
BIOGENIC GAS: CONTROLS, HABITATS, AND RESOURCE POTENTIAL 593 

12()• 

40" 1------------1------

--~-------4-------~~ 

120" ()" 120" 

Figure 6. World map showing location of Cenozoic deltas with documented (solid circles) and suspected (open circles) accumulations 

of biogenic gas. I, Mackenzie, Canada; 2, Gulf of Mexico, United States; 3, Orinoco, Venezuela; 7, Niger, Nigeria; 5, Orange, Namibia; 6, Nile, Egypt; 7, Indus, Pakistan; 8, Brahmaputra, Bangladesh; 9, Irrawaddy, Myanmar; 10, Yellow, China; 11, Yangtze, China; 12, 

Qiantang, China; 13, Pearl, China; 14, Mekong, Vietnam; 15, Baram, Brunei; 16, Mahakam, Indonesia. 

N s 

AR I LA 

Figure 7. Schematic north-south cross section of Gulf Coast, 

United States, showing progradation of the shoreline and relation 

of reservoirs (diagonal-line pattern) to thermal maturity (oil window, with vitrinite reflectance (R0 ) values of 0.6 to 1.35 percent, 

dotted) in each producing trend. Biogenic gas occurs mainly in 

Pleistocene reservoirs. AR, Arkansas; LA, Louisiana. From Dow 

(1978). 

1978) and are the likely source for biogenic gas. In the 

Niger delta, the highest TOC values are in the nonmarine 

facies, which contains mostly type III organic matter 

(Bustin, 1988). This source facies for the biogenic gas is 

juxtaposed with reservoirs of nearshore sandstones. The 

thermogenic hydrocarbons occurring in both these deltas 

have probably migrated from deeper, more mature source 

rocks that contain some type II organic matter. 

The high rates of sedimentation typical of deltas result in unstable slope conditions, and syndepositional 

gravity-driven growth faults are commonly developed 

(Galloway, 1986). These growth faults are important to 

hydrocarbon accumulation for two reasons. First, they 

provide traps in the conventional sandstone reservoirs for 

the early-formed biogenic gas. Second, they provide conduits for the vertical migration of thermogenic hydrocarbons and other fluids to shallower, immature reservoirs. 

This migration causes mixing of migrated, thermogenic 

hydrocarbons with indigenous biogenic gas and the scatter 

of gas compositional data. 

The shales that alternate with the biogenic-gas-bearing sandstone reservoirs in young deltas are commonly 

overpressured because of incomplete dewatering due to 

rapid deposition (Chapman, 1980). The difference in pressure between the shales and the more normally .pressured 

reservoirs aids in sealing the biogenic gas (Downey, 

1984). 
594 THE FUTURE OF ENERGY GASES 

DEEP-WATER CLASTIC SETTINGS 

The deep-water clastic setting is favorable for biogenIc gas accumulations because (I) it is characterized by 

rapid deposition, and (2) it contains interbedded sandstones and shale sequences (turbidites) that provide close 

association of reservoir, source, and seal. Ancient biogenic 

gas accumulations have been documented in deep-water 

clastic rocks in the Appennine foredeep of Italy (fig. 5, 

table 2). 

A significant portion of the natural gases of Italy occurs in the Appennine foredeep and is of biogenic origin 

(Mattavelli and others, 1983; Mattavelli and Novelli, 

1988). High rates of deposition, syndepositional tectonic 

activity, and turbiditic sedimentation during Tertiary and 

Pleistocene time were instrumental in the generation and 

accumulation of large volumes of biogenic gas in the foredeep in front of the Appennine Mountains (Mattavelli and 

others, 1983; Mattavelli and Novelli, 1988). The Appennine foredeep was rapidly filled by thick turbiditic sequences which consist of alternating sandstones and shales 

that have formed in multipay gas fields. The sandstones 

serve as the reservoir for the biogenic gas, and the shales 

act as both the source and the seal. The organic matter in 

the transported clays of the turbidite sequences is much 

richer than that in the pelagic clays and thus is the probable source of the biogenic gas. The organic matter consists 

mainly of herbaceous and woody components indicating 

type Ill; TOC values are variable, but can be more than 1 

percent (Mattavelli and others, 1983 ). 

In addition to the alternation of reservoirs and 

source/seals, syndepositional or very early compressional 

structures aided in the trapping of biogenic gas in the Appennine foredeep (Mattavelli and others, 1983; Mattavelli 

and Novelli, 1988). The compressional tectonics were related to the convergence of Africa and Europe and Jed to 

structural and combination traps. 

Biogenic gas has been reported to a maximum depth of 

4,600 m in the Pliocene reservoirs of the Appennine foredeep (table 2). Although generated at shallower depths, the 

biogenic gas is interpreted to be present at this depth because the rocks are relatively young and the geothermal 

gradient is relatively low. In one field, present-day temperatures ranging from 48 to 63°C are reported at depths of 

2,500 to 4,100 m (Mattavelli and others, 1983; Mattavelli 

and Novelli, 1988). These temperatures, in addition to low 

vitrinite-reflectance values (Mattavelli and others, 1983), 

indicate that the section is thermally immature. 

SHELF SETTING 

Shelves are a favorable setting for the generation and 

accumulation of biogenic gas provided that they were areas 

of high sedimentation rates. Ancient biogenic gas accumulations have been documented in shelf sequences of the Cretaceous Western Interior Seaway of North America (fig. 8, 

table 2). The accumulations are significant because they ( 1) 

are major, (2) occur in rocks of Cretaceous age, and (3) are 

trapped in low-permeability (unconventional) reservoirs. 

The Cretaceous Western Interior basin of North America (Canada and United States) was an elongate, asymmetrical foreland basin that was bordered on the west by the 

Cordilleran thrust belt and on the east by the low-lying 

Precambrian shield (fig. 8). A summary of the basin and 

its deposits is presented by Rice and Gautier (1983) and 

Rice and Shurr (1983). During Late Cretaceous time, the 

basin was occupied by a shallow epicontinental seaway 

that extended in a north-south direction from the Arctic 

Ocean to the Gulf of Mexico. Major biogenic gas accumulations occur in both clastic and carbonate sediments deposited in relatively shallow-water shelf settings. 

During Late Cretaceous time, a recurring pattern of 

sedimentation was established in the seaway (fig. 9); this 

pattern was controlled by supply of detritus from the west 

and by changes in base level, some global in scale. The 

marine shelf was the most favorable setting for the generation and accumulation of biogenic gas. As shown by the 

paleogeographic map (fig. 9), the central part of the seaway 

was characterized by the deposition of shelf sands and offshore marine silts and muds. The eastern part of the seaway, and sometimes extending into the central part of the 

seaway, was represented by the deposition of carbonate 

rocks (chalks). Carbonate deposition was limited by the 

input of terrigenous clastic sediments from the thrust belt to 

the west, and the chalks, therefore, are generally restricted 

to a shelf setting on the eastern side of the seaway. The 

shelf settings located in the central and eastern parts of the 

seaway had a series of structural elements (blocks) that 

experienced recurrent movement which affected subsidence 

and deposition of Late Cretaceous sediments. Favorable 

areas for biogenic gas generation and accumulation were 

those that experienced greater subsidence and deposition. 

CLASTIC SHELF 

The central part of the Cretaceous Western Interior 

Seaway was characterized by the deposition of mud and 

silt with lesser amounts of sand. Although the silt and 

sand occur as thin and discontinuous lenses and laminae 

(fig. 10), the interval that.contains them is widespread and 

as much as 70 m thick (Rice and Shurr, 1980). These individual lenses and laminae of silt and sand are commonly 

only a few centimeters thick and serve as the reservoirs 

for biogenic gas. The reservoirs have low permeability 

"Yith values of less than 0.1 millidarcy (Rice and others, 

1990). The enclosing shales serve as the source and the 

seal for the biogenic gas. The shales average 2 percent 

TOC, but locally contain as much as 5 percent TOC. The 
BIOGENIC GAS: CONTROLS, HABITATS, AND RESOURCE POTENTIAL 595 

0 500 1000 Km 

Figure 8. Extent of Western Interior Seaway during Late Cretaceous (Campanian) 

time. From Gill and Cobban (1973). 

organic matter is oxygen-rich type III (herbaceous and 

woody components) (fig. 11 ), suggesting that it was transported to the shelf area with the silt and sand. The intercalation of rapidly deposited coarser grained sediment 

(reservoir) and finer grained sediment (source and seal) at 

the centimeter scale has resulted in a very efficient package for generating and accumulating biogenic gas. 

The potential for biogenic gas accumulations in Cretaceous clastic shelf sequences occurs in the northern part of 

the basin (Montana and North and South Dakota, United 

States, and Alberta and Saskatchewan, Canada) where the 

section is thermally immature. To date, most of biogenic 

gas production has come from structural highs, although 

the gas is considered to be trapped stratigraphically in the 

discontinuous lenses and laminae of siltstone and sandstone. The structure has aided in trapping the gas in three 

ways. First, these present-day structural highs experienced 

recurrent tectonic movement during Late Cretaceous time, 

the time of deposition of the shelf sediments. The movement created shoals on the submarine shelf that resulted in 

winnowing and enhancement of the reservoir properties 

(Rice and Gautier, 1983). Second, at the time of generation the early-formed gas was probably dissolved in formation waters which served as a holding mechanism until 

traps and seals were formed. Uplift and erosion in Late 

Cretaceous and early Tertiary time resulted in exsolution 

of the gas and creation of a free-gas state. Finally, the erosion resulted in underpressuring which slowed down loss 

of gas by diffusion. 

The stages of metabolic activity leading to methanogenesis by C02 reduction have been documented in 

these sequences by the mineralogy, texture, and isotopic 
596 THE FUTURE OF ENERGY GASES 

50° ' 

\ 

114° 110 ° 106° 

\ 

ALBERTA 

." Mo~'~'"'"!" :wvo i.f!N(; .'-.! ._r.·-~ '-1 10AI-I0 : 

I 

SASKATCHEWAN 

I oc_ ____ 2__JOO Kilometers 

102° 

' ' 

MANITOBA 

___ _j ~ MINNESOiA 

Figure 9. Paleogeographic map of northern Rocky Mountains, United States and Canada, during Late Cretaceous 

(Campanian) time. Central and eastern parts of the Western Interior Seaway (inner and outer shelves) were favorable sites for generation and accumulation of biogenic gas. ss, sandstones. From Rice and Shurr ( 1983). 

0 

I 

1cm 

I 

Figure 10. Photograph of core showing interlaminated sandstone, 

siltstone, and shale of Late Cretaceous (Turonian) age, Montana, 

United States. Illustrates close relation between reservoir, source, 

and seal of biogenic gas. 

composition of concretionary carbonate cements and other 

authigenic minerals (Gautier and Claypool, 1984). 

CARBONATE SHELF 

The carbonate marine shelf of the Cretaceous Western 

Interior Seaway, as summarized by Rice and Gautier 

( 1983 ), represents another favorable habitat for the generation and accumulation of ancient biogenic gases. The car900 

750 

~ ~ 600 

0 l:' 

~0 

zw Ql C)~ 450 

Oe> 

a:E 

~ ~ 300 

I 

150 

0 

50 

][ 

Carbonate Shelf 

(Central Rockies, U.S.A.) 

Clastic Shelf 

(Northern Rockies, U.S.A.) 

100 

OXYGEN INDEX 

(mgC02/gCorg) 

150 200 

Figure 11. Modified van Krevelen diagram showing low level of 

maturity and types of organic matter that were source of biogenic 

gas for clastic-shelf (type III) and carbonate-shelf (type II) settings. Data for carbonate-shelf setting from Rice (1984). HC, hydrocarbon; Corg• organic carbon; Rockies, Rocky Mountains. 
BIOGENIC GAS: CONTROLS, HABITATS, AND RESOURCE POTENTIAL 597 

bonate rocks, referred to as chalks, are a fine-grained 

facies consisting of calcareous nannofossils and other microfossils. The chalks were deposited in an open-marine, 

pelagic environment in which the rate of accumulation 

was slow and the influence of terrigenous input was minimal. This setting contrasts with all other favorable settings, where rapid sedimentation was a critical element for 

both generation and accumulation. Because the main terrigenous source area was to the west, chalk deposition was 

generally restricted to the eastern part of the seaway. 

Biogenic-gas-bearing chalks deposited in the Western 

Interior Seaway consist of rhythmically bedded couplets at 

a centimeter scale (fig. 12) (Arthur and others, 1985; Pollastro and Martinez, 1985). The carbonate-rich laminae 

have the highest porosity values and are the best reservoir 

units. Because of their fine grain size, the chalks were deposited with high porosity and extremely low permeability, both of which decrease rapidly with depth of burial 

(Scholle, 1977). These properties provide for ample storage capacity and also help to trap the gas. 

Figure 12. Rhythmically laminated chalks of Late 

Cretaceous (Coniacian and Santonian) age, Kansas, 

United States. Lighter colored laminae are carbonate 

rich and serve as reservoir for biogenic gas. Darker 

colored laminae have higher amounts of insoluble 

residue (mainly clay minerals) and organic matter, 

and serve as source and seal for biogenic gas. 

In contrast, the alternating laminae are higher in insoluble residue (which consists mainly of clay minerals), 

have greater amounts of organic matter, and are lower in 

porosity. TOC values are as high as 5.8 percent and average 3.2 percent throughout the entire chalk interval (Rice, 

1984). In contrast to organic matter in all the other documented occurrences of ancient biogenic gas, the organic 

matter in this occurrence is hydrogen-rich type II (fig. 11 ), 

typical of open-marine conditions. 

The cycles that resulted in the preservation of higher 

amounts of organic matter are interpreted to be the result of 

poor oxygenation and weak circulation of bottom waters. 

These "oceanic anoxic events" were probably caused by 

regional climate and paleoceanographic conditions (Arthur 

and others, 1984; Fischer and others, 1985). Because of 

oceanic anoxic events, abundant amounts of organic matter 

were preserved without the need for rapid deposition. 

The trapping of the gas probably resulted from (I) low 

permeability of the chalk reservoirs and (2) a rapidly deposited, thick sequence of marine shale with bentonite 

beds deposited on top of the chalks. As was the case with 

the clastic shelf setting, early-formed biogenic gas was 

probably initially held in solution in the formation waters. 

After uplift and erosion, free gas formed as underpressured accumulations. 

Biogenic gas production has been established in northeastern Colorado and northwestern Kansas, United States 

(Lockridge and Pollastro, 1988). Depth of biogenic gas production varies from 250 to 850 m. Oil is produced from this 

same chalk interval at greater depths where the chalks are 

thermally mature and are naturally fractured. The biogenic 

gas accumulations occur on low-amplitude anticlinal structural closures with listric-normal faults that have resulted in 

fracturing and increased reservoir quality of the chalks. 

NONMARINE SETTINGS 

A variety of reservoirs in nonmarine depositional settings-including fluvial and lacustrine settings, coastal 

plains, and coal swamps-contain documented biogenic 

gas accumulations (table 2). Two particular nonmarine settings, coal swamps and coastal plains, are important habitats for biogenic gas accumulations and will be discussed. 

COAL SWAMPS 

Coal swamps are a setting favorable to the generation 

and accumulation of biogenic gas as indicated by the recent exploration activity for coalbed gas. Coalbeds are interpreted to be both reservoir and source rocks for large 

quantities of not only thermogenic but also biogenic gas. 

Biogenic gas production has been established in coalbeds and adjacent fluvial sandstones of Paleocene age in 
598 THE FUTURE OF ENERGY GASES 

the Powder River basin, northeastern Wyoming, United 

States (Law and others, 1991) (fig. 4 ). The coals were deposited in raised, ombrotiphic bogs that were cut by anastomosing fluvial channels (Warwick and Stanton, 1988). 

The coalbeds are anomalously thick (> 75 m) and are surface-mined on the margins of the basin. The thick coals 

indicate rapid subsidence during time of peat formation. 

This rapid subsidence accompanied by rapid deposition 

undoubtedly continued after peat accumulation. 

The coals consist mostly of the maceral huminite, and 

the organic matter is classified as type III. The coals are 

relatively low in rank over the entire basin, ranging from 

lignite to subbituminous (vitrinite reflectance (R0 ) values 

of 0.4 to 0.6 percent) (Law and others, 1991 ). 

On the basis of the molecular and isotopic composition 

of the gas and the low rank of the coals, the gases are 

interpreted to be biogenic and to have been generated via 

the fermentation pathway (fig. 3). However, 6D values of 

the water, used in conjunction with the isotopic composition of the gases, suggest that more than 80 percent of the 

gas was derived by C02 reduction (P.D. Jenden, oral commun., 1992). 

The timing of biogenic gas generation in the low-rank 

coalbeds of the Powder River basin is problematic. Biogenic gas was undoubtedly generated and accumulated shortly 

after deposition of the peat during a time of rapid subsidence and deposition. This early-stage gas was trapped by 

interbedded shales and compaction folds (Law and others, 

1991 ). Some or all of this early-formed biogenic gas probably degassed, however, from the coalbeds following regional uplift and erosion about I 0 Ma. This uplift and erosion 

also led to the establishment of a regional aquifer system in 

the thick coal beds '(Tyler and others, 1991 ). Groundwater 

flow in the coalbeds, at least along the basin margins, led to 

microbial activity that resulted in generation of late-stage 

biogenic gas by C02 reduction. Whether generation of latestage biogenic gas was widespread in the basin is uncertain 

because of the discontinuous nature of the coal beds. Consequently, late-stage biogenic gas may be limited to the margins of the basin or may extend across the entire basin. 

A survey of coalbed gases from Australia, Canada, 

China, Germany, Poland, and the United States demonstrates a stronger relation between molecular and isotopic 

composition of the gases when plotted against present-day 

depth of burial than when plotted against rank (Rice, in 

press). In general, shallow coalbed gases are composed of 

isotopically light methane, as compared with deeper 

coalbed gases, regardless of rank and age of the associated 

coal. Rice (in press) interpreted this difference to be the 

result of late-stage biogenic gas either (1) being mixed with 

previously generated thermogenic gas or (2) completely 

filling degassed coalbeds at shallow depths. As discussed 

earlier, coalbeds are commonly aquifers, particularly at 

shallow depths (<1 km), where microorganisms can thrive 

and significant amounts of biogenic gas can be generated. 

COASTAL PLAINS 

The coastal plain is an important setting for ancient 

biogenic gas accumulations in the northern part of West 

Siberia basin, Russia, where enormous reserves have been 

discovered. The petroleum geology of the province is 

summarized in English by Grace and Hart (1986), Galimov (1988), and Peterson and Clarke (1991). 

In the West Siberia basin, nonassociated gases of 

possible biogenic origin occur in Upper Cretaceous (Cenomanian) rocks at an average depth of about 1,100 m. 

Thermogenic gases and condensates are produced from 

Lower Cretaceous (Neocomian) reservoirs at depths of 

2,500 to 3,000 m. The shallow Cenomanian gas occurs in 

an 800-m section of interbedded sandstones and shales of 

coastal plain origin. The gas is trapped in very large structures, and the reservoir section is directly overlain by a 

thick (hundreds of meters) shale. Several investigators, including Makogon and others ( 1972), have suggested that 

Cenozoic glaciation may have aided in trapping the huge 

Cenomanian gas accumulations. The theory is that the formation waters and gas formed hydrates with the advance 

of the glaciers and permafrost. With the glacial retreat, the 

hydrates decomposed and a free gas state was formed. 

The gas-bearing Cenomanian section is thermally 

immature over the entire area (R0 values of 0.4 to 0.55 

percent). Humic (type III) organic matter is abundant 

throughout the section and is concentrated in coalbeds; it 

is an obvious indigenous source for the large gas accumulations. In contrast, the organic matter in the Neocomian 

section is transitional between marine and continental 

(mixture of types II and III). Vitrinite reflectance values of 

the Neocomian section range from 0.55 to 0.76 percent, 

indicating the early part of the mature stage of hydrocarbon generation. The underlying Upper Jurassic shales 

occur at a higher level of thermal maturity and are rich in 

type II kerogen. 

As reported by Yermakov and others (1970) and Alekseyev (1974), gases from Upper Jurassic and Neocomian 

reservoirs are chemically wet (average methane concentration is 88 percent) and isotopically heavy (methane 613C 

values for methane range from -38.5 to -44.2 permil). On 

the basis of these analyses and the level of thermal maturity, the gases are interpreted to be thermogenic and to have 

been generated in the adjacent source rocks or in the underlying organic-rich shales of Jurassic age. 

In contrast, gases from the Cenomanian reservoirs 

consist mostly of methane (average 98 percent). Yermakov 

and others ( 1970) and Alekseyev (197 4) reported that 

methane 613C values of methane in gases from eight 

fields, including the giant Urengoy, range from -57.5 to 

-67.8 permil. These isotopic values, in addition to the molecular composition and the low level of thermal maturity, 

strongly suggest an indigenous biogenic origin. On the 

basis of available data, the shallow gases in Cenomanian 
BIOGENIC GAS: CONTROLS, HABITATS, AND RESOURCE POTENTIAL 599 

reservoirs have probably not migrated from the deeper Jurassic and (or) Neocomian section. 

Galimov (1988) reported significantly heavier methane 

c~Pc values than those previously cited for methane in 

gases from the Urengoy field. His methane 6 13C values 

for methane in Cenomanian gases range from -46 to -50 

penni!, whereas those from Neocomian reservoirs range 

from -35 to -38 penni!. Galimov (1988) proposed early 

thermogenic generation for the major quantities of methane-rich gas from rocks generally recognized as being immature. He calculated from activation energies that this 

early generation took place from indigenous humic (type 

III) organic matter. Another possibility is that these gases 

were generated by reduction of heavy C02 or by the fermentation pathway resulting in heavier methane 613C values for the methane component. 

RESOURCE POTENTIAL OF 

BIOGENIC GAS 

During the geologic past, conditions were favorable for 

both the generation and accumulation of biogenic gas in 

many areas. However, only for a few areas are data available for both the identification and the evaluation of 

resource potential (table 3). As a result, the identified resources are presumably only a portion of the total resources 

of ancient biogenic gas. In addition, the resource potential 

of gas in hydrates is not included. Below is a discussion of 

the resources grouped by habitat of occurrence. 

DELTAS 

The offshore Gulf of Mexico is a major hydrocarbonproducing province of the United States. Total gas resources for the area are estimated to be about 6,500 billion 

cubic meters (Bern) (U.S. Geological Survey and Minerals 

Management Service, 1989). Reservoirs of Pleistocene age 

contain major accumulations of natural gas, much of 

which is of biogenic origin. Unpublished data of the U.S. 

Geological Survey indicate that about 18 percent of the 

discovered gas in the province is in Pleistocene reservoirs. 

A similar distribution is expected for undiscovered resources. Although some thermogenic oil and gas have migrated from deeper, more mature intervals, Rice ( 1980) 

and Rice and Claypool (1981) estimated that about 7 5 

percent of the gas in Pleistocene reservoirs is of biogenic 

origin. On the basis of these percentages, Pleistocene reservoirs are estimated to contain about 884 Bern of biogenic gas. Additionally, older reservoirs are also likely to 

contain accumulations of biogenic gas. 

Ancient biogenic gas was also identified in other 

major hydrocarbon- producing deltas, such as the Baram, 

Mahakam, and Niger (fig. 6). Although the percentage of 

biogenic gas is not reported, these deltas contain major resources of natural gas (Baram, 1,000 Bern; Mahakam, 750 

Bern; Niger, 6,500 Bern) (K. Robinson, oral commun., 

1989; Masters and others, 1991 ). A portion of these total 

resources is of biogenic origin. 

In the Polish part of the Carpathian foredeep, resources 

of biogenic gas in Miocene deltaic deposits are estimated to 

be about· 283 Bern (M. Kotarba, oral commun., 1990). 

About half of these resources have been discovered. 

DEEP-WATER CLASTIC SETTINGS 

Mattavelli and Novelli (1988) estimated that 74 percent of the original gas reserves of Italy (414 Bern) are of 

biogenic origin. They also estimated that about 77 percent 

of the original gas reserves ( 431 Bern) in Italy occur in 

deep-water clastic rocks (turbidite sequences) in the Appennine foredeep. They further approximated that 82 percent of the gas in the foredeep, or 354 Bern, is of biogenic 

origin. If these percentages apply to undiscovered resources as well, then the total biogenic gas resources of Italy 

are on the order of 815 Bern. 

SHELF SETTINGS 

In southeastern Alberta and southwestern Saskatchewan, Canada, major biogenic gas reserves have been established in shallow ( <600 m), clastic, low-permeability 

reservoirs of Late Cretaceous age. The present area of production covers more than 20,000 km2, and the area of production is rapidly expanding. In the Alberta portion, 420 

Bern of gas reserves have been reported (Energy Resources 

Conservation Board, 1986). 

Similar, shallow reservoirs occur over a large part of the 

northern Great Plains of Montana and North and South Dakota, United States. The National Petroleum Council ( 1980a) 

estimated that a 310,000-km2 study area contains undiscovered, recoverable biogenic gas resources of 2,830 Bern. 

Biogenic gas production has been established in chalk 

beds of Late Cretaceous age in northeastern Colorado and 

northwestern Kansas. As of 1987, about 4 Bern had been 

produced (Lockridge and Pollastro, 1988). Recoverable 

gas resources of 34 Bern were assessed for the area by the 

National Petroleum Council (1980b). 

Chalk beds with almost identical characteristics are 

widespread on the eastern shelf of the Western Interior 

Seaway in North and South Dakota. Shurr and Rice ( 1987) 

estimated the biogenic gas resources of the chalk beds in 

this area to be I, 700 Bern. 

Gas blowouts occurring in the Gulf of Mexico and in 

the North Sea indicate the occurrence of relatively large 

quantities of undiscovered biogenic gas in those shelf settings as well (Hovland and Judd, 1988). 
600 THE FUTURE OF ENERGY GASES 

Table 3. Estimated volumes of biogenic gas. 

lVolumes in billion cubic meters. ---,not determined] 

Habitat and location Discovered volumes 

(cumulative production 

and reserves) 

Undiscovered volumes References 

Delta 

Offshore Gulf of Mexico 

Carpathian foredeep (Poland) 143 

'394 

(recoverable) 

140 

U.S. Geological Survey and Mineral 

Management Service (1989) 

M. Kotarba, oral commun. (1990) 

Deep-water clastic setting 

Apennine foredeep (Italy) 815 Mattavelli and Novelli (1988); Masters and 

others (1991 ) 

Shelf setting-Clastic 

Southeastern Alberta (Canada) 

Northern Great Plains (U.S.A.) 

420 

13 2,830 

(recoverable) 

Energy Resources Conservation Board ( 1986) 

National Petroleum Council; Rice and others 

(1990) 

Shelf setting-Carbonate 

Central and northern Rocky Mountains 

(U.S.A.) 

4 1,700 

(in place) 

National Petroleum Council (1980b); Shurr and 

Rice (1987); Lockridge and Pollastro (1988) 

Nonmarine setting 

Powder R,ivcr basin (U.S.A.) 

Qaidam basin (China) 

Cook Inlet, Alaska 

Japan 

West Siberia (Russia) 

122 

133 

2134,252 

1,100 

(in place) 

455 

(recoverable) 

32 

(recoverable) 

Choate and others ( 1984) 

Ulmishek (1984) 

Magoon and Kirschner (1990); R.F. Mast, oral 

commun. (1990) 

Marsden and Kawaii (1965) 

Grace and Hart (1986) 

I On the basis of discovered volumes, Pleistocene reservoirs are estimated to contain 18 percent of the total hydrocarbons in offshore Gulf of Mexico. Of the total 

gas in Pleistocene reservoirs, 75 percent is estimated to be of biogenic origin. 

2 Although there arc conflicting data, gases in Cenomanian reservoirs may be of biogenic origin. 

NONMARINE SETTINGS 

The Powder River basin has anomalously thick, lowrank coalbeds of Paleocene and Eocene age at depths less 

than 750 m. The coal resources have been estimated to be 

1.2 billion tons (Choate and others, 1984). Localized production of biogenic gas has recently been established in the 

coalbeds. Using an in-place methane content of 0.6 m3

/ton 

for the biogenic gas, an in-place gas resource of about 

1,000 Bern has been estimated for the coal beds of the Powder River basin (Choate and others, 1984). This biogenic 

gas resource potential is comparable to that of other U.S. 

coal-bearing basins that have mainly thermogenic coalbed 

gas (Rightmire, 1984). 

Biogenic gas commonly occurs in shallow ( <1 km) 

coalbeds of all ranks and ages; a large part of this gas was 

generated during relatively recent geologic time (late 

stage). Worldwide resources of coalbed gas are estimated 

to be as much as 260,000 Bern (Kuuskraa and others, 

1992), and an unknown portion of these total resources is 

of shallow biogenic origin. 

The eastern part of the Qaidam basin (China) was an 

area of rapid fluvial and lacustrine deposition during Quaternary time, when as much as 3,000 m of sediments were 

deposited. Biogenic gas has been produced from these 

sediments at depths as much as 1,400 m (Gu and others, 

1988). Ulmishek (1984) estimated the undiscovered biogenic gas resources of these sediments to be 445 Bern. 

Biogenic gas has been produced at depths as much as 

1,600 min the Cook Inlet of Alaska, United States (Claypool and others, 1980). The production is from nonmarine 

sandstones of Miocene and Pliocene age. This occurrence 

is significant because coalbeds interbedded with the sandstone reservoirs may be the source of the gas. About 122 

Bern of gas have been discovered from this sequence (Magoon and Kirschner, 1990), and an additional 32 Bern of 
BIOGENIC GAS: CONTROLS, HABITATS, AND RESOURCE POTENTIAL 601 

undiscovered gas resources are estimated (R.F. Mast, oral 

commun., 1990). 

In Japan, biogenic gas dissolved in formation waters 

was the main source of natural-gas production from the 

1920's to 1960's (Marsden, this volume). The reservoirs 

are sands and gravels of mostly Pliocene and Pleistocene 

age, and production is generally from depths less than 

2,000 m. Marsden and Kawaii (1965) have described the 

production and estimated the reserves to be about 133 

Bern. 

The West Siberia basin (Russia) has gas reserves of 

32,000 Bern (Grace and Hart, 1986), about one-third of 

the world's gas reserves. Much of the gas occurs in giant 

fields, and two of the fields, Urengoy and Yamburg, are 

the two largest gas fields in the world. Although thermogenic hydrocarbon production is established in the Jurassic and Lower Cretaceous sequence, 62 percent of the 

proven gas reserves are estimated to be in· the shallow 

Cenomanian reservoirs (Peterson and Clarke, 1991). Although conflicting gas compositional data have been presented, the origin of most of the Cenomanian gases is 

interpreted to be biogenic, as discussed in the previous 

section. The reserves of gas fields given by Grace and 

Hart (1986) and identified as being biogenic in origin according to data by Yermakov and others (1970) and Alekseyev (1974) total 13.425 Bern. 

Biogenic gas is estimated to account for as much as 

20 percent of the world's gas resources, both discovered 

and undiscovered. This figure appears to be heavily influenced by the huge accumulations in West Siberia that are 

of questionable biogenic origin. However, many discovered gas accumulations do not have data that permit a determination of their origin and an assessment of their 

resource potential, and many other accumulations have 

been bypassed and overlooked and are therefore undiscovered. The percentage of biogenic gas of the total hydrocarbon resource is quite variable on a regional basis. For 

example, in the Northern Great Plains of North America 

(Canada and United States), large biogenic gas accumulations occur where there is little thermogenic hydrocarbon 

potential. In contrast, many of the young deltas contain 

both biogenic and thermogenic gases. 

Ancient biogenic gas resources will be important in the 

future for several reasons. First, natural-gas prices have 

limited gas exploration. Second, biogenic gas accumulations may occur in areas which have been discounted for 

thermogenic hydrocarbon potential, but which probably 

had conditions favorable for the generation and accumulation of biogenic gas. Third, biogenic gas may occur in currently subeconomic accumulations because of their 

generally small volumes and unconventional reservoirs. 

The small accumulations can be used locally, as is the case 

for biogenic gas accumulations in glacial drift in the Illinois 

basin, United States (Meents, 1968) and in the Pearl, Qiantang, and Yangtze deltas, China (Zhang and Chen, 1985). 

Large quantities of biogenic gas are either dissolved (Buckley and others, 1958) or in hydrate structures (K venvolden, 

1988). In addition, large accumulations of biogenic gas 

occur in low-permeability reservoirs as discussed by Rice 

and Shurr (1980). However, biogenic gas accumulations 

that are dissolved, in hydrates, or trapped in low quality 

reservoirs will only be developed when gas prices rise and 

drilling and recovery technologies are improved. Fourth, 

gas reserves tend to decrease with increasing geologic age 

of the reservoir, with the largest amounts occurring in reservoirs of late Tertiary age (fig. 13) (Bois and others, 1982). 

This same trend will probably apply to undiscovered gas 

resources. Because biogenic gas accumulations are usually 

concentrated in young reservoirs, a significant portion of 

both reserves and undiscovered resources will probably be 

of biogenic origin. Finally, biogenic gas, which is mainly 

methane, is a low-pollution energy source. 

SUMMARY AND CONCLUSIONS 

Biogenic gas is generated at low temperatures by the 

breakdown of organic matter by anaerobic microbes and 

may exist where thermogenic hydrocarbons are absent. 

GAS 

AGE RESERVES 

109ni3fMY 

0 200 400600 

TERTIARY 

CRETACEOUS 

JURASSIC 

TRIASSIC 

PERMIAN 

CARBONIFEROUS 

DEVONIAN 

SILURIAN 

ORDOVICIAN 

CAMBRIAN 

Figure 13. Distribution of ultimate reserves of gas by age of reservoir. From 

Bois and others (1982). E, early; L, late; 

m3, cubic meters; MY, million years. 
602 THE FUTURE OF ENERGY GASES 

Where generated, biogenic gas can accumulate in significant quantities and be an important resource. It is important that biogenic gas be considered in future exploration 

strategies. 

1. A succession of metabolic processes leads to the 

generation of biogenic gas. Although fermentation is the 

pathway for generation in some modern environments, C02 

reduction is the most important pathway for ancient biogenic gas accumulations. The two main sources of C02 for 

reduction are (1) bacterial processes (sulfate reduction and 

fermentation) and (2) thermal decarboxylation of kerogen. 

2. Factors controlling methane generation after sediment burial are anoxic conditions, low sulfate content, low 

temperatures, abundant organic matter, sufficient pore 

space, and high deposition rate. 

3. Factors controlling accumulation of biogenic gas 

are stratigraphic or early structural traps, adequate seals, 

early dissolutio11 and later exsolution, formation of hydrates, low permeability, low pressure, and high rate of 

deposition. 

4. Most ancient biogenic gas was probably generated 

early in the burial history, at shallow depths ( <1 km), and 

subsequently buried to greater depths. Some biogenic gas, 

particularly in coalbeds, was probably generated during 

later stages of geologic history, commonly in association 

with groundwater flow. 

5. In most documented ancient accumulations, biogenic gas was generated from type III organic matter. The 

type of organic matter used by microbes in biogenic gas 

generation was probably controlled by the type that was 

available rather than the type that was preferred by the 

microbes. In settings of rapid deposition, type III organic 

matter is usually dominant. 

6. Ancient biogenic gases can be distinguished by molecular and isotopic composition. Biogenic gases are mostly methane that is generally enriched in the light isotope 

12c (methane 613c values lighter than -55 permil). Biogenic gases generated by the C02 reduction pathway generally have methane 6D values in the range of -150 to 

-250 permil, whereas biogenic gases formed by the fermentation pathway are generally enriched in deuterium 

(methane 6D values ranging from -250 to -400 perrnil). 

The interpretation of biogenic origin should also consider 

the geologic setting. 

7. Ancient biogenic gas accumulations are documented 

in Mississippian and younger sequences (significant accumulations are usually Cretaceous and younger), at depths 

less than 4,600 m (depth is usually dependent on age), and 

in thermally immature sequences. They occur in a variety 

of both marine and nonmarine sequences and in a variety of 

rock types (clastic, carbonate, and coal). Commercial accumulations have been documented in Africa, Asia, Europe, 

North America, and South America. 

8. Favorable depositional settings for the generation 

and accumulation of ancient bacterial gas accumulations 

are deltas, deep-water clastic settings, clastic and carbonate shelves, and nonmarine settings (in particular coal 

swamps). In almost all cases, these settings are favorable 

if deposition is rapid. 

9. Biogenic gas accounts for as much as 20 percent of 

the world's resources of natural gas. Biogenic gas accumulations will be more important in the future because they 

have previously been overlooked and bypassed in the past. 

ACKNOWLEDGMENTS 

I thank Charles N. Threlkeld, April Vuletich, and Augusta Warden of the U.S. Geological Survey for chemical 

and isotopic analyses of natural gases; many oil companies for their assistance in collecting gas samples; and R. 

Ames of Amoco Production Co., C. Clayton of BP International Limited, and G. Lijmbach of Shell Internationale 

Petroleum Mij. for gas analyses. 

REFERENCES CITED 

Alekseyev, F.A., 1974, Zonality in oil and gas formation in the 

earth's crust based on isotope studies: Geologiya Nefti i 

Gaza, v. (April), p. 62-67. English version in Petroleum Geology, v. 12, p. 53-71. 

Alekseyev, F.A., Lebedev, V.S., and Krylova, T.A., 1972, Isotope 

composition of carbon in gaseous hydrocarbons and conditions for accumulations of natural gas: Sovetskaya Geologia, 

no. 4, p. 35-47. English version in International Geological 

Review, v. 15, p. 300-308. 

Arthur, M.A., Dean, W.E., Bottjer, D.J., and Scholle, P.A., 1984, 

Rhythmic bedding in Mesozoic-Cenozoic pelagic carbonate 

sequences-The primary and diagenetic origin of Milankovitch-like cycles, in Berger, A., Imbrie, J., Hays, J., Kukla, 

G., and Saltzman, B., eds., Milankovitch and climate: Dordrecht, Netherlands, Reidel, p. 191-222. 

Arthur, M.A., Dean, W.E., Pollastro, R.M., Claypool, G.E., and 

Scholle, P.A., 1985, Comparative geochemical and mineralogical studies of two cyclic transgressive pelagic limestone 

units, Cretaceous Western Int,erior basin, U.S., in Pratt, 

L.M., Kauffman, E.G., and Zeit, F.B., eds., Fine-grained deposits and biofacies of the Cretaceous Western Interior Seaway-Evidence of cyclic sedimentary processes: Society of 

Economic Paleontologists and Mineralogists Field Trip 

Guidebook 4, p. 16-27. 

Avrov, V.P., and Galimov, E.M., 1968, Microbiologic nature of a 

methane pool detected at considerable depth (based on isotope analysis): Akademiya Nauk SSSR Doklady, v. 206, 

p. 201-202. 

Belyaev, S.S., Laurinavichus, K.S., and Gaytan, V.I., 1977, Modern microbiological formation of methane in the Quaternary 

and Pliocene rocks of the Caspian Depression: Geochemistry International, v. 14, p. 172-176. 

Bois, C., Bouche, P., and Pelet, R., 1982, Global geologic history and distribution of hydrocarbon reserves: American As-
BIOGENIC GAS: CONTROLS, HABITATS, AND RESOURCE POTENTIAL 603 

sociation of Petroleum Geologists Bulletin, v. 66, p. 1248-

1270. 

Buckley, S.E., Hocott, C.R., and Taggart, M.S., 1958, Distribution of dissolved hydrocarbons in subsurface waters, in 

Habitat of oil: American Association of Petroleum Geologists, p. 850-882. 

Burke, Jr., R.A., Martens, C.S., and Sackett, W.M., 1988, Seasonal variation of D/H and 13C/12C ratios of biogenic methane in surface sediments of Cape Lookout Bight, U.S.A.: 

Nature, v. 332, p. 829-831. 

Bustin, R.M., 1988, Sedimentology and characteristics of dispersed organic matter in Tertiary Niger delta-Origin of 

source rocks in a deltaic environment: American Association of Petroleum Geologists Bulletin, v. 72, p. 277-298. 

Chapman, R.E., 1980, Mechanical versus thermal cause of abnormally high pore pressures in shales: American Association of Petroleum Geologists Bulletin, v. 64, p. 2179-2183. 

Choate, R., Johnson, C.A., and McCord, J.P., 1984, Geologic 

overview, coal deposits, and potential for methane recovery 

from coalbeds-Powder River Basin, in Rightmire, C.T., 

Eddy, G.E., and Kirr, J.N., eds., Coalbed methane resources 

of the United States: American Association of Petroleum 

Geologists Studies in Geology 17, p. 335-351. 

Claypool, G.E., 1974, Anoxic diagenesis and bacterial methane 

production in deep sea sediments: Los Angeles, University 

of California, Ph.D. dissertation, 276 p. 

Claypool, G.E., and Kaplan, I.R., 1974, The origin and distribution of methane in marine sediments, in Natural gases in 

marine sediments: New York, Plenum Press, p. 99-139. 

Claypool, G.E., and Kvenvolden, K.A., 1983, Methane and other 

hydrocarbon gases in marine sediments: Annual Review of 

Earth and Planetary Sciences, v. 11, p. 299-327. 

Claypool, G.E., Threlkeld, C.N., and Magoon, L.B., 1980, Biogenic and thermogenic origins of natural gas in the Cook 

Inlet basin: American Association of Petroleum Geologists 

Bulletin, v. 64, p. 1131-1139. 

Clayton, C., 1992, Source volumetrics of biogenic gas generation, in Vially, R., ed., Bacterial gas: Paris, Editions Technip, p.191-204. 

Coleman, D.D., Chao, L.L., and Riley, K.M., 1988, Microbial 

methane in the shallow Paleozoic sediments and glacial deposits of Illinois, U.S.A.: Chemical Geology, v. 71, p. 23-40. 

Combaz, A., and De Matharel, M., 1978, Organic sedimentation 

and genesis of petroleum in Mahakam delta, Borneo: American Association of Petroleum Geologists Bulletin, v. 62, 

p. 1684-1695. 

Davis, J.B., and Squires, R.M., 1954, Detection of microbially 

produced hydrocarbons other than methane: Science, v. 119, 

p. 381-382. 

Diamond, S., 1970, Pore size distribution of clays: Clays and 

Clay Minerals, v. 18, p. 7-23. 

Dickey, P.A., and Cox, W.C., 1977, Oil and gas in reservoirs 

with subnormal pressures: American Association of Petroleum Geologists Bulletin, v. 61, p. 2134-2142. 

Dow, W.O., 1978, Petroleum source beds on continental slopes 

and rises: American Association of Petroleum Geologists 

Bulletin, v. 62, p. 1584-1606. 

Downey, M.W., 1984, Evaluating seals for hydrocarbon accumulations: American Association of Petroleum Geologists Bulletin, v. 68, p. 1752-1763. 

Energy Resources Conservation Board, 1986, Alberta's reserves 

of crude oil, oil sands, gas, natural gas liquids, and sulfur, 

31 December 1986: Energy Resources Conservation Board 

Reserve Report Series ERCB-18, 379 p. 

Faber, E., 1987, Zur isotopengeochemie gasformiger kohlenwasserstoffe: Erdol Ergas Kohle, v. 103, p. 210-218. 

Faber, E., and Stahl, W.,197111978, Anwendung von isotopenmethoden bei der exploration auf kohlenwasserstoffe: Compendium 77/78, Erganzungband der Zeitschrift Erdol und 

Kohle, Ergas, Petrochemie, p. 380-391. 

Fischer, A.G., Herbert, T., and Silva, J.P., 1985, Carbonate bedding cycles in Cretaceous pelagic and hemipelagic sequences, in Pratt, L.M., Kauffman, E.G., and Zeit, F.B., eds., 

Fine-grained deposits and biofacies of the Cretaceous Western Interior Seaway-Evidence of cyclic sedimentary processes: Society of Economic Paleontologists and 

Mineralogists Field Trip Guidebook 4, p. 1-10. 

Fuex, A.N., 1977, The use of stable carbon isotopes in hydrocarbon exploration: Journal of Geochemical Exploration, v. 7, 

p. 155-188. 

Galimov, E.M., 1968, Isotopic composition of carbon in gases in 

the crust: Izvestiya AN SSSR, no. 5, p. 29-44. English version in International Geological Review, v.11, p. 1092-1104. 

---1988, Sources and mechanisms of formation of gaseous 

hydrocarbons in sedimentary rocks: Chemical Geology, 

v. 71, no. 113, p. 77-95. 

Galloway, W.E., 1986, Growth faults and fault-related structures 

of prograding terrigenous clastic continental margins: Gulf 

Coast Association of Geological Societies Transactions, 

v. 36, p. 121-128. 

Gautier, D.L., and Claypool, G.E., 1984, Interpretation of 

methanic diagenesis in ancient sediments by analogy with 

processes in modem diagenetic environments, in McDonald, 

D.A., and Surdam, R.C., eds., Clastic diagenesis: American 

Association of Petroleum Geologists Memoir 37, p. 111-123. 

Gill, J.R., and Cobban, W.A., 1973, Stratigraphy and geologic 

history of the Montana Group and equivalent rocks, Montana, Wyoming, and North and South Dakota: U.S. Geological Survey Professional Paper 776, 37 p. 

Grace, J.D., and Hart, G.F., 1986, Giant gas fields of northern 

West Siberia: American Association of Petroleum Geologists 

Bulletin, v. 70, p. 830-852. 

Gu, S., Liu, D., and Shao, H., 1988, Generation of Quaternary 

gas in the eastern part of the Qaidam Basin, in Wagner, H.C, 

Wagner, L.C., Wang, F.F.H., and Wong, F.L., eds., Petroleum 

resources of China and related subjects: Circum-Pacific 

Council for Energy and Mineral Resources: Earth Sciences 

Series, v. 10, p. 557-575. 

Hovland, M., and Judd, A.G., 1988, Seabed pockmarks and seepages: London, Graham and Trotman, 293 p. 

Hovland, M., Talbot, M.R., Qvale, H., Olaussen, S., and Aasberg, 

L., 1987, Methane-related carbonate cements in pockmarks 

of the North Sea: Journal of Sedimentary Petrology, v. 57, 

p. 881-892. 

Hunt, J.M., 1979, Petroleum geochemistry and geology: San 

Francisco, W.H. Freeman, 617 p. 

Jenden, P.D., and Kaplan, I.R., 1986, Comparison of microbial 

gases from the Middle America Trench and Scripps Canyon-Implications for the origin of natural gas: Applied 

Geochemistry, v. 1, p. 631-646. 
604 THE FUTURE OF ENERGY GASES 

---1989, Origin of natural gas in Sacramento basin, California: American Association of Petroleum Geologists Bulletin, 

v. 73, p. 431-453. 

Jenden, P.D., Newell, K.D., Kaplan, I.R., and Watney, W.L., 

1988, Composition and stable-isotope geochemistry of natural gases from Kansas, Midcontinent, U.S.A.: Chemical Geology,.v. 71, p. 117-147. 

Jorgensen, N.O., Laier, T., Buchardt, B., and Cederberg, T., 1990, 

Shallow hydrocarbon gas in the northern Jutland-Kattegat 

region, Denmark: Bulletin of the Geological Society of Denmark, v. 38, p. 69-76. 

Kaiser, W.R., Swartz, T.E., and Hawkins, G.J., 1991, Hydrology 

of the Fruitland Formation, San Juan basin, in Geologic and 

hydrologic controls on the occurrence and producibility of 

coalbed methane, Fruitland Formation, San Juan basin: Gas 

Research Institute, Topical Report (August 1987-July 1990), 

GRI -9110072, p. 195-241. 

Koncz, 1.,1983, The stable carbon isotope composition of the hydrocarbon and carbon dioxide components of Hungarian natural gases: Acta Mineralogica-Petrographica, Szeged, v. 26, 

p. 33-49. 

Konig, H., 1992, Microbiology of methanogens, in Vially, R., 

ed., Bacterial gas: Paris, Editions Technip, p. 3-11. 

Kotarba, M., 1992, Bacterial gases in Polish part of the Carpathian Foredeep and the Flysch Carpathians-Isotopic and 

geological approach, in Vially, R., ed., Bacterial gas: Paris, 

Editions Technip, p. 133-145. 

Kotarba, M., Szafran, S., and Espitalie, J., 1987, A study of organic matter and natural gases of the Miocene sediments in 

the Polish part of the Carpathian foredeep: Chemical Geology, v. 64, p. 197-207. 

K venvolden, K.A., 1988, Methane hydrate-A major reservoir of 

carbon in the shallow geosphere?: Chemical Geology, v. 71, 

p. 41-51. 

Kvenvolden, K.A., and McMenamin, M.A., 1980, Hydrates of 

natural gas: U.S. Geological Survey Circular 825, 11 p. 

Kuuskraa, V.A., Boyer, C.M., II, and Kelafant, J.A., 1992, Hunt 

for quality basins goes abroad: Oil and Gas Journal, v. 90, 

no. 40, p. 49-54. 

Laier, T., Jorgensen, N.O., Buchardt, B., Cederberg, T., and Kuijpers, A., 1992, Accumulation and seepages of biogenic gas 

in northern Denmark: Continental Shelf Research, v. 12, 

p. 1173-1186. 

Law, B.E., Rice, D.D., and Flores, R.M., 1991, Coalbed gas accumulations in the Paleocene Fort Union Formation, Powder 

River basin, Wyoming, in Schwochow, S.D., Murray, D.K., 

and Fahy, M.P., eds., Coalbed methane of western North 

America: Denver, Rocky Mountain Association of Geologists, p. 179-190. 

Leythaeuser, D., Schaefer, R.G., and Pooch, H., 1983, Diffusion 

of light hydrocarbons in subsurface sedimentary rocks: 

American Association of Petroleum Geologists Bulletin, 

v. 67, p. 889-895. 

Leythaeuser, D., Schaefer, R.G., and Yukler, A., 1982, Role of 

diffusion in primary migration of hydrocarbons: American 

Association of Petroleum Geologists Bulletin, v. 66, p. 408-

429. 

Lockridge, J.P., and Pollastro, R.M., I 988, Shallow Upper Cretaceous Niobrara gas fields in the eastern Denver basin, in 

Goolsby, S.M., and Longman, M.W., eds., Occurrence and 

petrophysical properties of carbonate reservoirs in the Rocky 

Mountain region: Denver, Rocky Mountain Association of 

Geologists, p. 63-74. 

Magoon, L.B., and Kirschner, C.E., 1990, Alaska onshore national assessment program-Geology and petroleum resource 

potential of six onshore Alaska provinces: U.S. Geological 

Survey Open-File Report 88-450T, 47 p. 

Mah, R.A., Ward, D.M., Baresi, L., and Glass, T.L., 1977, Biogenesis of methane: Annual Review of Microbiology, v. 31, 

p. 309-341. 

Makogon, Y.F., Tsarev, V.I., and Cherskiy, N .V., 1972, Formation 

of large natural gas fields in zones of permanently low temperatures: Akademiya Nauk SSSR Doklady, v. 205, p. 215-

218. 

Marsden, S.S., and Kawaii, K., 1965, "Suiyosei-ten'nengasu," a 

special type of Japanese natural gas deposit: American Association of Petroleum Geologists Bulletin, v. 49, p. 286-295. 

Martens, C.S., Blair, N.E., Green, C.D., and Des Martais, D.J., 

1986, Seasonal variation in the stable carbon isotopic signature of biogenic methane in a coastal sediment: Science, 

v. 233, p. 1300-1303. 

Marty, D.G., 1992, Ecology and metabolism of methanogens, in 

Vially, R., ed., Bacterial gas: Paris, Editions Technip, p. 13-

23. 

Masters, C.D., Root, D.H., and Attanasi, E.D., 1991, World resources of crude oil and natural gas [preprint]: Thirteenth 

World Petroleum Congress, 14 p. 

Mattavelli, L., and Novelli, L., 1988, Geochemistry and habitat 

of natural gases in Italy, in Mattavelli, L., and Novelli, L., 

eds., Advances in organic geochemistry 1987: New York, 

Pergamon Press, p. 1-13. 

Mattavelli, L., Ricchiuto, T., Grignani, D., and Schocll, M., 

1983, Geochemistry and habitat of natural gases in Po basin, 

Italy: American Association of Petroleum Geologists Bulletin, v. 67, p. 2239-2254. 

Mechalas, B.J ., 1974, Pathways and environmental requirements 

for biogenic gas production in the ocean-Natural gases in 

marine sediments: New York, Plenum Press, p. 11-25. 

Meents, W.F., 1968, Illinois glacial-drift gas, in Beebe, B.W., ed., 

Natural gases of North America: American Association of 

Petroleum Geologists Memoir 9, v. 2, p. 1754-1758. 

Mink, R.M., Smith, C.C., Bearden, B.L., and Mancini, E.A., 

1988, Regional geologic framework and petroleum geology 

of Miocene strata of Alabama coastal waters area and adjacent federal waters area: State Oil and Gas Board of Alabama Oil and Gas Report 16, 64 p. 

Nakai, N., 1960, Carbon isotope fractionation of natural gas in 

Japan: Nagoya University Journal of Earth Sciences, v. 8, 

p. 174-180. 

Nakai, N., Yoshida, Y., and Ando, N., 1974, Isotopic studies on 

oil and natural gas fields in Japan: Chikyu Kagaku, v. 7/8, 

p. 87-98. 

National Petroleum Council, 1980a, Northern Great Plains/Williston Basin: Tight Gas Reservoirs, Part II, p. 10-1 to 10-

170. 

---1980b, Denver Basin: Tight Gas Reservoirs, Part II, 

p. 15-1 to 15-39. 

Nikaido, M., 1977, On the relation between methane production 

and sulfate reduction in bottom muds containing sea water 

sulfate: Geochemical Journal, v. 11, p. 199-206. 
BIOGENIC GAS: CONTROLS, HABITATS, AND RESOURCE POTENTIAL 605 

Oremland, R.S., Marsh, L.M., and Polcin, S., 1982, Methane production and simultaneous sulfate reduction in anoxic, salt 

marsh sediments: Nature, v. 296, p. 143-145. 

Oremland, R.S., Whiticar, M.J., Strohmaier, F.E., and Kiene, R.P., 

1988, Bacterial ethane formation from reduced, ethylated sulfur compounds in anoxic sediments: Geochimica et Cosmochimica Acta, v. 52, p. 1895-1904. 

Peterson, J .A., and Clarke, J. W., 1991, Geology and hydrocarbon 

habitat of the West Siberian basin: American Association of 

Petroleum Geologists Studies in Geology 32, 96 p. 

Pollastro, R.M., and Martinez, C.J., 1985, Mineral, chemical, and 

textural relationships in rhythmic-bedded, hydrocarbon-productive chalk of the Niobrara Formation, Denver basin, Colorado: Mountain Geologist, v. 22, p. 55-63. 

Rice, D.O., 1980, Chemical and isotopic evidence of the origins 

of natural gases in offshore Gulf of Mexico: Gulf Coast Association of Geological Societies Transactions, v. 30, p. 203-

213. 

---1984, Occurrence of indigenous biogenic gas in organicrich, immature chalks of Late Cretaceous age, eastern Denver 

Basin, in Palacas, J.G., ed., Petroleum geochemistry and 

source rock potential of carbonate rocks: American Association of Petroleum Geologists Studies in Geology 18, p. 135-

150. 

---in press, Composition and origins of coalbed gas, in 

Law, B.E, and Rice, D.D., eds., Hydrocarbons from coal: 

American Association of Petroleum Geologists Studies in 

Geology. 

Rice, D.O., and Claypool, G.E., 1981, Generation, accumulation, 

and resource potential of biogenic gas: American Association 

of Petroleum Geologists Bulletin, v. 65, p. 5-25. 

Rice, D.O., and Gautier, D.L., 1983, Patterns of sedimentation, 

diagenesis, and hydrocarbon accumulation in Cretaceous 

rocks of the Rocky Mountains: Society of Economic Paleontologists and Mineralogists Short Course Notes II, 332 p. 

Rice, D.O., Nydegger, G.L., and Brown, C.A., 1990, Bowdoin 

field-U.S.A., Bowdoin dome, Williston basin: American Association of Petroleum Geologists Atlas of Oil and Gas fields, 

Structural Traps III, p. 337- 355. 

Rice, D.O., and Shurr, G.W., 1980, Shallow, low-permeability reservoirs of northern Great Plains-Assessment of their natural-gas resources: American Association of Petroleum 

Geologists Bulletin, v. 64, p. 969-987. 

---1983, Patterns of sedimentation and paleogeography 

across the Western Interior seaway during time of deposition 

of Upper Cretaceous Eagle Sandstone and equivalent rocks, 

northern Great Plains, in Reynolds, M.W., and Dolly, E.D., 

eds., Mesozoic paleogeography of the west-central United 

States: Rocky Mountain Section, Society of Economic Paleontologists and Mineralogists, Rocky Mountain Paleogeography, Symposium 2, p. 337-358. 

Rice, D.O., and Threlkeld, C.N., 1983, Natural gas analyses from 

offshore Gulf of Mexico: U.S. Geological Survey Open-File 

Report 83-152,6 p. 

Rightmire, C.T., 1984, Coalbed methane resource, in Rightmire, 

C.T., Eddy, G.E., and Kirr, J.N., eds., Coalbed methane resources of the United States: American Association of Petroleum Geologists Studies in Geology 17, p. 1-15. 

Rijks, E.J.H., 1981, Baram delta geology and hydrocarbon occurrence: Geological Society of Malaysia Bulletin 14, p. 1-18. 

Risatti, J.B., 1987, Biogeochemistry of a temperate zone peat 

bog: Geological Society of America Abstracts with Programs, v. 19, p. 821. 

Schoell, M., 1980, The hydrogen and carbon isotopic composition of methane from natural gases of various origins: 

Geochimica et Cosmochimica Acta, v. 44, p. 649-661. 

---1983, Genetic characterization of natural gases: American 

Association of Petroleum Geologists Bulletin, v. 67, p. 2225-

2238. 

---1988, Multiple origins of methane in the Earth: Chemical 

Geology, v. 71, p. 1-10. 

Schoen, M., Tietze, K., and Schoberth, S.M., 1988, Origin of 

methane in Lake Kivu (east-central Africa): Chemical Geology, v. 71, p. 257-265. 

Scholle, P.A., 1977, Chalk diagenesis and its relation to petroleum exploration-Oil from chalks, a modern miracle?: 

American Association of Petroleum Geologists Bulletin, 

v. 61, p. 982-1009. 

Shurr, G.W., and Rice, D.O., 1987, Geologic setting and potential for natural gas in the Niobrara Formation (Upper Cretaceous) of the Williston basin, in Peterson, J.A., ed., 

Williston Basin-Exploration model for a cratonic petroleum province: Denver, Rocky Mountain Association of Geologists, p. 245-257. 

Tissot, B.P., and Welte, D.H., 1984, Petroleum formation and occurrence: Berlin, Springer-Verlag, 699 p. 

Tyler, R., Ambrose, W.A., Scott, A.R., and Kaiser, W.R., 1991, 

Coalbcd methane potential of the Greater Green River, 

Piceance, Powder River, and Raton basins: Gas Research Institute, Topical Report (January 1991-July 1991), GRI91/0315, 244 p. 

Ulmishek, G., 1984, Geology and petroleum resources of basins 

in western China: Argonne National Laboratory ANL/ES146, 131 p. 

U.S. Geological Survey and Minerals Management Service, 

1989, Estimates of undiscovered conventional oil and gas 

resources in the United States-a part of the Nation's energy 

endowment: U.S. Department of Interior, 44 p. 

Vogel, T.M., Oremland, R.S., and K venvolden, K.A., 1982, 

Low-temperature formation of hydrocarbon gases in San 

Francisco Bay sediment: Chemical Geology, v. 37, p. 289-

298. 

Warwick, P.O., and Stanton, R.W., 1988, Depositional models 

for two Tertiary coal-bearing sequences in the Powder River 

Basin, Wyoming, U.S.A.: Journal of the Geological Society, 

London, v. 145, p. 613-620. 

Whiticar, M.J., and Faber, E., 1986, Methane oxidation in sediment and water column environments-isotope evidence: Organic Geochemistry, v. 10, p. 759-768. 

Whiticar, M.J., Faber, E., and Schoell, M., 1986, Biogenic 

methane formation in marine and freshwater environments-C02 reduction vs. acetate fermentation-isotope 

evidence: Geochimica et Cosmochimica Acta, v. 50, p. 693-

709. 

Woese, C.R., Kandler, 0., and Wheelis·, M.L., 1990, Towards a 

natural system of organisms-Proposal for the domains Archaea, Bacteria, and Eucarya: Proceedings of the National 

Academy of Science (U.S.A.), v. 87, p. 4576-4579. 

Wolfe, R.S., 1971, Microbial formation of methane: Advances in 

Microbial Physiology, v. 6, p. 107-146. 
606 THE FUTURE OF ENERGY GASES 

Woltemate, I., Whiticar, M.J., and Schoell, M., 1984, Carbon 

and hydrogen isotopic composition of bacterial methane in 

a shallow freshwater lake: Limnology and Oceanography, 

v. 29, p. 985-992. 

Woodbury, H.O., Murray, LB., Jr., Pickford, P.J., and Akers, 

W.H., 1973, Pliocene and Pleistocene depocenters, outer 

continental shelf, Louisiana and Texas: American Association of Petroleum Geologists Bulletin, v. 57, p. 2429-2439. 

Yermakov, V.I., Lebedev, V.S., Nemchenko, N.N., Rovenskaya, 

A.S., and Grachev, A.V., 1970, Isotopic composition of carbon in natural gases in the northern part of the West Siberian Plain in relation to their origin: Alademiya Nauk SSSR 

Doklady, v. 190, p. 683-686. 

Zeikus, J.G., and Winfrey, M.R., 1976, Temperature limitation of 

methanogenesis in aquatic sediments: Applied and Environmental Microbiology, v. 31, p. 99-107. 

Zhang, Y.G., and Chen, H.J., 1985, Concepts on the generation 

and accumulation of biogenic gas: Journal of Petroleum Geology, v. 8, p. 405-422. 

Zobell, C.E., and Anderson, D.A., 1936, Vertical distribution of 

bacteria in marine sediments: American Association of Petroleum Geologists Bulletin, v. 20, p. 258-269. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

World Resources of Natural Gas-A Discussion 

By Charles D. Masters 1 

CONTENTS 

Abstract .... ... .. .. ..... .. ... .... .. ....... .. .... .. . ... .. ... .. .. .. .... ... ... ...... 607 

Introduction ................................................................... 607 

Natural-Gas Resources ................................................. 611 

Resource Occurrence and the Realms Hypothesis ...... 612 

Worldwide Natural-Gas Resources .............................. 614 

Market Considerations-Supply and Demand ............ 614 

Conclusions ................................................................... 616 

Acknowledgments ........................................................ 616 

References Cited ... ... ....... .. ....... ... .. ....... .. .. . ... . ... .. ... ..... ... 616 

ABSTRACT 

Conventional natural-gas resources are ultimately recoverable in the world in about the same quantities as crude 

oil. Like crude oil, there are also unconventional sources of 

natural gas that may someday be recovered in significant 

quantities. However, the availability of these unconventional resources at high flow rates and acceptable costs are not 

well understood. Further, the element hydrogen, available 

in water, can be recovered and used for many of the same 

purposes as natural gas and, presumably, someday may become available to the energy mix. To date, natural gas has 

been consumed in substantially smaller amounts than has 

crude oil (in terms of British thermal units, about one-half 

as much), so large excess quantities are. available, for production and future discovery, if transportation facilities and 

markets can be established. 

1

U.S. Geological Survey, National Center, 12201 Sunrise Valley Dr., 

Reston, VA 22092-0001. 

Unlike oil, most gas has been used within the country 

of origin primarily because of difficulties and costs of 

long-distance transportation from the point of production 

to the point of consumption. About 75 percent of the 

world's gas occurs in North America, the former Soviet 

Union, and in the Middle East. The United States has been 

a major consumer of natural ,gas, and its resources are substantially developed. In recent years, the former Soviet 

Union has been recognized as having the largest amount 

of recoverable natural-gas resources in the world and has 

become the largest producer and consumer of natural gas. 

However, natural-gas resources in the former Soviet Union 

are remote from markets, so export possibilities will have 

to await the production of smaller but better positioned 

gas resources. The second largest amount of recoverable 

natural gas is in the Middle East, but the lack of largescale industries and population there creates minimal demand. This area is also remote from centers of gas use. 

The geographic locations and relative quantities of 

conventional natural-gas resources in the petroleum basins 

of the world are shown in figure 1. Just as for oil, the 

largest gas resources are located in very few geographic 

areas, but they are remarkably well located for long-term 

market acquisition, however limiting the near-term prospects may be. 

INTRODUCTION 

Natural gas, like crude oil, is a nonrenewable resource 

but at this stage in resource development, the known and 

estimated world gas resources relative to annual consumption are very large. There is perhaps a century of significant supply (table 1). Unconventional resources (for 

example, coalbed methane, see Rice, this volume, or gas 

from very tight reservoirs, see Law and Spencer, this 

volume) are recognized, but to date they have not been 

607 
608 THE FUTURE OF ENERGY GASES 

Natural-Gas Resource 

(Tcf, trillion cubic feet) 

D Basin containing less than . 6 T cf 

D Basin containing from .6 to 6 Tcf 

• Basin containing from 6 to 60 Tcf 

D Basin containing from 60 to 120 Tcf 

• Basin containing from 

• Basin containing more than 600 Tcf 

Eckert VI Projection 

Figure 1. World map of petroleum basins showing estimated natural gas resources in six quantitative categories. 

Basins referred to in the text are numbered: I, Arabian-Iranian; 2, West Siberian; 3, Barents Sea; 4, North Caspian; 5, 

Erg Oriental; 6, Niger Delta; 7, Gulf Coast; 8, Western Canada Basin. Black lines are country and shoreline boundaries. Scale, I :I 05 million. 

considered economically recoverable in quantities and at 

rates sufficiently high to satisfy modern energy needs. 

Therefore, we separate conventional from unconventional 

resources herein because of the perceived economic and 

technological gap in their production potential. In fact, 

only in the United States and Canada has any substantive 

work been accomplished on the recovery of unconventional natural-gas resources. Considering the large conventional natural-gas reserves available elsewhere in the 

world, we are most likely, in the coming few decades, to 

witness, with respect to unconventional natural gas, only 

those activities necessary to satisfy modest local demand 

that could be provided by coalbed methane development 

and the best of tight-gas sands. 

Gas that cannot be used locally and does not have access to long-distance markets will not be produced until 

economic conditions result in a demand for it. In fact, an 

economically controlled sequence of gas derivation can be 
WORLD RESOURCES OF NATURAL GAS-A DISCUSSION 609 

assumed. This sequence starts with local conventional natural-gas resources being developed, produced, and transported by pipeline, and it progresses to international 

conventional natural-gas resources also being transported 

by pipeline. From conventional resources there will be a 

shift to liquefied natural-gas (LNG) resources or methanol 

(a chemical-conversion liquid product) being transported 

by ship worldwide. Then, domestic unconventional gas resources will be developed, produced, and transported by 

pipeline. Finally, possibly, hydrogen gas derived from the 

electrolysis of water may be developed and transported by 

pipeline. At any stage, a lesser cost fuel may replace gas 

in the energy mix, but we have a large natural-gas resource potential sufficient to warrant substantial reliance 

on the physical source for many decades to perhaps as 

long as a century in the· future. 

Each unique gas source will cost a little more than its 

predecessor. Conventional natural gas in the United States 

is now priced at the wellhead at about $1.50/thousand 

cubic feet (Mcf) but commonly twice that in Europe. 

LNG coming from various sources can possibly be landed 

in the United States for $3.50-$5.00/Mcf (see Attanasi, 

this volume). Unconventional gas, from various sources, 

may make significant contributions to the energy mix 

above $4/Mcf, but rates and quantities of daily production 

are unknown. Finally, hydrogen, at present, can be produced in quantity at about $9- 15/Mcf (see Veziroglu and 

Barbir, this volume). All estimates, of course, are subject 
610 THE FUTURE OF ENERGY GASES 

Table 1. World estimates of cumulative production, identified reserves, and undiscovered resources of conventional natural 

gas in trillions of cubic feet 1

• 

[All data not available for all countries] 

Gas production 

(1989) 

North America----------- 24.0 

Canada---------------- 4. 7 

Mexico---------------- 1.3 

United States---------- 18.0 

South America ----------- 2.3 

Argentina ------------- 0.9 

Bolivia---------------- 0.1 

Brazil----------------- 0.1 

Chile------------------- 0.1 

Colombia ------------- 0.1 

Ecuador---------------

Peru-------------------

Trinidad--------------- 0.1 

Venezuela------------- 0.7 

Western Europe --------- 6.7 

Italy------------------- 0.5 

Netherlands----------- 2.5 

Norway--------------- 1.1 

United Kingdom ----- 1.4 

Other------------------ 1.2 

Eastern Europe ---------- 1.8 

Greece-----------------

Romania--------------- 1.3 

Other------------------ 0.4 

U.S.S.R.--------------- 26.1 

Africa--------------------- 2. 7 

Algeria---------------- 1.9 

Angola ----------------

Chad-------------------

Egypt------------------ 0.2 

Gabon -----------------

Libya------------------ 0.4 

Nigeria----------------

Somali Republic------

Sudan------------------

Tunisia----------------

Other------------------ 0.1 

Middle East--------------- 2.8 

Bahrain --------------- 0.2 

Iran-------------------- 0.5 

Iraq-------------------- 0.1 

Kuwait ---------------- 0.2 

Neutral zone----------

Oman------------------

Qatar------------------ 0.3 

Saudi Arabia---------- 0.9 

Syria-------------------

United Arab 0.7 

Emirates. 

Other------------------

Asia/Oceania ------------- 4.6 

Afghanistan-----------

Australia/ 0.6 

New Zealand. 

Bangladesh------------

Burma-----------------

China------------------ 0.5 

India------------------- 0.3 

Indonesia-------------- 1.5 

Malaysia/Brunei ------ 0.3 

Pakistan --------------- 0.4 

Papua------------------

Thailand---------------

Vietnam---------------

Other------------------ 1.1 

World ------------- 71.0 

1m3 = 35.3 ft3 

Cumulative 

production 

850.5 

77.8 

23.2 

749.5 

38.7 

10.2 

1.8 

1.9 

2.9 

2.5 

0.1 

1.1 

2.8 

15.3 

127.1 

14.0 

54.5 

10.4 

24.7 

23.4 

48.6 

29.8 

18.8 

358.3 

32.6 

16.9 

1.5 

0.3 

5.8 

5.9 

0.1 

2.0 

57.5 

1.8 

17.6 

3.3 

5.5 

0.6 

2.9 

14.0 

1.5 

7.7 

2.5 

81.4 

1.0 

7.6 

0.1 

17.6 

1.8 

14.4 

5.0 

5.8 

28.1 

1594.6 

Identified 

reserves 

466.2 

97.0 

72.7 

296.4 

184.9 

26.3 

5.7 

4.1 

4.1 

4.0 

4.0 

7.0 

8.7 

121.0 

203.6 

11.6 

60.9 

93.1 

19.8 

18.3 

15.0 

3.4 

11.5 

1550.0 

261.6 

114.2 

11.5 

0.5 

29.2 

87.4 

3.1 

15.6 

1479.2 

6.3 

600.0 

110.0 

48.6 

8.0 

9.9 

300.0 

184.4 

5.5 

184.4 

22.1 

345.7 

77.4 

12.4 

5.1 

33.0 

20.9 

85.7 

65.8 

23.0 

4.5 

14.5 

3.5 

4506.1 

Original 

reserves 

1316.7 

174.8 

95.9 

1045.9 

223.6 

36.5 

7.5 

6.0 

7.0 

6.5 

4.1 

8.1 

11.5 

136.3 

330.7 

25.6 

115.4 

103.5 

44.5 

41.7 

63.6 

33.2 

30.3 

1908.3 

294.2 

131.1 

13.0 

0.8 

35.0 

93.3 

3.2 

17.6 

1536.7 

8.1 

617.6 

113.3 

54.1 

8.0 

10.5 

302.9 

198.4 

7.0 

192.1 

24.6 

427.1 

1.0 

85.0 

12.4 

5.2 

50.6 

22.7 

100.1 

70.8 

28.8 

4.5 

14.5 

31.6 

6100.7 

Undiscovered resources (111/90) 

95 percent 

531.0 

155.2 

70.4 

306.8 

147.6 

10.0 

4.7 

20.3 

0.5 

6.7 

3.5 

13.8 

3.9 

13.3 

138.5 

11.1 

5.0 

86.3 

9.4 

26.6 

17.3 

2.8 

6.9 

6.3 

738.5 

195.5 

5.6 

2.0 

0.5 

8.0 

0.5 

7.0 

80.0 

3.8 

15.7 

5.0 

35.7 

603.7 

300.0 

60.0 

3.0 

1.0 

5.0 

191.5 

31.8 

298.9 

8.8 

10.9 

4.8 

3.1 

103.9 

8.9 

47.0 

27.5 

15.0 

14.9 

12.6 

5.3 

14.9 

2777.1 

Mode 

816.7 

274.9 

118.9 

385.3 

254.0 

17.0 

7.8 

36.9 

0.8 

11.6 

6.1 

23.6 

6.9 

130.0 

225.7 

20.0 

6.6 

122.0 

16.0 

50.0 

29.4 

5.0 

12.0 

11.0 

1227.0 

328.3 

18.0 

4.3 

2.0 

21.0 

1.0 

18.0 

136.0 

12.9 

26.3 

12.0 

61.5 

943.4 

450.0 

100.0 

5.0 

2.0 

8.0 

300.5 

50.0 

486.3 

14.7 

18.9 

14.4 

8.4 

175.9 

16.5 

76.4 

45.0 

34.4 

25.0 

22.0 

10.0 

25.0 

4417.3 

5 percent 

1554.2 

800.0 

291.3 

507.2 

663.2 

43.0 

18.2 

120.8 

2.0 

31.3 

16.7 

60.8 

20.0 

380.0 

497.2 

62.0 

20.0 

195.0 

40.0 

200.0 

74.7 

15.0 

33.0 

30.0 

2861.0 

791.4 

53.0 

10.6 

6.0 

60.0 

2.0 

55.0 

340.0 

40.3 

62.1 

35.0 

162.2 

1865.0 

1000.0 

200.0 

10.0 

5.0 

18.0 

600.0 

100.0 

1067.1 

35.0 

50.0 

38.4 

17.3 

434.2 

61.7 

166.7 

100.0 

60.0 

60.0 

60.0 

40.0 

60.0 

9126.6 

Mean 

958.2 

399.0 

157.2 

399.0 

347.3 

22.9 

10.1 

57.4 

1.1 

16.1 

8.6 

32.0 

10.0 

189.2 

283.0 

30.1 

9.8 

133.8 

21.4 

88.0 

39.7 

7.4 

16.9 

15.4 

1582.1 

430.5 

26.3 

5.7 

3.0 

30.2 

1.2 

26.9 

181.7 

19.5 

34.1 

17.4 

84.5 

1125.3 

566.7 

119.9 

6.0 

2.7 

10.1 

360.0 

59.9 

608.6 

19.2 

26.0 

19.9 

10.2 

233.5 

27.8 

95.4 

56.7 

39.0 

32.7 

30.8 

17.6 

32.7 

5374.6 

Ultimate 

resources 

(mode) 

2133.4 

449.7 

214.8 

1431.2 

476.9 

53.5 

15.3 

42.9 

7.8 

18.1 

10.2 

31.0 

18.4 

266.3 

556.4 

45.6 

122.0 

225.5 

60.5 

91.7 

93.0 

5.0 

45.2 

41.3 

3135.3 

622.5 

149.1 

4.3 

2.0 

34.0 

1.8 

53.0 

229.3 

12.9 

26.3 

15.2 

79.1 

2480.1 

8.1 

1067.6 

213.3 

59.1 

10.0 

18.5 

302.9 

498.9 

7.0 

242.1 

24.6 

913.4 

15.7 

103.9 

26.8 

13.6 

226.5 

39.2 

176.5 

115.8 

63.2 

29.5 

36.5 

10.0 

56.6 

10517.3 
WORLD RESOURCES OF NATURAL GAS-A DISCUSSION 611 

to ongoing technological change, but it is important to understand that there are various price levels of gas-product 

availability, coming from different parts of the world, that 

can satisfy gas-market demand. Economic incentives and 

gas technology development that fully recognize the long 

lead times necessary to produce, develop, and distribute 

natural gas are needed to ensure the future delivery of 

natural gas to the market in a timely manner. Equally important are economic incentives for producers of natural 

gas that recognize the long lead times and large capital 

investments required to produce, develop, and distribute 

natural gas. 

In most parts of the world, natural gas is not developed to the degree of crude oil owing to limited market 

demand in production areas and difficult export conditions. 

In some parts of the world, LNG industries have developed to permit gas export. This is, however, an expensive 

activity and investors have not yet responded sufficiently 

to permit widespread adoption of the procedure. Only 

about 2 trillion cubic feet (Tcf) of LNG are produced each 

year, whereas some 75 Tcf of natural gas are consumed 

each year. As a result, large quantities of discovered identified reserves of natural gas remain undeveloped. Natural 

gas can also be moved by long-distance pipelines but that 

results in high initial costs. Also, in most parts of the 

world the gas has to cross international boundaries, which 

adds ongoing risk to the marketing venture. 

NATURAL-GAS RESOURCES 

Resources of conventional natural gas are very large 

(fig. I). Ultimately recoverable resources of natural gas 

occur in approximately equal British thermal unit (Btu) 

quantities to that of oil (Masters and others, 1991; figs. 2, 

3). However, because only about 40 percent as much gas, 

in a Btu sense, as compared to oil has been consumed, 

the worldwide gas industry is in a youthful stage. Our estimates show conventional natural gas to occur in slightly 

smaller quantities than oil but we believe gas discoveries 

to be underreported and that they will remain so until 

greater market demand requires adequate data development. We do not anticipate, however, that the ultimate 

values will necessarily increase to, in any way, substantially exceed the energy value of oil. Rather, we believe 

the occasionally reported very large resource values of 

gas ultimately will be identified as unconventional and we 

remain uncertain as to the satisfactory commercial production of those potential resources. Only in the United 

States and Canada is there substantial effort to try to develop unconventional gas resources and that is influenced 

by subsidy in the recovery of coalbed methane at a level 

of some 400 billion cubic feet (Bcf)/yr (out of a U.S. total 

annual production of 18 Tcf). The recovery of gas from 

tight sands in the United States is probably subsidized at 

Cl) 100 

(,) 2771 1: 

Cl) 

:r... 80 :r... 

:J 

(,) 

(,) 60 0 4417 

-0 

>- 40 

-

JJ 20 cu 

JJ 

0 9127 :r... 

IJ. 0 

0 2000 4000 6000 8000 10,000 

!1595 I 4500 

Produced Identified Reserves 

Discovered Resources 

Figure 2. Ultimate resources of natural gas (10,512 Tcf, or 1,752 

Bboe) shown in its component parts of cumulative production, 

identified reserves, and undiscovered resources. Undiscovered resources expressed as probability range showing 95th and 5th percentiles and mode. Units, trillion cubic feet. 

-0 

>- 40-

= 

:c 20 co 

.c 

0 1 47 ... 

a. o0 200 400 600 800 1000 1200 1400 1600 

629 1053 

Produced Identified Reserves 

Discovered Resources 

Figure 3. Ultimate resources of crude oil (2, I 71 B bo) shown in 

its component parts of cumulative production, identified reserves, 

and undiscovered resources. Undiscovered resources expressed 

as probability range showing 95th and 5th percentiles and mode. 

Units, billion barrels. 

about the same level (Crow and Kroen, 1992). The definition of "tight" and the identification of unconventional 

wells and fields is difficult, but production values are 

modest compared to those of conventional reservoirs, 

wells, and fields. Some 4,500 Tcf of identified reserves of 

conventional natural gas have already been discovered, 

and an approximately equal amount remains to be discov- · 

ered (fig. 2) (Masters and others, 1991 ). These quantities 

are enormous compared to the world annual rate of production of about 75 Tcf. 

Another measure of resource youthfulness is the general dates of discovery of worldwide gas reserves and their 
612 THE FUTURE OF ENERGY GASES 

a: 

< w 

> 

a: 

w 

a. 

1-

w 

w 

u.. 

(.) 

iii 200 

MIDDLE EAST 

:::J 

(.) 180 

"' 160 ~0 

140 D EASTERN EUROPE, FORMER 

SOVIET UNION, ASIA 

::::. 

(/) 

z 

0 

:J 

120 

100 

80 

WESTERN HEMISPHERE, 

AFRICA, WESTERN 

EUROPE 

...J 60 a: 

1-

~ 20 (/) 

< 

(.? 1915 1930 1945 1960 1975 1990 

Figure 4. World natural-gas annual discovery rate averaged over five-year periods, 1914 

to 1989. Annual production also shown. Units, trillion cubic feet. 

production (fig. 4). The peak of the discovery curve is in 

the late 1960's. This peak is depicted in the bar graph that 

shows quantities in terms of annual discoveries averaged 

over five-year intervals. This is only about I 0 years later 

than a comparable discovery peak for oil but, for gas, the 

shape of the curve is not yet defined. Within the last few 

years, for example, the Russians have discovered three 

large gas fields in the Barents and Kara Seas that, when 

fully reported, will likely raise the annual discovery value 

of the current 5-year interval to about 100 Tcf. These discoveries were in no sense surprises. The dimension of the 

world undiscovered resources, some 5,000 Tcf, and the expectation of their location, suggest that additional large discoveries will be forthcoming. Gas reserves are large and the 

undiscovered resource potential is sufficient to permit replacement and, indeed, growth of the existing reserves. 

Considering the present annual production is about 75 Tcf 

(63 percent of the Btu value of oil production), the identified reserve to production ratio (or approximate years of 

future production) is about 70; this ratio and the undiscovered resource potential indicate the capability of more than 

a century of significant conventional natural gas production 

sufficient to meet all or a large part of expected demand. 

The quantity of resources, then, seems to be the least 

of the problems. Rather, important issues relate to international cooperation and market development because much 

gas is not located favorably to match demand. This reality 

is expressed in a bar graph of gas resources distribution 

(fig. 5). The graph shows ultimate resources in terms of 

cumulative production, identified reserves, and undiscovered resources for seven geographical regions of the 

world. Three regions, North America, the former Soviet 

Union, and the Middle East, clearly dominate in resource 

occurrence; together they account for nearly 75 percent of 

the ultimate resources of natural gas. The other four regions of the globe-the Far East, Africa, Europe, and 

South America-possess important gas resources, however 

modest in individual dimension, considering their location 

relative to market and the youthfulness of their development. However, these four regions should not be counted 

on by world markets for significant long-term gas supply. 

RESOURCE OCCURRENCE AND THE 

REALMS HYPOTHESIS 

It is not surprising that the largest resources of natural 

gas are locally concentrated. All natural resources are similarly concentrated owing to the complexity of geologic factors that result in their formation. For a natural-gas resource 

to occur, five reasonably independent geologic variables 

must be favorable-these are availability-of source and reservoir rock, development of a trap, good quality seal, and 

timing. For a large resource, all factors must be substantially favorable. All factors being so favorable is a statistically 

rare occurrence, and that is confirmed by the few areas of 

the world in which large quantities of natural-gas resources 

are present. Our geologic studies of worldwide natural-gas 

resource distribution underscore this reality and permit us 

to argue that although the world is in no sense equally 

explored, we believe it is sufficiently explored to establish 

the distribution and general quantitative occurrence of natural-gas resources. With the support of the world resource 

studies, reported by Klemme and Ulmishek (199 I), we can 

consider their Realms hypothesis, which proposes a rationale for the varying concentration of petroleum resources in 

four separate areas of the globe. The percentages of resource occurrence shown on figure 6 refer to the discovered 

resources of both oil and gas: 68 percent in the Tethyan 

Realm; 23 percent in the Boreal Realm; 5 percent in the 

Pacific Realm; and 4 percent in the South Gondwana 

Realm. These percentages would not change significantly if 
0 

WORLD RESOURCES OF NATURAL GAS-A DISCUSSION 

tw 

w 2000 

u. Cumulative Production 

() 1500 

m D Identified Reserves 

:J 

() 1000 LL Undiscovered Resources 

0 

C\1 

,.... 

0 

,... 

-

en 

z 

0 

..J 

..J 

a: 

tz 

en -1500 <( FORMER 

" SOVIET 

UNION 

Figure 5. Geographic distribution of identified reserves and cumulative production of 

natural gas as of January 1990 and undiscovered resources as of January 1991. Units, 

trillion cubic feet. 

613 

EXPLANATION 

2500 MILES 

Boreal 

Realm 

6/ i~;).:} ] 

Tethyan 

Realm 

1111111111111111111 

South 

Gondwana 

Realm 

-

Pacific 

Realm 

• Major 

Resource 

• Moderate 

Resource 

Figure 6. Divisions of world petroleum occurrence for four geographically defined Realms with percent notations of the amount of 

discovered petroleum in each Realm. Symbol notations show the local occurrence of major or moderate reserves. Modified from 

Klemme and Ulrnishek, 1991. 
6I4 THE FUTURE OF ENERGY GASES 

the undiscovered resources estimated over the past ten 

years by the World Energy Resources Program of the U.S. 

Geological Survey were included (Masters and others, 

I99I ). The estimates of the World Energy Resources Program were derived completely independently of the Realms 

hypothesis. 

The geology of this highly skewed resource distribution phenomenon can be explained with reference to local 

tectonics as well as climate variations. These two factors 

specifically affect the development of source rocks, reservoir rocks, and sealing rocks, all of which are critical to 

the formation and entrapment of petroleum resources. The 

critical rock types form in warm climates characteristic of 

equatorial regions. The organic matter necessary for oil 

source-rock development flourishes between the 30° latitudes. Furthermore, lake turnover does not take place in 

warm climates; hence, the bottom-water lacustrine muds 

are protected from oxidation. Carbonate reservoir rocks, 

which contain about 50 percent of known reserves of entrapped petroleum, only form in low latitudes; their absence in high latitudes, therefore, precludes an important 

reservoir. Salt is the best sealing material for preventing 

vertical leakage from a reservoir, and it forms only between the 30° latitudes. 

All these favorable conditions characterize the Tethyan Realm, which, as defined, is located somewhat north 

of the equator. Its plate tectonic position, during development of the critical rock sequences, however, was generally equatorial-that is, between the 30° latitudes. The 

Boreal Realm is significantly more favorable than the 

South Gondwana Realm because in Paleozoic time the 

geologic area defined as Boreal was located near the 

equator and hence the prevailing climate favored the formation of critical stratigraphy. South Gondwana, on the 

other hand, remained in the high latitudes until the continental breakup in Late Jurassic, which permitted the continents to move north into the favorable low latitudes. 

The Boreal Realm was also characterized by nonmarine, 

gas-prone Carboniferous source-rock development. For 

unknown reasons, Southern Hemisphere coal development 

is of poorer quality than coal development in the Northern Hemisphere and has not resulted in highly productive 

gas-p~one source rock. 

The Pacific Realm has limited proven petroleum resources owing to destructive tectonics. Subduction has destroyed most of the pre-Tertiary stratigraphy, and the 

younger reservoir rocks were damaged by volcanic debris 

mixing. Certain localities such as southern California have 

been free of limiting factors, but such geologic reprieves 

are rare around the Pacific Basin. 

Statistically, large amounts of petroleum resources are 

rare. The Realms hypothesis offers climatic and tectonic 

conditions that control the geologic occurrence of petroleum-and these conditions both enhance and limit its 

occurrence. 

WORLDWIDE NATURAL-GAS 

RESOURCES 

Basin locations of worldwide natural-gas occurrence 

are shown on figure 1. Natural-gas resources by country 

are listed in table I. The basins shown on figure I are 

categorized by estimates of the natural-gas resources they 

contain. Resources consist of identified reserves plus a 

modal value for undiscovered resources or, in other words, 

the future potential of the basin. The two largest sources 

of natural gas in the world are in the Arabian-Iranian 

Basin and the West Siberian Basin. Those areas are shown 

as having more than 600 Tcf of natural-gas resources, but, 

in fact, West Siberia is estimated to contain more than 

1,500 Tcf of natural-gas resources and the Arabian-Iranian 

Basin has likely more than 2,000 Tcf of natural-gas reserves. Only six other basins in the world (Gulf Coast, 

Western Canada, Barents Sea, North Caspian, Erg Oriental, and Niger Delta) are recorded in the next largest reserves category of 120 to 600 Tcf. It is not surprising to 

find this degree of skewed distribution in natural-gas resources for both statistical and geologic reasons. Only one 

potentially very large gas basin remains minimally explored-the Barents Sea Basin. One large field, Schtockmanov, was recently discovered in the eastern part of the 

basin and is reportedly as large as 150 Tcf. With the discovery of this one field, the basin has a futures value within the top few basins in the world. However, the 

remoteness of the area, coupled with the gas reserves excesses already established in the region, suggests that significant development may not take place for many years. 

However, responsible international firms are, today, investigating the investment possibilities of this area. 

MARKET CONSIDERATIONSSUPPLY AND DEMAND 

To establish export capability, an area should have 

from 6 to 60 Tcf of natural-gas resources. Anything less 

than that does not offer sufficient resources for a significant commercial venture. Several years ago when El Paso 

Natural Gas Company and Occidental Petroleum Corporation made initial efforts to develop a gas program in East 

Siberia, they considered that a minimum discovery of 30 

to 40 Tcf was necessary to initiate activity; they did not 

achieve that minimum before other factors halted the initiative. Upon inspection of the gas futures map perhaps 

approximately one-half to two-thirds of the potential gas 

exploration area of the world meets that standard of having, at least, a few tens of Tcf of natural-gas resources. 

Broad regions that do not appear to meet that standard include the West Coast of the United States and Canada, 

northeastern Canada, most of offshore East Coast of the 
WORLD RESOURCES OF NATURAL GAS-A DISCUSSION 615 

United States, most of Mexico and Central America, central and southern South America, most of southern and 

western Africa, central Europe, and much of southeastern 

Asia and Australia. The point here is not to be precise 

about where gas will or will not be exported from, but 

rather to call attention to the fact that many areas of the 

world are not likely to be in a position to take part in 

export supply-development planning. 

One consideration in analyzing the supply side of export potential is the determination of whether or not the 

country will use natural gas. A further consideration is 

whether the country is, in fact, willing to export the gas or 

possibly subsidize the export by making the gas available 

at below-market prices to balance against pipeline costs, 

the additional technical costs of LNG processing, or the 

costs of manufacturing liquid fuels from the gas. 

The largest limitation to natural-gas resource development in the near term is the limited worldwide demand. At 

present, there are only three centers of potential increased 

natural-gas demand-North America, western Europe, and 

the Asian Pacific Rim. Most natural gas is used in the 

country of origin-only 15 percent goes to an export market as opposed to 40 percent for crude oil (Energy Information Administration, 1992). In 1990, the United States 

received about 1.5 Tcf of natural gas from Canada out of a 

total consumption of about 19 Tcf. There is also an occasional small spot-market cargo of LNG coming into Boston from Algeria. The most likely source for immediate 

pipeline increases in imports to the United States is Canada. The nearest and most likely sources for increased LNG 

imports to the United States, when that demand increases, 

are eastern Venezuela and Trinidad. The Cristobal Colon 

LNG project, sponsored by Exxon, Shell, Mitsubishi, and 

Petroleos de Venezuela, has a late 1990's target date for 

being on production. Whether or not they meet that target 

surely depends on market access to the United States. Demand for LNG in the United States is limited overall by 

market demand for natural gas and by offtoading capacity, 

which may or may not expand owing to regulatory restrictions derived from environmental concerns (Attanasi, 

1991). The current free-market atmosphere for trading, 

however, may provide a way around the LNG landing limitation by permitting the LNG to be offloaded in northern 

Mexico and be transported to the United States by naturalgas pipeline. 

The United States is the only near-term demand target 

in the Western Hemisphere. Eastern Canada could become 

a target if more of their western gas is exported to the 

United States. Supply areas that could consider U.S. and 

Canadian demand include, in addition to Venezuela and 

Trinidad: Nigeria, Algeria; Norway, and possibly Russia 

out of the Barents Sea. Colombia and Peru could become 

a modest source of LNG to the U.S. Pacific Coast, but 

considering the position of the Canadian and Alaskan gas, 

one might reason that South American development will 

create a demand for the local gas resources before North 

American demand materializes. 

The intent of this paper is not to project supply and 

demand, but rather to show some of the available resource 

information that might contribute to future specific gasmarket analysis. Already, initial studies have been conducted by Department of Energy to evaluate foreign 

sources of natural gas relative to specific U.S. landing 

sites. These studies suggest that the most economic providers would be Venezuela and Trinidad followed by 

Algeria and Libya (Department of Energy, 1992). Interestingly, several potentially larger sources of supply including Nigeria, the former Soviet Union, and the countries in 

the Arabian Iranian Basin are, in fact, higher cost providers for a variety of reasons. 

The Eastern Hemisphere contains the largest gas resources of the world. Most of them, being concentrated in 

West Siberia and in the Arabian-Iranian Basin (table 1), 

are not readily accessible to export markets. The West Siberian gas is predominantly used within the former Soviet 

Union; all but 4 Tcf, out of 28 Tcf of annual production, is 

used there. The 4 Tcf of export gas goes to eastern and 

western Europe in about equal proportions (Energy Information Administration, 1992). Given the size of this gas 

resource, within a large industrialized society, it may make 

sense to use the gas internally and export the oil. Some 

data suggest they have already made that decision; for example, at peak production of oil, they exported one-third 

of the production (4 million barrels of oil per day export 

(bopd) out of 12 million bopd production) whereas, for 

gas they exported 4 Tcf out of 28 Tcf production or only 

one-seventh of the production. Another indication of substantive local use of natural gas is the fact that only 0.4 

percent of production is vented or flared (Energy Information Administration, 1992). To date, the limit on gas export from the former Soviet Union very likely was market 

demand; in the future, it may be limited by their internal 

energy strategy along with the limiting economics of gas 

transport. 

The Arabian-Iranian Basin gas resource constitutes 

one of the greatest energy market problems in the world. 

The gas is concentrated in the largest oil-energy export locality in the world and one that has essentially no local 

industry. To be used, the gas must be exported. Nearby 

populations in Africa and India are large but without 

money. Transport to industrialized Europe is awkward, 

both politically and geographically. Access to the Pacific 

Rim means the gas must pass through a moderately rich 

area of natural gas in southeast Asia-an area with minimum local demand and maximum incentive to export, as 

they are presently doing. One can hope for improvement 

in the industrial and economic future of India but, otherwise, a small market on the Pacific Rim must be shared 

with southeast Asia suppliers in better geographic position 

to serve but somewhat balanced by that area being more 
616 THE FUTURE OF ENERGY GASES 

expensive to develop (Department of Energy, 1993). 

Given growth in the Asian industrial market, most certainly, the Middle East gas is the only available long-term 

supply. 

Gas is abundant in only a few places, but it is widespread in occurrence. Therefore, many countries appear to 

have sufficient resources to satisfy local demand for limited time periods-given continued modest economic conditions. This reasoning applies to most of South America 

(exclusive of Venezuela), Africa (exclusive of the northern 

border states), and Australia. The economic risk in these 

areas, however, is high because much of the gas resources 

have not as yet been developed (table 1). However, in Nigeria a large resource has been discovered, but exploration, 

development, and transportation costs limit its export. Possibly, that reality anchors its energy contribution to Africa 

with distribution by electric powerlines from gas-turbine 

power sources. Again, there are vast resources but a very 

limited market that must eventually be served but possibly 

by inventive means. China also appears to have reasonably 

sustainable supplies but, as yet, lacks the infrastructure development to take advantage of the resource. 

The demand center for natural gas in the Eastern 

Hemisphere is western Europe and, fortunately, it has 

modest resources in several countries and substantial resources in the North Sea. The southern North Sea and 

western Europe gas resources derive from coal source 

beds. These gas resources add significantly to the larger 

resources farther north that derive from the deep burial of 

the same marine, black-shale source rock that produces the 

North Sea oil. The concentration of the present supply 

north of the western European population center allows 

supplies to come to southern Europe from North Africa. 

Algeria, in particular, has large contributions to make, and 

their gas is conveniently inexpensive enough to shut out 

competitive sources from the former Soviet Union or 

countries of the Arabian-Iranian Gulf. Should industrial 

development eventually reach North Africa, Arabian-Iranian gas will still be available and, even later, high-cost gas 

from deep drilling in deep water of the Mediterranean 

could prolong the hydrocarbon energy resources of the circum-Mediterranean area. 

CONCLUSIONS 

Natural gas is present as a very large discovered and 

potential energy resource throughout the world, but, owing 

to difficult transportation realities, all sources of supply 

and demand have not been brought into communication by 

the market. The technology to transport gas in both gaseous and liquid forms is well advanced, but because, for 

many uses, oil, gas, and coal can replace one another, economic equity is required in all import-export transactions. 

Three energy demand centers for natural gas-North 

America, western Europe, and the Pacific Rim-are evolv- · 

ing and the technology for local use in these areas suggests that natural-gas consumption will increase. This 

increased consumption will be influenced both by the declining availability of oil and the less damaging environmental effects of producing and using natural gas as 

compared to oil and coal. 

ACKNOWLEDGMENTS 

This paper is derived from the work of scientists and 

analysts who are part of the World Energy Resources Program of the U.S. Geological Survey. These people are 

James Clarke, James Peterson, Gregory Ulmishek, Keith 

Robinson, Mahlon Ball, Jack Kingston, Doug Klemme, 

David Root, and Emil Attanasi. Ongoing coordination with 

Gary Long and Jack Sanders of the Foreign Energy Supply Assessment Program of the Department of Energy, Energy Information Administration was essential. Bob Turner 

of the U.S. Geological Survey prepared figure 1. The Petroconsultants data system provided basic data for the 

World Energy Resources Program studies and this report. 

REFERENCES CITED 

Attanasi, E.D., 1991, Alternative natural gas contract and pricing 

structures and incentives for the LNG Industry, Natural Resources Forum, Aug. 1991, p. 190-201. 

Crow, P., and Kroen, A.D., 1992, Tight gas sands drilling buoying U.S. exploration and development activity: Oil and Gas 

Journal, Nov. 2, 1992, p. 21-27. 

Department of Energy, 1993, Assessment of costs and benefits of 

flexible and alternative fuel use in the U.S. transportation 

sector: Technical Report 9, Development Costs of Undeveloped Nonassociated Gas Reserves in Selected Countries, 

DOE/EP-003, 84 p. 

Energy Information Administration, 1992, International energy 

annual 1991, DOE/EIA-0219(91), 183 p. 

Klemme, H.D., and Ulmishek, G.F., 1991, Effective petroleum 

source rocks of the world-Stratigraphic distribution and 

controlling depositional factors: American Association of Petroleum Geologists Bulletin, v. 75, no. 12, p. 1809-1851. 

Masters, C.D., Root, D.H., and Attanasi, E.D., 1991, World resources of crude oil and natural gas, Proceedings of the 

Thirteenth World Petroleum Congress: New York, John 

Wiley and Sons, p. 51-64. 
The development and use of energy gases are closely 

related to environmental and societal issues. Society's 

energy systems have generally evolved toward cleaner 

and more efficient forms of fuel, mainly from wood to 

coal to oil to natural gas. Governments, faced with 

global, energy-related environmental problems, are 

looking for fair and effective ways to encourage cleaner 

energy systems. Natural gas is the cleanest burning 

of all fossil fuels, in terms of air pollutants and some 

greenhouse gases. However, natural gas is mostly 

methane, which is increasingly regarded as an important greenhouse gas. Therefore, increased extraction, 

transportation, and use of natural gas must be conducted with intent to minimize methane leakage. 

THE ENVIRONMENT AND SOCIETY 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Environmental Consequences of Increased Natural-Gas Usage 

By Frances Cole1 

CONTENTS 

Abstract ... .. .... .. . . .............. ... .... .. ... .... ...... ... ... .. .. . ... ... . . . . . .. 619 

Introduction ................................................................... 619 

Fossil Fuels and the Greenhouse Effect ....................... 620 

Greenhouse Gases ..... .... ... ... .. .. .... ..... .. ....... .. ...... .. ... 620 

Carbon Dioxide .. ....... ... .. .. ... . ..... .. ... . . .... . ... .... .. . 622 

Methane ....... ... ... ... . .. .. . .. . . .. ... ... ... . ..... .. .... ... ....... 624 

Other Greenhouse Gases .. . ..... .... ... ..... .. .... .. ... .. 625 

Climate Change? .................................................... 625 

Methane and Stratospheric Ozone ....... .. . . . . .. . . . . . . . . .. .. . ... 625 

Fossil Fuel Emissions and Atmospheric Oxidants ..... 626 

Air Pollution and Acid Precipitation ............................ 626 

Particulates ............................................................. 627 

Sulfur Dioxide ....................................................... 628 

Nitrogen Oxides ..................................................... 629 

Acid Precipitation . ... ..... .. .. ......... ... .... ..... .. .... ... ... .. .. 630 

Volatile Organic Compounds and Carbon 

Monoxide ............................................................... 631 

Local Environmental Issues ......................................... 631 

Conclusions ...... ... ........ .. ...... .. .. ..... .. .... ..... .. . .... ... ... ... ... ... 632 

References Cited ........................................................... 633 

ABSTRACT 

Energy use is the primary cause of many environmental problems in the United States and around the world. 

Fossil fuels, including coal, oil, and natural gas, supply 

roughly 90 percent of our energy needs in the United 

States, and they are directly responsible for urban and industrial air pollution and acid rain. Combustion emissions 

1

U.S. Geological Survey, MS 955, 345 Middlefield Rd., Menlo 

Park, CA 94025. 

from fossil fuels also contribute to the Earth's greenhouse 

effect, and they may play an important role in ozone depletion in the stratosphere, and oxidant depletion in the 

troposphere. 

Natural gas, which is mostly methane, is the least polluting of the fossil fuels. Upon combustion, natural gas 

produces lower C02, CO, NOx, S02, and particulate emissions than either oil or coal. This means that substitution of 

natural gas for oil and coal can help mitigate air pollution 

and the human contribution to the greenhouse effect. However, methane is itself a potent greenhouse gas, and increased production and consumption of natural gas must be 

conducted in such a way that gas leakages are minimized. 

Natural gas compares well to the other fossil fuels in terms 

of water quality, preservation of natural ecosystems, and 

safety. These combined advantages may give natural gas a 

more prominent role in the U.S. energy mix. Like other 

fossil fuels though, natural gas is nonrenewable and, therefore, not a permanent solution to our energy needs. 

INTRODUCTION 

Many environmental problems that we face today stem 

from the use of fossil fuels for energy (Ehrlich and Ehrlich, 

1991). Increased concentrations of many greenhouse gases 

and toxic air pollutants are tied to rising production and 

consumption of fossil fuel energy (see U.S. Environmental 

Protection Agency, 1992; Holdren, 1992). Since the beginning of the Industrial Revolution some 150 years ago, 

countries like Great Britain and the United States have increased by 100-fold their energy consumption. The United 

States now uses 80 quadrillion British thermal units annually-10 times the energy use of most developing nations. At 

the same time, developing nations are striving to attain economic, technologic, and social standards comparable with 

their industrialized neighbors. As populations increase, and 

619 
620 THE FUTURE OF ENERGY GASES 

as more people gain access to amenities that are considered 

indispensable in the developed nations, such as household 

electricity and private transportation, energy consumption 

will grow. If current trends continue, world energy consumption may double by the year 2020 (Pexton, 1984). 

This trend does not necessarily portend a doubling of 

worldwide energy-related pollution. Technological advances in energy efficiency and pollution control tend to follow 

where energy production and consumption have gone before. In the United States, for example, per capita use of 

motor vehicles has more than doubled over the past 20 

years, yet air pollution from motor vehicles has been reduced nationwide by nearly 50 percent; this reduction is 

largely due to the adoption of catalytic converters (U.S. 

Council on Environmental Quality, 1992a). In addition, 

many economists see human civilization moving on a longterm trend toward cleaner energy fuels. Heavily polluting 

hydrocarbon fuels such as wood and coal have given way 

to cleaner hydrocarbon fuels such as oil and natural gas 

(Nakicenovic, this volume). Ultimately, oil and natural gas 

may be replaced by virtually nonpolluting forms of energy, 

such as a solar-hydrogen gas system (Ausubel, 1991 ). 

In light of these trends, natural gas is expected to gain 

increasing importance as an energy fuel in the United 

States, particularly in the transportation and power-generation sectors. Already, natural-gas powered cars and buses 

are being used as low-emission alternatives to gasoline 

and diesel vehicles in many cities across the country. In 

the Midwest and Northeast, electrical generation plants 

powered by natural gas have gained recognition for low 

emissions of nitrogen and sulfur compounds compared 

with conventional coal-burning plants. But what are the 

broader implications of increased use of natural gas? What 

issues need to be considered in attempting to understand 

the benefits and the problems of replacing existing fuels 

with natural gas? Herein, I summarize the environmental 

implications of increased use of natural gas, and provide 

an overview of the questions that remain to be answered. 

FOSSIL FUELS AND THE 

GREENHOUSE EFFECT 

Today, roughly 90 percent of all energy consumed in 

the United States comes from the combustion of fossil 

fuels (fig. 1). Fossil fuels include coal, oil, natural gas, and 

their various energy offspring, such as gasoline and diesel 

fuel. These hydrocarbon compounds form in soils and buried marine sediments, through the breakdown of organic 

material by bacterial decomposition or heating (Wiese and 

Kvenvolden, this volume). Through these mechanisms, 

carbon is transferred from the biosphere and made available for storage in the Earth's crust. During the combustion of hydrocarbon fuels, the stored carbon and hydrogen 

are released back into the atmosphere-carbon in the form 

HYDRO 

NUCLEAR 4% 

NATURAL GAS 

25% 

Figure 1. U.S. energy consumption in percent, by primary source, 

for 1992. From U.S. Department of Energy (1992). 

of C02 and hydrogen as water vapor. These principal 

emissions from hydrocarbon fuels are benign under normal conditions. However, the concentration of C02 in the 

atmosphere has grown rapidly since the Industrial Revolution, raising concerns over the human impact on the 

Earth's natural greenhouse effect. 

GREENHOUSE GASES 

The dry atmosphere is composed of 78 percent nitrogen gas (N2), 21 percent oxygen (02), and 1 percent trace 

gases, including argon (Ar; .93 percent), carbon dioxide 

(C02; .035 percent), methane (CH4; .0001 percent), and 

hydrogen (H2; .00005 percent). Roughly 75 percent of 

these gases resides in the troposphere, the lower 12 kilometers of the atmosphere, whereas the remainder is distributed through the stratosphere, which extends to about 50 

kilometers above the Earth's surface. Atmospheric pollutants from fossil fuels and other industrial processes occur 

as trace gases with low concentrations relative to the main 

atmospheric constituents. However, because of the complex coupling between the atmosphere, the oceans, and the 

biosphere (Meehl and Schimel, 1993), and because of the 

sensitivity of species and ecosystems to environmental 

changes, a seemingly small change in the chemistry of the 

atmosphere can have a profound impact on living organisms. A case in point is the greenhouse effect. 
ENVIRONMENTAL CONSEQUENCES OF INCREASED NATURAL-GAS USAGE 621 

The greenhouse effect refers to a warming that occurs 

when certain atmospheric gases-primarily water vapor, 

carbon dioxide, methane, nitrogen oxides, carbon monoxide, and ozone-trap infrared radiation near the Earth's 

surface (fig. 2). These greenhouse gases allow short-wavelength energy from the Sun to pass through the atmosphere, but they prevent the escape of longer wavelength, 

infrared energy that is reradiated by the Earth. By absorbing some of this outgoing radiation, the greenhouse gases 

moderate the temperature of the Earth, maintaining a comfortable average surface temperature of 14 to l5°C (58°F). 

Without the greenhouse effect the average temperature at 

the Earth's surface would be a chilly -I8°C (0°F) (Wuebbles and Edmonds, 1991). 

The importance or warming potential of a particular 

greenhouse gas depends on its abundance, the wavelengths 

of solar radiation that it absorbs, and its atmospheric lifetime. The wavelengths of radiation that arrive from the Sun 

and those that are reradiated from the Earth are shown in 

figure 3. Also shown are the ranges of energy wavelengths 

absorbed by specific greenhouse gases. Carbon dioxide and 

water vapor are the most important greenhouse gases 

because they are abundant, and they are extremely effective at absorbing certain wavelengths of infrared energy, 

mostly between I and 7 micrometers, and above 14-micrometers. Other gases that absorb the same wavelengths 

have little influence, because carbon dioxide and water 

vapor soak up nearly all the radiation available in these 

bands. Conversely, trace gases of lower concentration (less 

than .000 I percent) such as methane, ozone, and chlorofluorocarbons, are important because they absorb infrared in 

Figure 2. The Earth's greenhouse effect. 

the 7- to 14-micrometer wavelength window where other 

gases are ineffective (fig. 3). The present atmosphere allows 80 percent of the energy in the 7- to 14-micrometer 

window to escape to space; this condition leaves a potentially large role for gases that absorb these energy bands 

(Ramanathan, 1988). 

The atmospheric lifetime or residence time of greenhouse gases is also very important (Graedel and Crutzen, 

1993). Most greenhouse gases are removed from the atmosphere by chemical reactions or photodissociation-the 

breakdown of gas molecules by radiant energy from the 

Sun. Methane, for example, reacts with atmospheric oxidants to form carbon dioxide and water vapor. Its residence time is approximately 10 years, which means that if 

we shut off all anthropogenic sources of methane today, 

the concentration of methane in the atmosphere would return to natural levels in about I 0 years. 

Carbon dioxide has a much longer residence time, because it is not broken down easily by other atmospheric 

gases. Its removal from the atmosphere depends instead on 

rates of transfer to and from the oceans and the biosphere. 

Carbon dioxide is dissolved in seawater and incorporated 

into calcium carbonate in the form of fossil tests, lime 

mud, and coral reefs. And plants use C02 from the atmosphere to perform photosynthesis. But these materials-calcium carbonate skeletons and plants of all types-are 

continually breaking down and releasing C02 back into the 

atmosphere. Because the influxes are in close balance with 

the outfluxes, net removal of C02 from the atmosphere is 

very sluggish (Wuebbles and Edmonds, 1991). Recent estimates of the residence time of C02 in the atmosphere are 
622 THE FUTURE OF ENERGY GASES 

>-

(!J 

a: 

w 

z 

w 

1-

z 

~ 

0 

<( 

a: 

A WAVE NUMBER (CM-1) 

50000 

I 

1 0000 5000 2000 1000 663 333 200 100 

I I I II I I I I I I I il I I I I I Ill 

0.1 0.2 0.3 0.5 1 .0 1 .5 2 3 5 1 0 15 20 30 50 100 

WAVELENGTH (~M) 

8 

Figure 3. Radiation and absorption curves for the Earth's surface. A, Energy emitted from the 

Sun (left) and re-emitted from the surface of the Earth (right). B, Bands of energy absorbed, 

measured in percent, by the greenhouse gases. Modified from Wuebbles and Edmonds (1991 ). 

Wavelength in micrometers. Wave number in centimeters. 

between 200 and 500 years (Wuebbles and Edmonds, 

1991; MacDonald, 1989). 

The importance of residence times in the long-term influence of greenhouse gases is shown in figure 4. Relative 

contributions of carbon dioxide, methane, carbon monoxide, nitrogen oxides, and chlorofluorocarbons are shown 

for time spans of 50, 100, and 500 years. Gases with relatively short residence times, such as methane and nitrogen 

oxides, are important greenhouse contributors in the short 

term, but they lose importance over time spans of hundreds of years. Carbon dioxide gains relative importance 

over longer integration times because of its long residence 

time in the atmosphere. Figure 4 gives a sense of the relative importance of the principal greenhouse gases, and it 

shows that their contributions are not fixed, but are highly 

dependent on the amount of time in question. 

CARBON DIOXIDE 

Since the early 1800's, C02 in the atmosphere, as 

measured from air bubbles trapped in glacial ice from 

Greenland and Antarctica, has increased from 280 ppmv to 

350 ppmv (fig. 5; Wuebbles and Edmonds, 1991; Post and 

others, 1990). From 1958 to 1988, C02 in the atmosphere 

increased from 315 to 350 ppmv, as determined from direct measurements at Mauna Loa, Hawaii, representing an 

addition of 74 billion tons of carbon in 30 years (Keeling 

and others, 1989). Similar trends have been observed at a 

network of land- and sea-based stations around the world. 

The current growth rate for atmospheric C02 is about 0.4 

percent per year (Macponald, 1989). 

Atmospheric C02 arises from both natural and anthropogenic sources. Natural emissions of C02 come from 

plants and soils, the oceans, and volcanic eruptions; it also 

is produced by oxidation of other gases such as CH4 and 

CO. The largest anthropogenic sources of C02 are the 

burning of fossil fuels and the clearing and burning of timber. Carbon dioxide is also produced during the manufacturing of cement. Globally, human activity adds roughly 7 

gigatons (1 gigaton=J015 tons) of carbon to the atmosphere each year; 5.4 gigatons come from the burning of 

fossil fuels and 1.6 from biomass burning and cement production. Of the 7 gigatons that we add each year, roughly 

3.6 gigatons, is transferred to the deep oceans (2 gigatons) 

and terrestrial biosphere (1.6 gigatons). The remaining 3.4 

gigatons accumulates in the atmosphere (Quay, 1992). In 

other words, we are adding C02 to the atmosphere at 

twice the rate that it can be removed by the oceans and the 

biosphere. 
ENVIRONMENTAL CONSEQUENCES OF INCREASED NATURAL-GAS USAGE 623 

, 

I 

I ~ 

A 

0\9 

o#r$3 

0w o =from air bubbles 

0 0 0 0 trapped in polar ice caps 

0 0 e =from direct observation 

by gas chromatography 

1800 1900 2000 

YEAR 

B 

Figure 5. Trends in atmospheric C02 concentrations, in parts per million 

by volume, ppmv, since 1700 (modified from Wuebbles and Edmonds, 

1991). Data for 1958 to the present are from direct observations by gas 

chromatography; pre- I 958 data are from air bubbles trapped in polar ice in 

Greenland and Antarctica. 

c 

Figure 4. Relative contributions of each greenhouse gas to the greenhouse effect, using 1988 

emissions and integration times of (A) 20, (B) 

100, and (C) 500 years. From Wuebbles and 

Edmonds (1991). Copyright by CRC Press. 

Used with permission. 

Natural-gas combustion produces significantly less 

C02 per energy unit than coal or oil. In producing a gigajoule of energy, coal emits 24 to 25 kilograms of carbon, 

oil emits 19 to 20 kilograms of carbon, and natural gas 

emits 13 to 14 kilograms of carbon (fig. 6; Flavin, 1992; 

Marland and Pippin, 1990). In the United States, 47 percent of fossil fuel-use comes from burning oil, 26 percent 

from coal, and 27 percent from natural gas (Marland and 

Pippin, 1990). Nationwide, oil accounts for about 43 percent of fossil fuel C02 emissions, coal accounts for about 

37 percent, and natural gas accounts for 19 percent. Glo30 

24·25 

20 

10 

0 

NATURAL GAS OIL COAL 

FUEL 

Figure 6. Carbon emissions for natural gas, crude oil, and coal, 

based on equivalent energy production from each fuel. From Flavin (1992). Copyright by Worldwatch Institute. Used with permission. Units are kilograms/gigajoule, kg C/109 J. 

bally, coal burning produces about 45 percent of fossil-fuel 

C02 emissions, oil produces 40 percent, and natural gas 

produces 15 percent of the total. Increased use of natural 
624 THE FUTURE OF ENERGY GASES 

gas, at the expense of coal and oil, could reduce significantly the anthropogenic emissions of C02, because fossilfuel emissions represent the largest human source of C02. 

METHANE 

Methane, the main component of natural gas, is also an 

important greenhouse gas. It absorbs bands of radiation in 

the 7- to 14-micrometer window, those not absorbed by 

C02 or water vapor (fig. 3), so it is 21 times more effective 

than C02 in accentuating the greenhouse effect (Wuebbles 

and Edmonds, 1991). Methane concentrations in the atmosphere show more rapid growth than C02, having doubled over the past 200 years (fig. 7; Khalil and Rasmussen, 

1988). The current rate of increase is 1 percent per year, 

roughly three times the rate of increase of C02 (Khalil and 

Rasmussen, 1982). However, CH4 has a short residence 

time in the atmosphere-it remains in the troposphere for 

about 10 years before it is oxidized to C02 and water by 

hydroxyl radicals (OH) or transported to the stratosphere 

(Wuebbles and Edmonds, 1991 ). So CH4 is a potent greenhouse gas in the short term and a potential source of C02 

and water vapor over the long term. 

Atmospheric methane emanates from both natural and 

human sources (table 1; Houghton and others, 1992). 

Though methane emissions are not well quantified, roughly one-third comes from natural sources such as wetlands, 

oceans, lakes, tundra, the destabilization of methane hydrates (by submarine landslides for instance), leakage 

from other subsurface accumulations, and the digestive 

tracts of wild ruminant animals and termites. Another onethird is generated by agricultural practices such as the cui-

> .g_ 1600 _ 0 ~from a1r bubbles 

_e, trapped tn polar 1ce caps 

6 1400-

i= 

~ 

g:: 1200-

2 

w 

() 1000-

2 

0 

t.;. 800-

I 

~ 600 - 0 

0: 

w 

I 400- a_ 

(/) 

~ 200- r-

~ 

e =tram d1rect observation 

by gas chromatography 

0 

0 0 0 

0 

0 

tivation of rice and the raiSing of cattle and sheep. The 

remaining one-third comes from coal mining, oil and natural-gas production and distribution, landfills, and biomass 

burning. Of the 50 teragrams (Tg) per year that are emitted from oil and gas systems, it is estimated that naturalgas systems account for 25 to 50 Tg and oil systems 

account for 5 to 20 Tg (Houghton and others, 1992). 

Table 1. Estimated sources and sinks of methane per year, in 

teragrams (Tg), from the U.S. Environmental Protection Agency 

(1993). 

[N/A, not applicable] 

Global estimate 

Human Sources 

Oil/gas systems -------------------------

Coal mining -----------------------------

Lan dfi II s ----------------------------------

Domesticated livestock -------------"--

Animal waste----------------------------

Rice paddies-----------------------------

Biomass burning------------------------

Wastewater treatment------------------

. Natural Sources 

Natural wetlands------------------------

Termites----------------------------------

Oceans and freshwater-----------------

CH4 hydrate depressurization---------

Total --------------------------------

50 

40 

30 

80 

25 

60 

40 

25 

115 

20 

15 

0 

500 

Global range 

30-70 

25-50 

20-70 

65-100 

20-30 

20- 150 

20-80 

NIA 

100-200 

10-50 

5-45 

0-5 

400-610 

OL---~---L---L--~----L---L---~---L--~--~ 

1000 1200 1400 1600 1800 2000 

YEAR 

Figure 7. Trends in atmospheric CH4 concentrations, in parts per billion 

by volume, since A.D. 1000. Modified from Wuebbles and Edmonds 

(1991). Data·for 1958 to the present are from direct observations by gas 

chromatography. Pre-1958 data are from air bubbles trapped in polar ice in 

Greenland and Antarctica. 
ENVIRONMENTAL CONSEQUENCES OF INCREASED NATURAL-GAS USAGE 625 

OTHER GREENHOUSE GASES 

Other energy-related gases that contribute to the greenhouse effect are nitrous oxide and ozone. These gases are 

less abundant than C02 and CH4, but they are potent infrared absorbers. Nitrous oxide comes from natural sources in 

the biosphere and atmosphere, and from human sources 

such as fossil-fuel combustion and the manufacture of fertilizers. Its concentration in the atmosphere has been growing steadily since about 1940 (MacDonald, 1989). Ozone 

concentrations also show steady growth during this century, especially in urban areas in the Northern Hemisphere. 

Ozone is produced from a complex set of reactions involving nitrogen dioxide, reactive hydrocarbons, carbon monoxide, and sunlight. Ozone. is the principal component of 

smog and will be discussed in more detail in the "Air Pollution and Acid Precipitation" section. It is derived mainly 

from diesel- and gasoline-burning motor vehicles. 

Finally, chlorofluorocarbons (CFC's), are the most rapidly increasing gas species in the atmosphere (Wuebbles and 

Edmonds, 1991 ). They have no known natural sources; their 

main human sources are refrigerants, propellents for household aerosol products, and foaming agents. Chlorofluorocarbons linger in the troposphere where they contribute to the 

greenhouse effect, and eventually they move upward to the 

stratosphere where they undergo photodissociation and 

begin attacking statospheric ozone molecules. Their role in 

the destruction of the Earth's ozone layer will be discussed 

in the "Methane and Stratospheric Ozone" section. 

CLIMATE CHANGE? 

Though significant increases in greenhouse gases over 

the past 200 years are well established, their effect on the 

Earth's climate is less clear (for critical review, see Jaworowski and others, 1992). While most climatologists 

agree that the average temperature at the Earth's surface 

has increased over the past century, no unique cause for this 

warming trend has yet been identified. Temperature records 

show an overall increase of 0.5°C in the mean global surface temperature over the past 100 years. The eight warmest years on record have occurred since 1980, even after the 

effects of El Nifio are accounted for (Boden and others, 

1991 ). However, it is not clear that the observed warming is 

related to the greenhouse effect; it may be part of a natural 

warming trend that began about A.D. 1500. 

Another measure of climatic change is the variation of 

temperature extremes, such as daily maximum and minimum temperatures. For the Northern Hemisphere during the 

period 1951 to 1990, these show a persistent, worldwide 

decrease in daily temperature ranges. Since 1950, temperature minimums have increased three times faster than maximums; thus the gap between daily temperature extremes has 

narrowed (Karl, 1993). Various ideas have been offered to 

explain this trend, including increasing cloud cover possibly 

caused by a combination of aerosols, the greenhouse effect, 

and natural climatic variation (Karl, 1993 ). 

Our present understanding of the greenhouse effect 

and its potential results is by no means complete. Some 

scientists predict a gradual, persistent rise in surface temperature with resultant changes in regional patten1s of precipitation, temperature, and cloud cover that are likely to 

disrupt human agricultural systems (Wuebbles and Edmonds, 1991). Sea level may rise owing to partial melting 

of polar ice caps and thermal expansion of the oceans. As 

a result, ecosystems on low-lying coasts may be inundated. Though the precise rates and locations of these changes are uncertain, it is easy to imagine the disruptive effects 

they may have on human society as well as other animal 

and plant communities. 

Mitigating increases in the greenhouse effect requires 

reduction in emissions of greenhouse gases from anthropogenic sources. The bulk of these emissions comes from 

fossil-fuel combustion. Substitution of natural gas for coal 

in electrical power generation could reduce C02 emissions 

by nearly 50 percent (Marland and Pippin, 1990). And natural gas in place of gasoline could reduce motor vehicle 

emissions of C02 by up to 25 percent (Singh, 1985). This 

substitution would also reduce nitrous oxide emissions, because natural gas produces 45 percent less nitrous oxides 

in motor vehicles (Singh, 1985) and up to 95 percent less 

nitrous oxides in electrical power generation (Flavin, 1992; 

National Acid Precipitation Assessment Program, 1990). 

Growth in the use of natural gas is likely to increase 

methane leakage from production and distribution infrastructure. In the United States, natural-gas leakage from 

distribution systems totals less than 1 percent of the gas 

that is transported (Mosher, oral commun., 1992). When 

emissions are totaled, however, they form a significant 

source of atmospheric methane (table 1). Presently, worldwide leakage from production and distribution systems 

amounts to 7 to 8 percent of global methane emissions 

from all sources, and about 11 to 12 percent of emissions 

from anthropogenic sources. Coal mining contributes a 

similar amount; efforts are underway to encourage recovery of coal bed methane that, until 1990, was vented to the 

atmosphere (Barns and Edmonds, 1990). 

METHANE AND 

STRATOSPHERIC OZONE 

Methane has recently emerged as a potential influence 

on the ozone layer. Ozone is a natural product of sunlight 

on oxygen, with a normal concentration in the upper atmosphere of about 0.1 ppm and in the troposphere of 

about 0.02 ppm. The ozone layer, which starts at about 12 

kilometers above the Earth's surface and extends upward . 

to about 50 kilometers, protects plants and animals from 
626 THE FUTURE OF ENERGY GASES 

ultraviolet radiation in sunlight. Specifically ozone blocks 

UV-B radiation, which has wavelengths ranging from 290 

to 320 nanometers, a range that can damage or destroy 

cellular DNA. Ozone molecules act as catalysts in converting incoming UV radiation into IR radiation through 

the following process: 

+UV~0 +0 

+0~0 +IR 

Net: UV~IR 

We have known for some time that CFC's added to the 

atmosphere from refrigerators, air conditioners, aerosol 

propellants, and foaming agents destroy ozone. Chlorine 

atoms are released when CFC molecules are broken down 

in the upper atmosphere by UV radiation. Chlorine, in turn, 

acts as a catalyst in the conversion of ozone to oxygen: 

Cl+0 ~CI0+02 

CI0+0-+Cl+02 

Net: +0~20 . 

Chlorofluorocarbons are chemically inert, so they do not 

react with other compounds in the atmosphere. They are 

not soluble in water, so they are not washed from the atmosphere by rain and snow. Also, because chlorine is not 

consumed by the ozone reaction, a single chlorine atom 

can break up an indefinite number of ozone molecules 

(Turk and Turk, 1988). Chlorine is finally converted to a 

less reactive state when it gets incorporated into a less reactive molecule, but this conversion may take as much as 

100 years (Stetson, 1992). Chlorofluorocarbons presently 

in the atmosphere may thus continue to deplete the ozone 

layer for a century or more, even though production of 

CFC's worldwide has been reduced by 50 percent since 

the Montreal Protocol of 1986 (Stetson, 1992). 

Methane enters the ozone issue as a potential contributor 

to ice cloud formation. Stratospheric ice clouds provide the 

substrate upon which the catalytic conversion of ozone to 

oxygen takes place. Methane molecules in the stratosphere 

are converted by photodissociation and oxidation to C02 

and HzO; this H20 may contribute to the buildup of stratospheric ice clouds (MacDonald, 1990). On the other hand, 

Khalil and Rasmussen (1982) suggested that methane in the 

stratosphere may combine with chlorine atoms and thereby 

reduce the ozone-destroying potential of CFC's. Clearly, our 

understanding of the role of methane in stratospheric ozone 

depletion is incomplete, and further research is warranted if 

natural gas is to gain importance in the global energy mix. 

FOSSIL FUEL EMISSIONS AND 

ATMOSPHERIC OXIDANTS 

Another important attribute of the atmosphere is its 

oxidizing capacity, represented by the total atmospheric 

concentration of 0 3, H20 2, and the OH radical (Thompson, 1992). The OH radical is the most important of the 

oxidants because it reacts with hundreds of different gases, 

both natural and manmade, and it controls their concentrations in the troposphere. The OH radical has been referred 

to as the "tropospheric vacuum cleaner," (Graedel, 1978) 

because it controls the buildup of pollutants such as carbon monoxide, methane, and other hydrocarbons. It also 

reacts with hydrogenated chlorofluorocarbons, which are 

now being substituted for chlorofluorocarbons to mitigate 

depletion of stratospheric ozone. 

Because of increased fluxes of reactive gases into the 

atmosphere, the abundance of OH radicals may be declining. The concentration of OH in the troposphere may be 

20 percent lower now than a century ago (Khalil and Rasmussen, 1988), but its concentration is too low to measure 

accurately. Atmospheric chemistry models predict decreasing levels of OH since the Industrial Revolution, driven by 

rapid increases in CO and CH4. The removal of tropospheric OH is worrisome because of feedback mechanisms 

inherent in the system. As we inject reactive gases into the 

trophosphere, they consume OH molecules; as the population of OH molecules declines, a critical sink for reactive 

gases slowly disappears. Without the OH sink, the increase in reactive pollutants is accelerated, and more reactive pollutants use increasingly more OH radicals. Where 

we are in this suggested cycle, or where it may end, are 

both unknown. Until more is known, fossil-fuel emissions, 

particularly CO, CH4 and reactive hydrocarbons, need to 

be viewed as potentially harmful to the oxidizing capacity 

of the atmosphere. 

AIR POLLUTION AND 

ACID PRECIPITATION 

The atmospheric changes discussed in the previous 

sections are long-term phenomena that affect the entire 

planet. Near-surface air pollution is a more local and immediate problem. The most harmful air pollutants and 

those that are monitored by the Federal Government are 

sulfur dioxide, nitrogen oxides, particulates, carbon monoxide, ozone, and lead. These are all derived primarily 

from fossil-fuel use in transportation, electricity generation, and industrial processes. The adverse effects of these 

pollutants range from scratchy eyes to lung cancer resulting from local ozone increases to widespread damage to 

ecosystems resulting from severe ozone pollution or acid 

precipitation (Turk and Turk, 1988). 

Federal and state controls under the Clean Air Act of 

1970, have brought notable improvements in nationwide 

ambient concentrations of all the regulated pollutants 

(fig. 8). This improvement, however, is somewhat deceptive, because it does not reflect the air quality in large cities 

such as Los Angeles and New York, where concentrations 
ENVIRONMENTAL CONSEQUENCES OF INCREASED NATURAL-GAS USAGE 627 

.025 c::: 

~ - .020 ~ 

:» .015 Q. 

., 

t: .010 Ill 

~ 

c 

c::: 

0 

.005 

= 10 ~ ... 

Gl 

Q. 

., 

t: 5 Ill 

~ 

E 

1980 1985 1990 

1980 1985 1990 

~ .015 

~ 

:» .010 Q. 

., 

t: 

:. .005 

B 

~ 0.15 

~ 

:» 0.1 Q. 

., 

t: 

:. 0.05 

D 

1980 1985 1990 

1980 1985 1990 

... 1.5.----------------------. 

~ Gl 

:i: 

u 

:s 

::J 

(,) 

... 

Gl 

Q. 

., 

~ 0.5 

c;, 

~ u 

~ O..LA...__.L.A....__.L.A....__.L.A....__.L.A... ...... UIOJ 

1975 1980 1985 1990 

F 

Figure 8. National ambient concentrations of particulates (A), sulfur dioxide (B), nitrogen 

dioxide (C), ozone (D), carbon monoxide (E), and lead (F), from 1975 to 1990. From U.S. 

Council on Environmental Quality ( 1992a). 

of carbon monoxide, ozone, and particulates often exceed 

the national standards. Because most Americans live in 

urban areas, many of the 1990 amendments to the Clean 

Air Act are aimed at reducing urban air pollution. 

PARTICULATES 

Particulate matter is a mixture of minute solid particles 

or liquid droplets, mostly unburned carbon and ash, derived from burning coal and, to a lesser extent, oil. In elevated concentrations, these tiny particles can cause 

respiratory diseases, including lung cancer (Turk and Turk, 

1988). The nationwide trends in particulate emissions since 

1940 are shown in figure 9. After 1970, when the Clean 

Air Act was emplaced, U.S. emissions of particulates were 

reduced drastically, through the installation of electrostatic 

precipitators and baghouse filters at many coal-fired industrial plants and powerplants. Today, industrial plants produce 37 percent of particulate matter nationwide, with 

powerplants and motor vehicles each contributing an additional 20 percent (U.S. Council on Environmental Quality, 

1992a). Of the fossil fuels, coal produces the highest particulate emissions, but diesel oil is an additional important 

source. Natural gas is free of solid particles and produces 

no particulates during combustion, which makes it a clean 

alternative to conventional coal burning for industry and 

electrical generation. 
628 THE FUTURE OF ENERGY GASES 

25 

Ill 

§ 20 1-

·~ ... 

~ 15 

r::: 

.!2 

;: 10 

:!: 

5 

0 

1940 1950 1960 1970 1975 1980 1985 1990 

• Transportation 

D Solid waste 

D Fuel combustion 

lZLJ Miscellaneous 

D Industrial processes 

Figure 9. U.S. emissions of particulates by source, from 1940 to 1990. From U.S. Council 

on Environmental Quality (1992a). 

25 

Ill 

§ 20 1-

u 

·;: 

... 

~ 15 

r::: 

.!2 

;: 10 

:!: 

5 

0 

1940 1950 1960 1970 

• Transportation 

D Industrial processes 

1975 1980 1985 

D Fuel combustion 

lZLJ Miscellaneous 

1990 

Figure 10. U.S. emissions of S02 by source, 1940-1990. From U.S. Council on Environmental Quality (1992a). 

SULFUR DIOXIDE 

Sulfur and nitrogen oxides are acidic gases that are 

emitted in varying amounts during fossil-fuel combustion 

(see U.S. Environmental Protection Agency, 1992; National Acid Precipitation Assessment Program, 1990). Sulfur, 

present in small amounts in coal and oil, is oxidized to 

sulfur dioxide during combustion by means of the following reaction: 

More than two-thirds of the anthropogenic S02 added to 

the atmosphere comes from powerplants, primarily from 

those which burn coal. Industrial plants, including smelters, paper mills, and chemical facilities, produce about 15 

percent of so2 emissions, whereas motor vehicles produce 

less than 5 percent (fig. 1 0). In the United States, total 

output of so2 has declined from a high of 28.3 million 

metric tons in 1970 to 21.2 million metric tons in 1990. 

This 25 percent decrease reflects the introduction of fluegas desulfurization devices (scrubbers) and low sulfur fuel 

at many coal-fired powerplants. Strict industrial regula-
ENVIRONMENTAL CONSEQUENCES OF INCREASED NATURAL-GAS USAGE 629 

tions have reduced emissions of so2 from smelters, paper 

mills, and chemical facilities. 

Sulfur dioxide emissions can be reduced further. 

Scrubbers can reduce S02 emissions from existing electrical generation plants by as much as 95 percent (French, 

1990), but they also reduce efficiency. By 1990, scrubbers 

were installed at only 20 percent of the coal-burning powerplants in the United States, compared with 85 percent in 

Japan. Newer ''clean coal" technologies have the potential 

to reduce so2 and, to a lesser extent NOX, while improving efficiency, but these technologies are expensive. 

An alternative to coal-fired powerplants is a natural 

gas-fired combined-cycle system. Exhaust heat from a gasfired turbine produces steam, and the steam is reinjected 

into the turbine or used to power a second steam turbine. 

On average, combined-cycle powerplants cost 25 to 50 

percent less to build than a coal plant, and they have higher efficiencies (45 percent) than conventional, single-cycle 

gas turbine plants (35 percent) (Burnett and Ban, 1989). 

Combined-cycle natural-gas powerplants produce virtually 

no S02 or particulates (fig. 11). They also produce far less 

NOx than a coal-fired plant. 

5 

4 

0 

4.3 

COAL· 

STEAM 

OIL-STEAM 

• so2 

0 NOx 

GAS 

COMBINED· 

CYCLE 

ELECTRIC POWER GENERATION 

Figure 11. Sulfur dioxide (S02) and NO, emissions for electricpower generation, by primary fuel. From Flavin (1992). Copyright by Worldwatch Institute. Used with permission. 

NITROGEN OXIDES 

Nitrogen oxides represent the combination of mtnc 

oxide (NO), which accounts for 95 percent of NOx emissions, and nitrogen dioxide (N02), which accounts for 5 

percent or less of NOx emissions (National Acid Precipitation Assessment Program, 1991). Two types of NOx are 

formed during combustion, thermal NOx and fuel NOx· 

Thermal NOx forms within the combustion flame core, 

where very high temperatures facilitate the dissociation of 

atmospheric N2 and 0 2 molecules into their atomic states. 

These atoms react with other N2 and 0 2 molecules to 

form NOx: 

N2+0-+NO+N 

N+02-+N0+0 

Fuel NOx is generated from nitrogen compounds in the 

fuel during combustion in an oxygenated environment. 

The reactions that transform fuel-bound nitrogen to NOx 

are complex and varied. Coal-bound nitrogen compounds 

follow a solid-phase reaction, and oil-bound compounds 

follow a gas-phase reaction, and conversion rates depend 

on the amount of oxygen available and the temperature of 

the combustion flame (Campbell and others, 1991 ). N atural gas and most distillate oils produce only thermal NOx, 

because they contain no fuel-bound nitrogen. Coal and residual oils contain variable amounts of chemically bound 

nitrogen, so when combusted they produce both thermal 

and fuel NOx. 

Nitrogen oxides contribute to urban smog and acid 

precipitation. In a series of complex photochemical reactions in the presence of sunlight and oxygen, nitrogen oxides combine with volatile organic compounds to form 

ozone, the principal ingredient in urban smog. Their role 

in acid precipitation will be discussed in the "Acid Precipitation" section. 

In 1990, U.S. emissions of nitrogen oxides totalled 

19.6 million metric tons, down slightly from a historical 

high of 21.7 million metric tons in 1978. Motor vehicle 

(transportation) emissions (fig. 12) account for roughly 

half of global annual NOx emissions, and electric power 

generation (fuel combustion) accounts for most of the remainder (U.S. Council on Environmental Quality, 1992a). 

Additional sources of NOx are industrial boilers and heaters and solid-waste incinerators (Campbell and others, 

1991 ). These combined sources account for less than 5 

percent of total NOx emissions, and their contribution has 

remained essentially stable since historic records began. 

The transportation share of NOx emissions has been 

dropping since the 1970's and 80's owing to Government 

regulation of vehicle emissions and related advances in 

combustion technologies. While Americans have doubled 

their vehicle miles since 1970, per-vehicle emissions have 

fallen more than 90 percent over the same period (U.S. 

Council on Environmental Quality, 1992a). Emissions 

from power generation, on the other hand, have been rising steadily. 

The greatest potential for future NOx reductions is in 

the power generation industry. Cpmbined-cycle gas plants 
630 THE FUTURE OF ENERGY GASES 

Ill 

c:: 

0 

.... 

20 

u 15 ·;::: 

4i 

::E 

E 10 

~ 

~ 

5 

0 

1940 1950 1960 1970 1975 1980 1985 1990 

• Transportation 

D Solid waste 

D Fuel combustion 

[22J Miscellaneous 

c::J Industrial processes 

Figure 12. U.S. emissions of NOx by source, from 1940 to 1990. From U.S. Council on 

Environmental Quality ( 1992a). 

produce 40 to 85 percent less NOx than the most advanced 

coal plants (fig. 11; Flavin, 1992; Gillette and others, 

1988). Natural gas can also contribute to reductions in 

NOx emissions through co-firing and reburn techniques at 

existing coal-fired powerplants. These techniques involve 

introducing small amounts of natural gas into the combustion zone to improve combustion of the primary fuel 

(coal). They can reduce NOx by up to 60 percent. They 

also reduce S02 and particulate emissions, providing an 

important mitigation option for coal-fired plants that do 

not comply with Federal emissions standards (Burnett and 

Ban, 1989). 

Natural gas also has potential to reduce NOx emissions in the transportation sector. Vehicles that run on 

compressed natural gas generally have lower NOx emissions than gasoline. In vehicles that have been converted 

to run on either gasoline or natural gas, NOx emissions are 

reduced by 20 to 50 percent when such vehicles run on 

natural gas (Singh, 1985). Emissions are expected to improve significantly in engines designed to run solely on 

natural gas. Cities such as Los Angeles and New York are 

converting municipal fleet vehicles to natural gas in an effort to reduce urban smog. 

ACID PRECIPITATION 

As the atmospheric burden of · sulfur and nitrogen 

compounds from fossil fuels has grown, rain and snow in 

some regions have become increasingly acidic, particularly 

downwind of major industrial centers. Sulfur dioxide 

(S02) and nitrogen oxides (NOx) from combustion sources 

enter the atmosphere where they are oxidized, mainly by 

reaction with OH radicals, to form sulfates (S03) and nitrates. The sulfates and nitrates then combine with hydrogen and oxygen in rainwater (or snow) to form sulfuric 

and nitric acids, as described by the following reactions: 

S03+HzO.-H2S04 (sulfuric acid) 

4N0+302+2H2Q.-4HN03 (nitric acid) 

Normal rain is weakly acidic, with a pH of 5.6 to 5.7, as a 

result of similar reactions that occur between water and 

carbon dioxide (producing carbonic acid) and between atmospheric nitrogen and water (producing nitric acid). In 

polluted regions, however, rainwater with a pH of 4 to 5 is 

not uncommon, and, in extreme cases, a pH as low as 1. 7 

has been reported (Turk and Turk, 1988). 

Acid precipitation affects both aquatic and terrestrial 

ecosystems. Elevated acidity in lakes and streams can kill 

aquatic organisms and inhibit the reproduction of some 

amphibians. Many species of snails, clams, mayflies, and 

crayfish cannot survive in water with a pH of 5.5 or lower, 

and many fish die under conditions of pH 4.5 or less. On 

land, acid rain or snow damages trees and other plants 

through direct exposure and through the indirect effects of 

increased soil acidity. Most plants, including agricultural 

crops, cannot survive under conditions of sustained exposure to pH 3.6 or lower (National Acid Precipitation Assessment Program, 1991 ). 

The Northeast and the Southeast are the two areas of 

the United States that have been most affected by acid 

precipitation. In the Northeast, S02 emissions and surfacewater sulfate concentrations both decreased over the past 

15 to 20 years, but in the Southeast, sulfur emissions and 

surface-water sulfate both increased (U.S. Council on En-
ENVIRONMENTAL CONSEQUENCES OF INCREASED NATURAL-GAS USAGE 631 

vironmental Quality, 1992b). Because natural gas produces 

no so2 and low NOX emissions, a shift to natural gas in 

electricity generation and transportation would reduce the 

incidence of acid precipitation. 

VOLATILE ORGANIC COMPOUNDS AND 

CARBON MONOXIDE 

Volatile organic compounds (also known as VOC's, reactive hydrocarbons, or non-methane hydrocarbons), along 

with NOx are critical to the formation of ozone in urban 

smog. Their sources include gasoline vapors, coal gasification, chemical solvents, and combustion emissions from 

fossil fuels (Hunt, 1987). Emissions trends for VOC's since 

1940 are shown in figure 13. Since 1970, emissions have 

dropped from 27.5 to 18.7 million metric tons annually. 

The transportation sector cut its share of emissions by onehalf, by using catalytic converters and other technologies 

aimed at compliance with the Clean Air Act and its amendments. Emissions could be reduced further by using natural-gas-powered vehicles, which produce 35 to 55 percent 

less VOC's than gasoline-powered vehicles (Singh, 1985). 

Carbon monoxide (CO) is another important component in urban smog. It is a clear, odorless gas that escapes 

during incomplete combustion of fossil fuels (Conservation Foundation, 1987). At high exposure levels, it reduces 

the blood's capacity to circulate oxygen and thereby causes drowsiness and slows reflexes. In very high concentrations, it causes death. Motor vehicles (transportation) 

contribute two-thirds of the national total CO emissions 

(fig. 14), but their emissions have been reduced by nearly 

50 percent since 1970, owing to the use of catalytic con25 

§ "' 20 1-

·~ 

t 15 :E 

c:: 

.!2 

;: 10 

:E 

5 

0 

1940 1950 1960 1970 

verters. Again, natural-gas vehicles can play an important 

role in further reductions of CO emissions. They produce 

80 to 90 percent less CO than gasoline-powered vehicles 

(Singh, 1985). 

LOCAL ENVIRONMENTAL ISSUES 

Fossil fuels release most of their pollutants as combustion emissions, so their greatest environmental impacts 

are in the atmosphere. This paper focuses on global atmospheric effects, but each fossil fuel is associated with local, 

land-based environmental problems as well-problems at 

the drillsite or mine shaft where the fuel is extracted from 

the Earth's crust, problems along the pipeline where the 

fuel is transported, as well as end-use safety issues in the 

home and in the car. One of the greatest difficulties in 

finding an environmentally favorable energy plan is balancing local, regional, national, and global issues. The 

brief discussion of local problems herein is not a reflection 

of their importance. I can only suggest some of the local 

problems that need to be considered. 

Oil, for instance, has the potential to contaminate 

fresh water and seawater. Oil tankers carry huge volumes 

of crude oil over seas, and accidents such as the January, 

1993, break up of the Norwegian crude-oil tanker in the 

Shetland Islands are harmful to marine wildlife and the 

local maritime economy. Underground fuel tanks can pollute ground water, and oil rigs and pipelines also have potential for leakage both onshore and offshore. In addition, 

oil exploration and production in remote areas can disrupt 

animal and plant life, although these impacts can be minimized by careful planning and reclamation. 

1975 1980 1985 1990 

• Transportation 

D Solid waste 

D Fuel combustion 

IZa Miscellaneous 

1\111 Industrial processes 

Figure 13. U.S. emissions of volatile organic compounds (VOC's), by source, from 1940 

to 1990. From U.S. Council on Environmental Quality (1992a). 
632 THE FUTURE OF ENERGY GASES 

120 

100 

"' c: 80 0 

1-

·~ .... 

Q) 60 :E 

c: 

~ 40 ~ 

20 

0 

1940 1950 1960 1970 1975 1980 1985 1990 

• Transportation 

D Solid waste 

D Fuel combustion 

[2Lj Miscellaneous 

D Industrial processes 

Figure 14. U.S. emissions of carbon monoxide (CO), by source, from 1940 to 1990. From 

U.S. Council on Environmental Quality (1992a). 

Strip mining and underground mmmg for coal can 

also disrupt the natural environment. Some mines impose 

visible scars on the land surface, and many create acid 

mine drainage that can pollute ground water and surface 

water. Mine safety is also an important issue in the coal 

industry. Many miners suffer lung disease, and mine explosions are a direct threat to miners and their families. 

Transportation and storage of coal is relatively safe and 

environmentally benign. However, at the powerplant, 

where the coal is burned, millions of tons of solid waste 

are produced, and this waste requires environmentally safe 

disposal. 

Natural-gas exploration and production involves the 

same infrastructure as oil, so it too has the potential to 

disrupt ecosystems with road and pipeline construction 

and maintenance. Natural-gas leakages are a significant 

source of atmospheric methane, which plays an important 

role in the human contribution to the greenhouse effect 

and in other atmospheric issues discussed in previous sections. In terms of safety, natural gas is flammable and 

under compression it is potentially explosive. It can be a 

fire hazard in the home, as well as at the drill rig, and 

compressed natural gas in an automobile fuel tank is more 

explosive than gasoline or other liquid hydrocarbon fuels. 

CONCLUSIONS 

Overall, natural gas has some marked environmental 

advantages over the other hydrocarbon fuels, but it is not 

environmentally perfect. Combustion of natural gas produces fewer greenhouse gases and air pollutants than either oil or 

coal. It produces less C02, CO, and NOx than other hydrocarbon fuels, and, because it is gaseous and relatively pure, it 

emits virtually no particulate matter and S02. Accordingly, 

substitution of natural gas for coal and oil can improve some 

of the most important environmental problems related to our 

atmosphere. These include urban and industrial air pollution, 

acid rain, and anthropogenic forcing of the greenhouse effect. However, methane is also a potent greenhouse gas, and 

increases in natural-gas production and consumption could 

raise the emissions of unburned methane from leaky pipelines. Also, methane may have adverse effects on the ozone 

layer and the oxidizing capacity of the atmosphere. These are 

important issues that merit further research. 

Natural gas compares well to the other fossil fuels in 

terms of water quality and the preservation of natural ecosystems. It does not have the problems of acid-mine drainage associated with coal mining, nor the oil-spill potential 

associated with crude-oil transportation. In fact it is virtually impossible to pollute ground water or surface water 

with methane, because it is lighter than air. Natural-gas 

exploration, production, and distribution have relatively 

low impacts on natural ecosystems, if they are conducted 

along existing infrastructures. Where new roadways or 

pipelines are required, natural-gas exploration and production are potentially detrimental to delicate ecosystems such 

as natural wetlands. 

In the United States, over 50 percent of electricity generation is fueled by coal, whereas natural gas supplies only 

10 percent, and oil supplies less than 5 percent (fig. 15). 

Nuclear and hydroelectric power supply roughly 20 percent 

and 10 percent, respectively (see Fanelli, this volume). 

Coal-fired powerplants are the major source of particulate 

and so2 emissions, and they produce large portions of nationwide C02 and NOx emissions. Natural-gas combined-
ENVIRONMENTAL CONSEQUENCES OF INCREASED NATURAL-GAS USAGE 633 

3,000 

2,500 

~ 

::l 2,000 0 

£ 

"' :~· 

:!: 1,500 .2 

~ ~: 

;;:. ·::: .~: 

::: :::· ·•.· . . :.·.'. 

c 

0 

1,000 

llJ 

500 

1960 1965 1970 1975 1980 1990 

• Coal D Natural gas 

1985 

Ill Oil 

~ Hydroelectric Ill Nuclear 

Figure 15. Primary sources of U.S. electricity for 1990. From U.S. Council on Environmental 

Quality ( 1992a). 

cycle powerplants are less expensive to build and. operate, 

they are more efficient, and their overall emissions are 60 

percent lower compared to coal-burning powerplants. Substitution of natural gas in place of coal in the electricitygeneration sector could reduce industrial and urban air 

pollution, acid precipitation, and exacerbation of the greenhouse effect. 

In transportation applications, substitution of naturalgas-powered vehicles for traditional gasoline-powered vehicles can improve urban air quality. Natural-gas-powered 

vehicles produce less than half the overall tail-pipe emissions of a conventional gasoline-powered vehicle. They 

emit far less CO, NOx, and VOC's than conventional gasoline and diesel vehicles, and, therefore, have tremendous 

potential to reduce smog levels in our urban areas. Issues 

of safety and convenience have so far restricted the use of 

natural-gas-powered vehicles to municipal fleets and public transport, but technology may overcome these obstacles and expand the application of natural-gas-powered 

vehicles to private users. 

Like coal and oil, natural gas is a nonrenewable resource, and, therefore, not an ultimate solution to our energy needs. However, in the near-term it may help reduce air 

pollution, water pollution, and the harmful impacts of 

human industry on the atmosphere. 

REFERENCES CITED 

Ausubel, J.H., 1991, Energy and environment-The light path: 

Energy systems and policy, v. 15, p. 181-188. 

Barns, D.W., and Edmonds, J.A., 1990, An evaluation of therelationship between the production and use of energy and atmospheric methane emtsswns: Washington, D.C., U.S. 

Department of Energy-Carbon Dioxide Research Program, 

Rept. No. TR047. 

Boden, T.A., Sepanski, R.J., and Stoss, F.W., 1991, Trends '91-

A compendium of data on global change, Rept. No. ORNU 

CDIAC-04.6: Oak Ridge, Tennessee, Carbon Dioxide Information Analysis Center, Oak Ridge National Laboratory, 700 p. 

Burnett, W.M., and Ban, S.D., 1989, Changing prospects for natural gas in ·the United States: Science, v. 244, p. 305-310. 

Campbell, L.M., Stone, O.K., and Shareef, G.S., 1991, Sourcebook-NO, control technology data, Rept. No. EPA-600/2-

91-029: Research Triangle Park, North Carolina, U.S. 

Environmental Protection Agency, Environmental Protection Technology, 58 p. 

Conservation Foundation, World Wildlife Foundation, 1987, State 

of the environment-A view toward the nineties: Washington, D.C., Conservation Foundation, World Wildlife Fund. 

Ehrlich, P.R., and Ehrlich, A. H., 1991, Healing the planet: Reading, Mass., Addison-Wesley Publishing Co., 366 p. 

Flavin, C., 1992, The bridge to clean energy: World Watch, v. 5, 

no. 4, p. 10-18. 

French, H.F., 1990, Clearing the air-A global agenda: Worldwatch Institute, Worldwatch paper, No. 94, 54 p. 

Gillette, J.L., Poch, L.A., and Buehring, W.A., 1988, Regional 

application of natural-gas fired combined-cycle power generation, final report: Gas Research Institute/Argonne National 

Laboratory, No. GRI 88/0050. 

Graedel, T.E., 1978, Chemical compounds in the atmosphere: 

New York, Academic Press, 380 p. 

Graedel, T.E., and Crutzen, P.J., 1993, Atmospheric change-An 

Earth system perspective: New York, W.H. Freeman and 

Co., 446 p. 

Holdren, J.P., 1992, The energy predicament in perspective, in 

Mintzer, I.M., ed., Confronting climate change-Risks, implications, and responses: Cambridge University Press, 

p. 163-170. 
634 THE FUTURE OF ENERGY GASES 

Houghton, J.T., Callender, B.A., and Varney, S.K., 1992, Climate 

change 1992-The supplementary report to the Intergovernmental Panel on Climate Change (IPCC) scientific assessment: Cambridge University Press, 198 p. 

Hunt, W.F., 1987, National air quality and emissions trends report, 1985: U.S. Environmental Protection Agency, Office of 

Air Quality Planning and Standards, No. EPA-450/4-87-001. 

Jaworowski, Z., Segalstad, T.V., and Hisdal, V., 1992, Atmospheric C02 and global warming-A critical review: Oslo, 

Norsk Polarinstitutt, 76 p. 

Karl, T.R., 1993, A new perspective on global warming: Eos 

(American Geophysical Union Transactions), v. 74, no. 2, 

p. 25. 

Keeling, C., Bacasiow, R., Carter, A., Piper, S., Whorf, T., Heimann, M., Mook, W., and Roeloffzen, H., 1989, A threedimensional model of atmospheric C02 transport based on 

observed winds-1. Analysis of observational data, in Peter-

~on, H., ed., Geophysical Monograph 55-Aspects of climate variability in the Pacific and the Western Americas: 

Washington, D.C., American Geophysical Union, p. 165-

236. 

Khalil, M.A.K., and Rasmussen, R.A., 1982, Secular trends of 

atmospheric methane (CH4): Chemosphere, v. II, no. 9, 

p. 877-883. 

Khalil, M.A.K., and Rasmussen, R.A., 1988, Carbon monoxide 

in the Earth's atmosphere-Indications of a global increase: 

Nature, v. 332, no. 6161, p. 242-245. 

MacDonald, G.J., 1989, Global climate change, in MacDonald, 

G.J., and Sertorio, L., eds., Global climate and ecosystem 

change: New York, Plenum Press, p. 1-95. 

MacDonald, G.J., 1990, The future of methane as an energy resource: Annual Reviews of Energy, v. 15, p. 53-83. 

Marland, G., and Pippin, A., 1990, United States emissions of 

carbon dioxide to the Earth's atmosphere by economic activity: Energy Systems and Policy, v. 14, p. 319-336. 

Meehl, G.A., and Schimel, D., 1993, The coupled climate system 

and global change: Eos (American Geophysical Union 

Transactions), v. 74, no. I, p. 2, 14. 

National Acid Precipitation Assessment Program, 1990, Acid 

deposition-State of science and technology, Rept. 1, Emissions involved in acidic deposition processes: Washington, 

D.C., Superintendent of Documents, 185 p. 

National Acid Precipitation Assessment Program, 1991, 1990 integrated assessment report-U.S. National Acid Precipitation 

Assessment Program: Washington, D.C., NAPAP Office of 

the Director, 520 p. 

Pexton, A.F., 1984, A fuels policy intb the 21st century, in Shaw, 

T.L., Lennard, D.E., and Jones, P.M.S., eds., Policy and development of energy resources: New York, John Wiley and Sons, 

p. 5-30. 

Post, W.M., Peng, T.H., Emanuel, W.R., King, A.W., Dale, V.H., 

and DeAngelis, D.L., 1990, The global carbon cycle: American Scientist, v. 78, p. 310-325. 

Quay, P., 1992, Carbon sink-The role of oceans: Geotimes, 

v. 37, no. 9, p. 16--18. 

Ramanathan, V., 1988, The greenhouse theory of climate 

change-A test by inadvertent global experiment: Science, 

v. 240, p. 293-299. 

Singh, M.K., 1985, Environmental concerns related to natural 

gas vehicles, in Klass, D.L., and Seisler, J.M., eds., Nonpetroleum vehicular fuels-CNG Fuel: Arlington, Va., Institute 

of Gas Technology. 

Stetson, M., 1992, Relief for the ozone layer?: World Watch, 

v.5, no. 4, p. 9, 34. 

Thompson, A.M., 1992, Oxidizing capacity of the Earth's atmosphere-Probable past and future changes: Science, v. 256, 

no. 5060, p. 1157-1165. 

Turk, J ., and Turk, A., 1988, Environmental science: Fort Worth, 

Tex., Saunders College Publishing, Harcourt-Brace-Jovanovich College Publishers, 712 p. 

U.S. Council on Environmental Quality, 1992a, Environmental 

quality-22nd annual report of the Council on Environmental Quality: Washington, D.C., U.S. Council on Environmental Quality, 382 p. 

U.S. Council on Environmental Quality, 1992b, United States of 

America national report, United Nations Conference on Environment and Development: Washington, D.C., U.S. Council on Environmental Quality, 423 p. 

U.S. Department of Energy, Energy Information Administration, 

1992, Annual energy review: Washington, D.C., U.S. Government Printing Office. 

U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards, 1992, National air pollutant emission estimates, 1900-1991, E.P.A. Rept No 454/R-92-013: 

Research Triangle Park, N.C., U.S. Environmental Protection Agency. 

U.S. Environmental Protection Agency, 1993, Anthropogenic 

methane emissions in the United States-Estimates for 1990, 

E.P.A. Rept. No. EPA-430-R-93-003: Washington, D.C., U.S. 

Environmental Protection Agency, Office of Air and Radiation. 

Wuebbles, D.J., and Edmonds, J., 1991, Primer on greenhouse 

gases: Chelsea, Mich., Lewis Publishers, 230 p. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

An Introduction to the Use of Natural Gas and 

Opportunities for Greater Consumption 

By Michael Fanelli 1 

CONTENTS 

Abstract . .. ... ... .. ... . . .. . .. . .. . ... . ........ ... . .. .. ... . ... ... .. ... .... .. ... . .. . 635 

Introduction . ............ ..... .... ..... .. .. .. .... ..... ........... .. .... .... .. . . 635 

The Nation's Overall Energy Requirement .................. 636 

Residential and Commercial Sectors ..................... 637 

Industrial Sector .. .. .. .. ..... .. ... ... .... ... .. . . .... ... . .. . ...... ... . 640 

Transportation Sector ....... .. ..... .... .... ...... ... .. .. .. .. ... ... 641 

Electricity Generation Sector .... .. ...... .. .. .. .. .. .. .. .... ... 645 

Summary ....................................................................... 648 

References Cited ...... ....... ........ ... ...... .. ....... .... .. ... . .. ... .. . .. 650 

ABSTRACT 

Each sector of the U.S. economy presents different 

chaiJenges and opportunities for the increased use of natural gas to meet the Nation's future energy needs. Regional 

and local expansions of gas-pipeline transmission and distribution systems will bring natural-gas service to many 

new residential and commercial customers throughout the 

country. The transportation sector presents a potentially 

large and essentiaily new market for natural gas. A number of issues will expedite the penetration of natural gas 

into the vehicle fuel market: the development and marketing of original, dedicated-fuel natural-gas vehicles and 

cost-effective conversion equipment and services; public 

relations efforts to increase awareness and acceptance of 

natural-gas vehicles; continuation of the natural-gas fuel1

U.S. Geological Survey, MS 999, 345 Middlefield Rd., Menlo 

Park, CA 94025. 

price advantage over gasoline. The industrial and electricity generation sectors represent considerable potential for 

increased natural-gas consumption by replacement of current energy sources in fuel-switchable applications such as 

industrial process heat applications and steam generation 

for electricity generation. Competitive pricing, adequate 

pipeline capacity, and demonstrable operational flexibility 

will be the keys to successful marketing of more natural 

gas to the industrial and electricity generation consumer. If 

the natural-gas industry can successfully expand its production and distribution capability, maintain its energy 

price advantage, establish a reputation for reliable and 

flexible delivery, and continue the development of energyefficient gas-fired technologies, there is significant opportunity for greater consumption of natural gas. 

INTRODUCTION 

The United States has long exhibited a dependence on 

various forms of energy to satisfy the energy demands associated with increasing standards of living and expanding 

industrial activity. The requirement for energy reaches 

nearly every aspect of society, including the production, 

distribution, and utilization of physical goods and services, 

the conditioning of the living and working environments 

in homes and offices, or for transportation. In its various 

forms, energy is consumed to meet the requirements of a 

vast and diverse array of specific applications, with a 

widely varying intensity and technology of energy consumption among them. 

In the past 50 years, this appetite for energy has been 

met by a variety of energy sources. During that time, fossil 

fuels (coal, oil, and natural gas) have provided the largest 

share of the Nation's total energy requirement (Energy 

635 
636 THE FUTURE OF ENERGY GASES 

Information Administration, 1992a; see Fanelli, fig. 2, this 

volume). As solids, liquids, and gases, these fuels are physically distributed to millions of homes and businesses 

throughout the country. In addition, non-fossil-fuel energy 

sources such as nuclear, hydro, biomass, geothermal, wind, 

and solar are used primarily to supplement fossil-fuel energy sources used to generate electricity. The average industrial customer consumes vast quantities of energy for heat 

or feedstock in industrial processes or to generate steam to. 

power turbines for electricity generation. The choice of 

fuel to meet these energy needs, therefore, has a significant 

impact on the Nation's overall mix of fossil-fuel consumption. Only relatively tiny quantities of fossil fuels (predominately distillate fuel oil and natural gas) are consumed in 

individual residences and commercial buildings for space 

conditioning, cooking, and water heating needs. Tens of 

millions of these customers, however, amount to a very 

formidable market which represents a significant portion of 

the Nation's overall demand for energy. 

This report summarizes the consumption of the various types of energy by different segments of the U.S. 

economy: residential and commercial, industrial, transportation, and electricity generation. It raises and discusses 

some factors which influence the choice and use of fuels 

by each economic sector, and it evaluates the potential for 

increased consumption of natural gas in the United States 

To some people, increased natural-gas consumption augurs 

a recovery from the prolonged period of depressed activity 

in our domestic energy industries which explore for, develop, and transport natural energy resources to end-users. 

To others, increased natural-gas consumption signals a 

mitigation of the environmental impacts of fossil-fuel 

combustion by reducing the emissions of greenhouse gases 

and atmospheric pollutants which result primarily from 

coal and oil combustion. To still others, natural gas presents an opportunity to eliminate or reduce our fragile dependence on foreign sources of energy, particularly oil, 

and the unfortunate consequences of increased military expenditures, deadly conflict, political and price instability, 

and the continued threat of tanker spills spoiling coastlines 

and marine environments. 

THE NATION'S OVERALL.ENERGY 

REQUIREMENT 

In general, increased natural-gas consumption can be 

achieved in one or both of two ways. Either the current 

natural-gas market share of the Nation's total energy requirement can be increased by replacing other energy 

forms currently used in existing applications, or its consumption can be expanded by filling new energy needs, 

which result from a growing economy or, for example, 

from the development of new industrial applications. 

However, because many applications for energy, particularly industrial and electricity generation applications, can 

be served by several different energy sources, the energy 

markets have been and will remain very competitive 

among the different fuels (Gas Research Institute, 1992). 

Replacement of one energy supply by another will certainly be contested by competing energy producers, marketers, 

distributors, and equipment manufacturers who expect to 

maintain and expand their customer base. In many cases, 

the intense market competition between suppliers of different energy products is no different from the competition 

between manufacturers or service providers who hope to 

sell products or services when a competitor's product or 

service can just as easily fill the need. New markets for 

energy will also be vigorously competed for. Trade associations representing the interests of each energy commodity 

will continue to make sizable investments in research activities in hopes of developing technologies which favor 

the use of their form of energy. Each energy industry will 

continue to refine their product pricing and service options 

to justify the consumer's decision to favor one energy 

source over others. 

At the most basic level, energy consumption involves 

many millions of decisions made each day to undertake 

some activity which has an energy component. But because these decisions are influenced by factors on both the 

macro and micro scale, this paper will attempt to address 

both. It will first introduce factors which influence overall 

energy consumption, then it will focus on individual economic sectors and their energy consumption. 

Historically, the trend in U.S. total energy consumption has correlated relatively closely to economic activity. 

During periods of economic expansion, as measured by 

the Nation's inflation-adjusted gross domestic product 

(GDP), the Nation's energy consumption has tended to increase. Likewise, during periods of economic contraction, 

energy consumption has tended to decline. The trend in 

U.S. energy consumption and real GDP ($1987) over recent decades is shown in figure 1. With the exception of a 

couple of relatively minor recessionary interruptions, the 

United States has experienced a persistently expanding 

economy over the past several decades. Until 1973, there 

was a consistent and uniform correlation between economic activity and energy consumption; as the economy grew 

in real terms, energy consumption kept equal pace. As a 

measure of the Nation's efficiency of energy consumption, 

the quantity of energy consumed per dollar of GDP fluctuated narrowly between 21,000 and 23,000 Btu (British 

thermal unit) per dollar of economic activity. Little to no 

improvement in the overall efficiency of energy consumption was achieved during this period. Since 1973, however, the correlation between economic activity and energy 

consumption has changed. Energy consumption has not 

kept pace with economic production, signaling a period of 

increasing energy efficiency (fig. 1). While the pattern of 

energy consumption is similar to that of economic activity, 
USE OF NATURAL GAS AND OPPORTUNITIES FOR GREATER CONSUMPTION 637 

125 5 

115 r:: 4.5 co 

"' 105 ;n. 

c:: 

95 ~ 

~ 3.5 85 t; 

§ ::1 

c 75 3 0 

5 a: 

Q. 

85 () 

2.5 i= 

(/1 

UJ 55 :::1! 

2 0 

0 

45 (/1 

(/1 

1.5 0 

a: 35 (!) 

25 

.. 0 .. 0 "' 0 .. 0 .. 0 .. ... .. .. .. ., .... .... ., ., "' : ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 

Figure 1. U.S. primary energy consumption (open squares, left scale) and U.S. gross 

domestic product (GDP) (closed squares, right scale). Data from Energy Information 

Administration (l992a). I quad=l0 15 Btu (British thermal units). 

the Nation's efficiency of energy consumption improved 

from 23,000 Btu per 1987 dollar of GDP in 1973 to 

17,000 Btu per dollar in 1990. This represents a reduction 

of more than 25 percent in the energy consumed per dollar 

of economic output. 

Most of the changes in trends of energy consumption 

and efficiency of energy use can be attributed to changes in 

economics, technology, demographics, and attitudes about 

energy conservation. During the mid-1970's and early 

1980's, the United States experienced rapidly rising costs 

of energy, primarily as a result of significant increases in 

the cost of imported crude oil supplies. Rising crude oil 

prices led to increases in various refined oil products such 

as distillate and residual fuel oils and motor gasolines. Natural gas and coal prices also increased substantially during 

the same period (Energy Information Administration, 

1992a; see Fanelli, this volume). Higher energy prices had 

the effect of increasing the costs of living and of doing 

business. These higher prices dampened economic activity, 

contributing to the economic recessions of the mid-1970's 

and early 1980's. Demand for energy declined during these 

periods. Higher energy prices, however, also stimulated 

greater research and investment in new equipment and 

businesses which focused on more efficient energy consumption technologies. Many new and more efficient energy-consuming technologies (for example, improved air 

heating and cooling equipment used for conditioning living 

and working environments (Gibbons and Blair, 1990), and 

motor vehicle improvements that increased their fuel efficiency (Energy Information Administration, 1992a)) were 

developed, which improved the Nation's energy consumption per unit output of goods and services. This allowed a 

continuation in the Nation's economic growth at lower levels of energy consumption. 

Other improvements in energy consumption were realized by greater population and housing growth in southern 

and western regions, where milder climates require lower 

levels of energy consumption for space conditioning. Of 

the approximately 18 million housing units that were 

added between 1977 and 1989 in the United States, approximately 68 percent were located in the South and West 

(American Gas Association, 1992). In addition, changes in 

the mix of industrial production away form energy intensive manufacturing toward more service-based industries 

has resulted in a lower overall energy requirement per dollar of GDP (Gibbons and Blair, 1990). 

The future trend in the Nation's overall energy requirement will continue to be influenced by several factors. Opportunities for increased natural-gas consumption, 

or any other energy source, as a result of economic expansion will likely be in the context of increased competition 

between fuels and their consumption technologies and delivered energy prices, attitudes about conservation, continued realignment of the industrial mix, and continued 

regional redistribution of population growth and housing 

construction. 

RESIDENTIAL AND 

COMMERCIAL SECTORS 

When disaggregating the Nation's total energy consumption into specific economic sectors and energy applications, the residential and commercial sectors of the economy 
638 THE FUTURE OF ENERGY GASES 

include households and nonmanufacturing businesses. The 

commercial sector includes office buildings, retail outlets, 

warehouses, government buildings, schools, hospitals, hotels, and others. Because these two sectors consume energy 

primarily for space conditioning purposes, they are often 

grouped together for energy consumption evaluation. 

The trend in overall energy consumption in the United 

States residential and commercial sector during the period 

1947-1991 is shown in figure 2. After rising rapidly during 

the 1950's and 60's, total energy consumption in this sector has remained relatively stable since the early 1970's, 

despite large increases in the number of housing units and 

square footage of commercial space. This is a result of 

greatly reduced per-household and per-commercial-squarefoot energy consumption. The reduced consumption per 

household and commercial square foot can be attributed to 

the following: 

1. Improvements in the thermal integrity (for example, 

insulation and windows) of residential and commercial 

structures (see Mills, this volume). 

2. Greater efficiency of new space conditioning equipment installed in new structures, and replacing existing 

equipment (Gibbons and Blair, 1990). 

3. More conservative attitudes about energy consumption resulting in greater tolerance of a wider range of temperatures in residential living space, and less energy waste. 

4. Greater population and housing stock growth in 

more temperate regions which require less energy for 

space conditioning (American Gas Association, 1992). 

120 

110 

100 

~ 90 

:::1 

i 80 

~ 

~ 70 

0 

z 

"" 60 

~ 

"" 50 :::1 

0 

40 

30 

20 

·-· 

... "' 

~ 

0 

"' "' 

"' "' 

~ 

0 

"' "' 

The history of consumption of individual forms of energy during 1950-1991 in the residential and commercial 

sector is shown in figure 3. Also shown are data concerning the number of housing units using specific types of 

fuels, primarily for space-heating purposes. 

Increased natural-gas consumption in the residential 

and commercial sector will depend on several factors: ( 1) 

the ability of natural-gas service to meet the energy needs 

in new buildings; (2) the ability of the natural-gas industry 

to increase its current market share in existing buildings 

by (a) retaining its current custorpers and (b) capturing 

new customers in the equipment r~placement market; (3) 

improving energy efficiency in space-heating equipment 

and the thermal integrity of buildings. 

Natural gas competes with electricity and fuel oils for 

the space conditioning and water heating requirements of 

new construction only in geographic regions where gas 

services already exist or are scheduled to be installed. 

Large regional differences are evident in the availability 

and choice of energy sources for various commercial and 

residential applications. For example, in Florida's househeating-fuel market, electricity currently has a 79 percent 

share and natural gas only 8 percent. In Michigan the situation is reversed, natural gas has a 77 percent share and 

electricity only 5 percent (American Gas Association, 

1992). Florida's much warmer climate and greater demand 

for space cooling, an application which is dominated by 

electricity-powered appliances, has made electricity the favored fuel choice. 

0 

., 

"' 

"' "' "' 

0 

"' "' 

"' "' "' 

30 

25 ~ 5 20 

1 0 

Figure 2. U.S. total primary energy consumption (solid diamonds, left scale), residential and commercial sector total energy consumption (solid squares, right scale), residential and commercial total primary energy consumption (open squares, right scale), 

and number of housing units (open diamonds, left scale, in millions). Data from Energy Information Administration (1992a). 1 quad=l0 15 Btu (British thermal units). 
5.0 

4.0 

USE OF NATURAL GAS AND OPPORTUNITIES FOR GREATER CONSUMPTION 

__._ RESIDENTIAl. Gf.S CONSUMPTION (LEFT SCALE) 

--<>-- COMMEACIALGf.SCONSUMPTION(lEFTSCALE) 

--•OF RESIDENTIAL Gf.S HOOKUPS (RIGHT SCALE· 

MIUJONS) 

639 

~ 3.0 

5 

1.0 

A 0.0 ... 0 ... 0 ... 0 ... 0 ... 0 

• ... ... "' "' ... ... ~ ~ ~ ~ ~ ~ ~ "' 

~ "' ~ "' ~ 

7 ... ----<>-~=~~.:.~PETinEUM .............................. ···----··--'----·--·······-------- ______ -+ :~ ~ 

: •·· =:::::::::::::-· ··········••••• s~ ········••••······· j :: ~ 

~: -~==;::=~>= ~~~~;· ~~ t:· i ·····-·-······· ··············- ··---·--······· ···------······ ····--········· ····----·-·---- ···-·----·········-·····-o ___________ !? _____ []__ --···--+ 3 :::E 

B 0 ~~------4---------~--------~---------+---------4--------_,--~~~~~~~~--~--------+---------+ ·-·-·-·-· i 0 

... 

• ... 

2.5 

0 

"' "' "' ... 

~ 

0 "' 0 

"' .. .... ~ ~ ~ 

2 ·····-·-·---··- ..•... ········ ·-------------- ········-·····-----··--------······----

~ 1.5 

0.5 

c 0 ... 0 ... 0 

... "' ... ~ ~ ~ "' 

~ 

3.5 

3 --. --a-- RESIDENTIAL El.l;CTRICITY CONSUMPTION ~oft scale) 

2.5 

~ 

5 1.5 

0.5 

... 

... 

.. 

D 

-•- COMMERCIAL ELECTRICITY CONSUN!PllON (loft scale) 

--• OF HOUSING UNITS HEATED WITH ELECTRICITY (rlgrt 

ICIIe) . 

... 

"' "' 

0 

.. 

"' 

... 

"' 

~ 

:s 

"' 

0 

.... 

~ 

0 

.... 

"' 

"' ... 

~ 

"' .... 

~ 

"' .... 

.. 

0 

., 

~ 

0 

., 

~ 

0 

"' "' 

"' 0 

"' 

~ "' ~ 

"' 0 

: "' 

~ 

"' "' "' 

"' "' "' 

-- ::j ::! ·- 20 !!l I 2 

...•••..• ·······~ :: ~ -- --------·--- ---t 5 ~ 

... ., 

"' 

0 

"' "' 

... 

"' "' 

Figure 3. Residential and commercial sector historical energy consumption. A, Natural gas; B, Petroleum; C, Coal; D, Electricity. Data 

from Energy Information Administration (1992a); American Gas Association (1992). 1 quad=I0 15 Btu (British thermal units). 
640 THE FUTURE OF ENERGY GASES 

Population shifts that might occur, for example, as a 

result of the Nation's uneven economic development and 

activity, will impact regional construction rates of housing 

units and commercial square footage. The mix of singlefamily versus multifamily housing units will also be a factor 

because of perceived disadvantages of gas service installation in multifamily construction. In the southern and western parts of the country, where energy choice is dominated 

by space-cooling requirements, electricity may continue to 

be favored. 

As residential and commercial energy-consuming 

equipment reaches the end of its useful life and is considered for replacement, opportunities for conversion to a different energy source exist. The availability, reliability, and 

cost of alternative fuels, as well as the cost of conversion, 

and the efficiency and performance of alternative equipment will be factors in decisions to convert to alternate 

fuels. Because there are considerable differences in the delivered cost of different energy sources in each region, and 

very wide price variations between regions, the importance of end-user cost of energy will vary from region to 

region. For example, in the New York/New Jersey region, 

the average cost of electricity delivered to a residential 

customer is more than 4 times the average cost of an energy-equivalent amount of natural gas (Energy Information 

Administration, 1992b). Electricity has only a 10 percent 

share of the residential heating market in this region 

(American Gas Association, 1992). In northwestern states, 

electricity is considerably less expensive, averaging less 

than 3 times the cost of natural gas. As a result, in the 

State of Washington, electricity has more than 50 percent 

of the residential heating market (American Gas Association, 1992). 

As shown on figure 3, coal consumption has diminished in the residential and commercial sector to approximately 0.2 quad (I quad=1015 Btu's) per year (fig. 3A). 

Replacement of this relatively small market by natural gas 

will be difficult owing to limited accessibility of gas service in areas of coal consumption. Total replacement of the 

entire coal market by gas would contribute only slightly to 

total gas consumption. Petroleum consumption is currently 

approximately 2 quads per year, significantly lower than 

the highs of greater than 4 in the 1970's (fig. 3B). Petroleum consumption in the residential and commercial sector 

is a market that continues to offer opportunities for greater 

gas consumption. In areas where gas service is available, 

gas technologies for space and water heating could compete favorably with petroleum. Continued expansion of the 

gas distribution system and continued price advantages of 

natural gas over petroleum will favor the selection of gas 

over oil when equipment replacement decisions are made. 

Petroleum use is concentrated along the East Coast, exceeding 50 percent of the residential heating market in 

New England, and averaging 33 percent in middle Atlantic 

states (American Gas Association, 1992). 

As structures are built or updated with greater thermal 

integrity, and as existing equipment is replaced with more 

energy efficient types, the average energy requirement per 

housing unit will continue to decline (see Mills, this volume). This will limit the growth in energy consumption in 

the residential and commercial sectors. It is likely, therefore, that growth in energy consumption in this sector will 

be small. 

INDUSTRIAL SECTOR 

The industrial sector is a large energy-consuming sector 

of the U.S. economy. In particular, four segments of the 

industrial sector (paper and allied products, chemical and 

allied products, petroleum and coal products, and the primary metals industry) accounted for approximately 16 quad 

(quadrillion Btu), or approximately 70 percent of the total 

energy consumed by the industrial sector. The industrial 

sector consumes a wide variety of energy products for a 

diversity of specific applications. The trend of industrial 

energy consumption during 1960-1991 is shown in figure 4. 

Also shown is the Nation's overall energy consumption. 

Additionally, industrial energy consumption is shown with 

and without electricity. Like the residential and commercial 

sector, the industrial sector also experienced strong growth 

in energy consumption until the early 1970's, after which 

time the pattern of steadily increasing energy consumption 

was replaced by a period of wide fluctuation in energy consumption (Energy Information Administration, 1991 a). This 

period was punctuated by pronounced declines in overall 

energy consumption during economic recessions. Energy 

consumption in the industrial sector has also been impacted 

greatly by the changing mix of industrial activity. Energyintensive manufacturing is gradually being replaced by 

service-oriented businesses, which require less energy (Gibbons and Blair, 1990). As in other economic sectors, 

opportunities for increased natural-gas consumption in the 

industrial sector will depend on either ( 1) increased demand 

for energy supplies due to an expansion or change in industrial activity or (2) capture of a greater market share of the 

current industrial energy requirement. 

Industrial energy consumption can be divided into 

feedstock and fuel/power uses. As feedstocks, natural gas, 

petroleum, and small amounts of coal are consumed as 

raw materials in processes. Feedstock use of energy represents approximately 25 percent of the total consumption of 

energy in the industrial sector. Due to physical and chemical differences between the various energy forms, it is unlikely that significant replacement of energy supplies will 

occur in the feedstock market. Changes in consumption 

levels of individual fuels for feedstock and raw material 

use will largely depend on changes in demand for finished 

products. 

The largest portion of energy consumed by industry is 

combusted for steam production, onsite electricity genera-
USE OF NATURAL GAS AND OPPORTUNITIES FOR GREATER CONSUMPTION 641 

tion, and the production of heat. This represents a very 

competitive market, as any of several fuels can provide 

the needed services (Energy Information Administration, 

1991b). Individual fuel choice decisions in the industrial 

sector are impacted primarily by supply availability and 

reliability, price differential, efficiency of consumption, 

installed equipment fuel capability, emerging technologies, and environmental and regulatory constraints on fuel 

consumption. 

The history of consumption of natural gas, petroleum, 

coal, and electricity in the industrial sector from 1960 to 

1991 is shown in figure 5. Coal consumption has been 

steadily declining while electricity consumption has been 

steadily increasing (figs. 5C, D). Natural-gas and oil consumption has varied significantly during the period. During 

the late 1970's, natural gas was often in short supply during peak demand months and industrial customers often 

had their gas supplies curtailed in favor of residential arid 

commercial customers. Oil consumption rose to meet energy demand during the period of gas shortages, but rising 

oil prices of the late 1970's and early 1980's discouraged 

demand for oil (fig. 5B). As gas supplies and deliverability 

recovered in the early to mid 1980's, gas prices rose during 

a period of falling international oil prices. This caused 

many industrial consumers to reduce gas consumption in 

favor of alternative energy sources. Since the mid 1980's 

as the price of gas has fallen in adjustment to deregulation 

and market forces, gas demand and consumption has substantially increased (fig. 5A). This illustrates the nature 

with which choices of energy supply in the industrial sec100 

90 

80 

70 

~ 60 

5 50 

40 

30 

20 

10 

"' 

~ 

tor can fluctuate according to fuel-price differentials and 

regulatory constraints and concerns. If the U.S. economy 

continues to shift away from the energy-intensive manufacturing activities toward more service-oriented businesses, it is likely that the mix of fuels consumed by industry 

will continue to change. 

TRANSPORTATION SECTOR 

The transportation sector of the U.S. economy is predominantly and historically an oil-consuming sector. This 

sector includes fuel consumption for motor vehicles, 

trains, planes, ships, as well as compressor stations which 

move natural gas through pipelines to markets. Figure 6 

shows the overall energy consumption in the transportation sector from 194 7 to 1991. As in other sectors, energy 

consumption for transportation experienced rapid growth 

until the mid-1970's, after which the trend has been irregular, but generally increasing. Consumption has been impacted by economic recessions as well as substantial 

improvements in efficiency, which have been mandated by 

government regulation. For example, the CAFE (corporate 

average fuel efficiency) standards for U.S. manufactured 

automobiles requires manufacturers to meet fuel efficiency 

(miles per gallon) goals in new models. 

The history of consumption of various fuels for transportation service from 1947 to 1991 is shown on figure 7. 

Consumption of natural gas at compressor stations is 

largely a function of total deliveries of natural gas and has 

Figure 4. Industrial sector total energy consumption (solid squares, right scale), primary energy consumption (open squares, right scale), and total U.S. energy consumption (solid diamonds, left scale). Data from Energy Information Administration 

(1992a). 1 quad=I0 15 Btu (British thermal units). 
642 THE FUTURE OF ENERGY GASES 

12 ~--------,---------.---------.----------.---------.---------.---------.---------.---------.---------, 12 

--------------1 10 10 

------------- --------------- --------------- ·-···--------·- ···-------·-··· ······------- . ···-·:··::·::.!' 68 : 6 ········------- ···•··········• ·············- ~ 

4 ----·--······-- ----··-········ _-_·:::·:_·_-_·:·:: :::·:·:: .... : .. ::: .. :.:::·::.: .:::::···:·::: .. ::::: ... ::.::· ·::: .. :::::.::: ::::·····:····· : .... :::· ·.::) 42 0 

2 ···········-··· ·····-------··· 

A 

"' 0 "' 0 "' 0 ... "' "' "' <0 <0 .... .... ~ ~ ~ ~ ~ ~ ~ 

12 

10 

I 6 --------------- --------------- --------------- ----

4 •···•···••····· ··············- ---············ ······-·······- ---············ ............... ·············· 

0 

.. 

~ 

.. "' "' 

0 

.. .. 

2 ··············· --------------- --··-·········· ······ ......... ·····•········· ···········--·· .............................. ·········· ····· . ······-·· 

"' ... 

.. 

B 0 

.. "' "' "' .. 0 

"' "' "' ... 

.. 0 

.... 

.. "' .... .. 0 

.. 

"' .. .. "' 0 

"' "' 

I 

.. "' 

.. 

.. .. "' 

6 ~--------.----------.---------.---------.----------.---------.---------~--------.----------,---------r 

:.............................. ~~~~~····························································· "(Y'J -u;_, ~ 

~ 3 -----------------------------------------------------------------------------------------------------------v~--~------

2 __ • _____ . _ --cr-- INOUSTRIAL TOTAl COAL CONSUMPTION l. __ --INDUSTFIAL NON-RJEL COAL CONSUMPTION I 

c 0~=-------+---------~------~---------+---------+--------~--------~~~~~~~~~·=~--------+ 

"' ... 

.. 0 

"' .. "' "' 

~ 

0 "' 0 

"' ... .... ~ ~ ~ "' 0 "' 0 

.... ... .. ... "' .. ~ ~ ~ ~ ~ 

10 

4 

0 

3.5r---------.--------,---------.--------.---------.--------.---------.--------.---------.--------, 3.5 

···-··············-································-···············-···········--··················:..o.:···················-~~-

2.5 

~ 

~ ': ••••••••••••••••••••••••••••••••••••••••••••• ~~~~".~ •••.••••••• 01.5 ~ 1.5 5 

0.5 ---······. ····· 

D 0 

"' "' "' "' "' 

0 

... 

"' 

0 

.... 

"' "' .... 

"' .. "' "' 

0 

.. 

.. "' .. .. 

0.5 

Figure 5. Industrial sector historical energy consumption. A, Natural gas; B, Petroleum; C, Coal; D, Electricity. Data from Energy Information Administration (1992a). 1 quad=10 15 Btu (British thermal units). 
USE OF NATURAL GAS AND OPPORTUNITIES FOR GREATER CONSUMPTION 643 

fluctuated in a similar fashion to total natural-gas demand 

(fig. 7A). Coal consumption for transportation has declined 

to very small quantities today (fig. 7C). Electricity consumption for transportation is also very small (fig. 7 D). 

Approximately 97 percent of the energy requirements for 

transportation services has been met by petroleum derivatives, primarily motor gasoline, diesel, and aviation fuel 

(fig. 7B). 

Significant opportunity exists for greater natural-gas 

consumption in the transportation market (Energy Information Administration, 1992b; Gas Research Institute, 1988; 

Gott, 1992; National Petroleum Council, 1992; National 

Research Council, 1990; Seisler, 1992; Webb and Farrell, 

1993). At the same time, however, there are significant obstacles which may limit the magnitude of the market for 

natural gas in the transportation market, or may limit the 

pace at which natural gas captures a portion of the transportation fuel market. Natural gas, in compressed form, has 

already been proven to perform well in internal combustion engines (Adams, 1985; Messera, 1985; Sprague, 

1985). Natural gas vehicles (NGVs) are currently in operation in most states (Gott, 1992). Gas utilities have the 

greatest experience with these vehicles, but, increasingly, 

private fleet vehicle operators are finding that natural gas 

offers an attractive alternative to conventional fuels. In 

many places, natural gas has been available at $0.60 to 

$0.76 per gallon of gasoline equivalent (excluding taxes), a 

significant savings over gasoline and diesel. (If natural gas 

used as a vehicle fuel were to be taxed at an equivalent 

rate as gasoline, the price benefit of natural gas would be 

80 

70 . . . . . . . . . . . . . . . . ............ . 

§ 60 

5 50 

40 

30 

... "' 

"' 

0 

"' "' 

"' "' "' 

"' "' "' 

significantly reduced or eliminated). For high mileage, centrally fueled fleets that have high fuel expenses, conversion 

to natural-gas fuel can result in fuel savings. 

The successful penetration of natural gas into the vehicular fuel market, however, depends on the resolution of 

several issues which are currently limiting its use: 

I. Vehicles that currently operate on gasoline must be 

fitted with special equipment which will allow . them to 

operate on natural gas. Specially designed cylinders for 

on-board storage of compressed natural gas are required. 

Additional fuel lines carry the compressed gas from storage to a regulator which reduces the pressure and delivers 

gas to mixers and nozzles which feed the gas to the engine 

at the proper flow rate. Other items adjust the engine for 

the proper spark and ignition timing when operating on 

natural gas. Currently, conversion of a vehicle to naturalgas operation can be expensive. This greatly reduces the 

economic benefits of the lower cost of natural gas vs. gasoline. As the cost of conversion declines, more vehicle 

owners may justify the initial expense as a trade-off for 

lower fuel costs. 

2. The availability of natural-gas fuel for vehicular use 

is probably the biggest limiting factor to NGV acceptance. 

In order to carry enough fuel for an acceptable driving 

range, gas is stored under high pressures in cylinders, and 

special refueling facilities are required to dispense compressed gas. While compression technology is rapidly developing and more natural-gas fueling facilities are being 

built, there are still very few public fueling stations. Some 

operators of large fleets (delivery services, taxis, airport 

"' r-

"' 

0 

"' "' 

... 

140 

··r 35 

--------

"' "' "' 

30 

25 

20 

1 5 

1 0 

§ 

::;:) 

0 

Figure 6. Transportation sector historical total energy consumption (solid squares, 

right scale) and U.S. total primary energy consumption (open squares, left scale). Data 

from Energy Information Administration (1992a). I quad=l0 15 Btu (British thermal 

units). 
644 THE FUTURE OF ENERGY GASES 

0.9 -·------------- ·-------------" ------------------------------ ---·----------- --------------- ---------------

0,8 ------.-------- -------------------------------.-------------. 

0.7 --------------- --------------- ------------------------------

~ 0.6 

:;:) 0.5 

0 0.4 

0.3 

0.2 

0.1 

20 

"' ... 

... 0 

"' ... "' 

... "' 0 

.., 

... 

5 ------·-------- ................................ . 

3.5 

2.5 

~ 

5 1.5 

0.5 

"' ... 

~ 

"' .... 

.. 

B 0 

"' 

~ 

0 

"' ... 

"' "' 

~ 

"' "' ... 

0 

"' 

~ 

0 

"' "' 

"' "' ... 

~ 

"' "' 

~ 

"' "' ... 

0 

.. 

"' 

0 

.. 

~ 

0 

.. "' 

"' .. 

~ 

.. "' 

.. 

0 

., 

... 

0 

., 

~ 

0 

., 

... 

"' ., 

... 

"' ., 

~ 

"' ., 

... 

0 

... 

... 

0 

... 

~ 

0 

... 

... 

0.9 

0.8 

0 7 

::! :.: 0 ~ .. 0.4 

-. 0 3 

... 0 2 

"' "' "' 

0.1 

20 

1 s 

10 

! 3.5 

I t 3 

2.5 

1.5 

I 

...... .j. 0.5 

i 0 

~ 

"' 

~ 

~ :::1 

0 

0.01 .---------,-------~.--------.---------.---------r--------.---------,---------.---------,---------r 0.01 

~ a 

0.009 .............. --------------- ...... -- ................... ------ ...... -- .. - ---------- .. -- .......... ----- ...... -

0.008 

0.007 

0.006 

0.005 

0.004 

~ 5 ~0:0 ••••••·••••••· ••••••••••••••••....•.•••• p--0-o::: .... --{}--{}--. a--0-0 

0.003 

0.002 

0.001 '[j""""" .............. . 

o+=~----~--------~------~-------4--------+-------~--------~------~-------4--------+ 

"' ... 

... 0 .. "' "' .. "' 0 

... "' 0 

"' "' .. "' 

.. 0 

., 

"' "' ., 

... 0 

... 

... "' 

~ "' 

0.009 

0.008 

0.007 

0.006 

0.005 ~ :::1 

0.004 0 

0.003 

0.002 

0.001 

Figure 7. Transportation sector historical energy consumption. A, Natural gas; B, Petroleum; C, Coal; D, Electricity. Data from Energy 

Information Administration (1992a). 1 quad=10 15 Btu (British thermal units). 
USE OF NATURAL GAS AND OPPORTUNITIES FOR GREATER CONSUMPTION 645 

shuttles, and so forth) which operate vehicles within short 

distances from a central point have invested in private 

compression/fueling facilities. Operators of smaller fleets 

and individual car owners can be convinced to convert to 

natural-gas use only when suitably convenient fueling facilities exist for them. 

3. In addition to the economics of conversion and the 

development of a refueling infrastructure, other impediments to vehicular natural-gas use are: (I) public awareness 

and acceptance of a new and different fuel; (2) acceptance 

of shorter vehicle range versus gasoline due to the limited 

gas storage capacity in most cases; (3) industry standardization ofrefueling couplings; (4) concerns about the safety of 

carrying highly compressed, flammable fuel on-board; (5) 

NGV driving performance versus gasoline; (6) the frequency, expense, and availability of NGV maintenance services 

versus gasoline and diesel operation; (7) reasonable assurances of stable and favorable natural-gas fuel costs; (8) 

validation of vehicle warranty for conversions; (9) the availability of original, dedicated NGVs to eliminate the expense 

of after-market conversion to natural gas; (10) the availability of cost-effective, private, home-fueling compression 

equipment which would encourage commuter-vehicle operation despite (or in addition to) a minimal public refueling 

infrastructure; (11) Federal, state, and local government cooperation/involvement with NGV regulation and restriction, 

fuel price and fuel tax issues, environmental regulation, refueling-station siting, and construction regulation. 

Recent legislation, the Federal Clean Air Act Amendments of 1990, requires states to develop plans for reducing air pollution. Unless states institute their own programs 

prior to Federal deadlines, the Act has provisions taking 

effect in the late 1990's which require the cities with the 

dirtiest air to have increasing numbers of "clean-fuel" vehicles in fleets. Because natural gas meets the definition of 

a "clean fuel," many see these environmental compliance 

requirements as the beginning of· a new and greatly expanded phase in natural-gas use as a vehicle fuel. If, for 

example, one-quarter of the motor gasoline currently consumed in the United States were to be replaced by natural 

gas, approximately 3.5 quads of natural gas (equivalent to 

approximately 3.5 trillion cubic feet) would be necessary 

to meet the additional demand. That amount represents an 

increase of approximately 18 percent in the current rate of 

consumption of natural gas in the United States. It also 

may be considerably greater than the current natural-gas 

production and delivery capacity. Many see the eventual 

development of a broad natural-gas refueling and maintenance infrastructure, which will assuage operators concerns 

about fuel availability and vehicle operation, and allow far 

greater travel distances than currently possible. 

There are, however, alternative fuels, such as reformulated gasoline, methanol, ethanol, and electricity, which 

also meet the "clean fuel" definition (Gott, 1992). Competition between these fuels and natural gas will likely be 

very keen. Technology development, fuel efficiency and 

performance, and fuel price differentials will play key 

roles in the adoption of these various fuels. 

ELECTRICITY GENERATION SECTOR 

Electricity generation consumes the largest quantity of 

energy of all the economic sectors. In 1991, electricity 

100 .-----,---.---.-----,----,------,---,------,r---------r---,- 50 

§ 

:::) 

0 

90 ....................... ········ ................ ········ ········ ········ 45 

80 

70 

60 

50 

40 

30 

20 

10 

0 

"' 0 "' 0 "' 0 ... "' "' ., .. ... ~ ~ ~ ~ ~ ~ "' 0 "' 0 ... .. .. .. ~ ~ ~ ~ 

.. .. "' 

40 

35 

30 

25 § 

20 

15 

10 

:::) 

0 

Figure 8. Electricity generation total energy consumption (solid squares, right scale) 

and U.S. total energy consumption (open squares, left scale). Data from Energy Information Administration (1992a). 1 quad=l0 15 Btu (British thermal units). 
646 THE FUTURE OF ENERGY GASES 

generation accounted for nearly 40 percent of the Nation's 

total energy consumption, having steadily increased from 

less than 15 percent in 1950 (fig. 8). In particular, the residential and commercial sector, as well as the industrial sector, has experienced substantial increase since 1960 in the 

amount of electricity consumed (figs. 3D, 5D). Because of 

the convenience, versatility, and acceptance of electrotechnologies, electricity has captured increasing amounts 

of the market for energy services. While electricity will 

continue to encounter considerable competition in certain 

applications that are also served by other fuels, such as the 

use of natural gas and fuel oil for space heating, there are 

many applications which can only be met by electricity, 

such as lighting, home appliances, and business equipment. 

Electricity generation can be disaggregated into different types according to the principal methods of electricity 

production at powerplants: steam turbines driven by heat 

generated from fossil fuel combustion or nuclear reactors, 

internal combustion engines and gas turbines, and hydraulic turbines. Relatively minor amounts of electricity are 

generated by geothermal operations, solar steam and photovoltaic technologies, and wind turbines. On figure 9, the 

historical trend shows that since 1950 most of the increased electricity generation has been accomplished by 

greater amounts of fossil-fueled steam generation, with increasing contribution by nuclear power since the development of nuclear power technologies during 1970's. Figure 

10 shows how fossil steam generation has become increasingly dominated by use of coal as the energy supply. Currently, coal accounts for approximately 75 percent of the 

fossil energy consumed for electricity generation. 

The demand for fuels used to generate electricity is, of 

course, driven by the demand for electricity from endusers in other sectors, principally the residential and commercial and industrial sectors. In these sectors, the level of 

electricity demand is dependent upon the share it captures 

of the overall energy demand. As discussed in the previous 

sections covering each sector, there is considerable competition between energy sources for various energy applications. The overall demand for electricity will depend on 

the following factors: 

1. The rate of construction of new housing units and 

commercial buildings. Greater growth in southern and western regions with climates requiring space cooling favor a 

greater market share for electricity, the predominate energy 

source for space-cooling equipment. 

2. Improvements in the efficiency of energy consuming 

equipment and greater thermal integrity of building shells. 

Heating, cooling, and lighting services that can be delivered 

with Jess energy consumed will mitigate the growth in energy demand caused by increasing residential and commercial 

square footage. 

3. Consumer attitudes regarding energy conservation. 

Reductions in unnecessary energy consumption through 

energy audits. 

4. The continued proliferation of electrical appliances 

for personal and business use, and development of electrotechnologies for industrial applications. 

2500 ···············································¥ 2500 

§ 2000 

; 1500 

52 

§ 1000 

liD 

500 

... 

... 

.. ... 

.. "' 0 .. "' 0 

... 

.. "' ... 

.. 0 

... 

.. "' ... 

... 0 

"' "' "' "' "' 

!{! .2000 ::::> 

~ 

I: 

~ 1500 0 

..J 

52 

z 

Q 

1000 ..J 

..J 

iii 

500 

Figure 9. Electricity generation historical generating capacity. Solid diamonds, total 

capacity. Open diamonds, fossil steam capacity. Solid triangles, nuclear capacity. Solid 

squares, hydroelectric capacity. Open squares, internal combustion and gas turbine capacity. Data from Energy Information Administration (1992a). 
USE OF NATURAL GAS AND OPPORTUNITIES FOR GREATER CONSUMPTION 647 

The opportunities for increased use of natural gas in 

electricity generation, however, depend on the competition 

between the options for generating electricity to meet demand (Electric Power Research Institute, 1992). There are 

a number of factors which will influence the fuel choice 

for electricity generation: 

1. The availability of current generating capacity.-ln 

places, increased electricity demand may be met by greater utilization of unused capacity in existing facilities. 

Some nuclear reactors are still operating at less than full 

capacity. In places where electricity demand is projected 

to exceed capacity, natural gas may be considered in the 

plans to construct new generating capacity. 

2. The availability of fuel supply.-While solid and 

liquid fuels (coal and oil) can be transported by vehicles to 

powerplants and stored on-site until used, the delivery of 

sufficient quantities of natural gas for powerplant operation requires the construction of pipelines to bring gas 

supplies from producing regions and underground storage 

sites. Increased gas consumption for electricity generation 

will depend on sufficient pipeline capacity to meet a powerplant's gas demand. 

3. The required flexibility of power generation.-Electricity demand varies widely and rapidly in hourly, daily, 

and seasonal patterns that result, for example, from differences between daytime and nighttime electricity requirements, diminished utilization of some commercial buildings 

during weekends, and weather fluctuations. Because electricity cannot be stored, the generation of electricity to 

2000 

1800 

1600 

K! 

;:) 1400 

0 

instantaneously match demand requires considerable flexibility. Utilities use a variety of generating facilities which 

provide flexibility to meet the fluctuating demand. The majority of electricity is generated at base-load plants which 

routinely produce the minimum electricity demand. These 

plants require less flexibility because they operate essentially continuously. Other plants are designed to meet weekly, 

daily, and hourly demand fluctuations above the levels produced by the base-load plants. This electricity demand is 

often referred to as intermediate and peak demand. Because 

peak electricity demand can change very rapidly as homes 

and business activate space conditioning equipment to compensate for temperature fluctuations, the plants which provide electricity to meet these intermediate and peak loads 

have to respond quickly. Some gas-fired technologies, particularly gas turbines, are well suited for meeting rapid electricity demand fluctuations because they can be started very 

quickly and operated more flexibly than base-load plants. 

4. Cost of construction.-As growth and changes in 

electricity demand forces the construction of additional 

generating facilities, the cost of various plant designs and 

fuel options will be major factors in selecting from the 

investment options. Some gas-fired generating technologies, particularly turbines, have significantly lower capital 

requirements than nuclear and coal-fired plants. In addition, gas-fired plants can normally be sited, permitted, and 

constructed in much less time than others. 

5. Fuel cost.-Because electricity generation is such an 

energy-intensive industry, the cost of fuel is a large factor 

--------1-- j /~·,L. __ --rl! :::: 

.r·-· ;·/· ...... 

-- -- -;--./_ \-· __ -------- t 1600 

---('-Y 1400 K! 

;:) 

::r:: 

1: 1200 

/. 

---------------/ 1200 ~ 

1: 

0 

~ 1000 

:! 

~ 

z 800 

Q 

....1 

....1 

iii 600 

400 

200 

I -------------- - ·--- -------- /__ /. 

I /. --.----------. --- - ---- ·;•·------

;• 

/ . -- .• .-:.+..-.- ---------- - ;-" 

.-·-· .." ---I /. / . .--• --.- ·•""-.t: ... - -- -------- ---. 

1000 

-T 800 

li:Qj~xi\o'l '•-•-•• n.,._""'.-'<~1-C-~HJTKJ' E 

+----+----+---_,·----+----+----+----+---+----- 0 

"' "' "' 

0 

"' ., 0 

,.__ 

., 0 

"' ., "' "' "' 

0 

., 

., 

~ 0 

....1 

52 

z 

Q 

....1 

....1 

iii 

Figure 10. Electricity generation historical fossil steam generating fuels. Solid diamonds, total fossil steam generation. Open diamonds, coal steam generation. Solid 

squares, petroleum steam generation. Open squares, gas steam genertion. Data from 

Energy Information Administration ( l992a). 
648 THE FUTURE OF ENERGY GASES 

in fuel selection. Many plants with dual fuel capability seek 

to minimize costs by consuming fuels which offer the lowest cost option. Fuel costs vary considerably from region to 

region and from time to time as a result of regional differences in fuel availability and transportation charges, and the 

effects of changing supply/demand balance. 

6. Regulation.-Attempts to reduce air pollution in 

certain regions has resulted in changes to environmental 

regulations which impose new costs of compliance with 

legislation that is intended to reduce air pollution. In places, there are restrictions on the use of certain fuels at certain times of the year in electric power generation to 

reduce combustion emissions. 

Consumption of natural gas in electricity generation 

peaked at approximately 4 quads in the early 1970's 

(fig. llA). Since that time it has fluctuated around a slow 

decline to the current level of approximately 3 quads, a 25 

percent decline. Figure liB shows how petroleum consumption has declined by almost 75 percent from a historic 

high of 4 quads in 1978 to only 1 quad today. Coal consumption has steadily increased and now accounts for more 

than 16 quads of energy consumed to produce electricity 

(fig. 11 C). Many forecasts suggest that natural-gas consumption will increase considerably over the next several 

years. Announced plans for construction of new generating 

capacity to support increased electricity demand show that 

indeed many of the new plants are being designed to consume natural gas. Of 421 units currently planned for construction through the year 2000, nearly 50 percent are 

planned to use gas as the primary energy source. At the end 

of 1990, less than 20 percent of the 10,296 existing U.S. 

powerplants used gas as a primary energy source (Energy 

Information Administration, 1991 c). 

The principal challenges to increased gas consumption 

in electricity generation are reliability of gas service, pipeline operating flexibility, and pipeline supply capacity 

(Electric Power Research Institute, 1992). Reliance on natural gas as the primary energy source for electricity generation implies dependence on a gas supply infrastructure 

that is capable of routinely delivering large volumes of gas. 

During periods of high gas consumption, close coordination is required between wellhead deliveries, gas processing facilities, transmission capacity, and underground 

storage options. Routine delivery requires reliability at 

each point in the flow of gas from the wellhead to the 

powerplant. Because of the highly variable operating 

schedule of most gas-fired plants, the gas supply infrastructure must have the flexibility to meet the rapidly fluctuating gas requirements at a powerplant. Close coordination 

between the powerplant and the gas supplier is required to 

assure that gas supplies can be delivered when needed, in 

sufficient volumes, and at required pressures. The pipeline's operating characteristics and capability to adjust frequently and rapidly to changing demand are important to 

reliable gas service at powerplants. New gas-fired generating units need assurance that the natural-gas resource base 

and the existing pipeline delivery capacity is sufficient to 

account for the requirements of the powerplant as well as 

the projected needs of the pipelines existing customers. 

The construction of multiple gas-fired plants along a single 

pipeline corridor may create considerable difficulty for a 

pipeline to deliver sufficient gas to meet a potential simultaneous gas demand from many large consumers. Widespread regional climate fluctuations, such as heat waves or 

cold snaps, could significantly increase regional electricity 

demand for space conditioning thus triggering the start-up 

of multiple intermediate and peaking generators. Simultaneous operation of several gas-fired plants along a pipeline 

corridor could rapidly deplete the available delivery capacity from underground storage capacity or pipeline operating flexibility. 

SUMMARY 

Each economic sector presents different challenges 

and opportunities for the increased use of natural gas to 

meet the Nation's future energy needs. Regional and local 

expansion of gas pipeline transmission and distribution 

systems will bring natural-gas service to many new residentiaVcommercial customers throughout the country, but 

the overall growth in demand for gas by this segment will 

be mitigated by conservative attitudes and improvements 

in the efficiency of gas-fired equipment, especially for 

space conditioning and water heating, and continued improvement in the thermal integrity of structures. More and 

more gas customers will each be consuming less and less 

fuel, leading to an overall stable gas demand in the residentiaVcommercial energy market. 

The transportation sector presents a potentially large 

and essentially new market for natural gas. With the impetus of recent air quality legislation, clean-fuel vehicle 

mandates, and a fuel-price advantage for natural gas, the 

possibility exists for a slow but steady development of a 

broader and denser population of compressed natural-gas 

refueling stations and use of natural gas in commercial 

and government fleets and eventually individual private 

vehicles. A number of issues will expedite the penetration 

of natural gas into the vehicle fuel market: the development and marketing of dedicated-fuel natural-gas vehicles 

and cost-effective conversion equipment and services; 

public relations efforts to increase awareness and acceptance of natural-gas vehicles; continuation of the naturalgas fuel price advantage over gasoline; continuation of the 

favorable tax treatment of natural gas versus gasoline for 

natural gas that is consumed as vehicle fuel. 

The industrial and electricity generation sectors are 

large, price-sensitive energy consumers. There is considerable potential for increased gas consumption by replacement 

of current energy sources in fuel-switchable applications 

such as industrial process heat applications and steam generation for electricity generation. Fuel choices, however, will 
USE OF NATURAL GAS AND OPPORTUNITIES FOR GREATER CONSUMPTION 

~ 3 ··············· ··············· .. 

5 2 .... 

A 0 

"' 0 .. "' "' "' ~ ~ ~ 

3.5 ······ --- ----·· 

3 ··············· 

2.5 ---------------

2 .•............. •····•····•··•·•······ 

1.5 -----·--------- --------------

0.5 

B 0 

"' 0 

... :ll ~ "' 

~ .. 18 

0 "' "' ::: ~ 

0 "' "' 

~ ~ "' 

0 

,_ 

~ 

0 

,_ 

"' 

:e 

.. 

16 ................... ··········· ········ ...... ··············· . ·············· .. ············· .. . 

14 

12 

~ 10 

5 . 8 

4 

2 .......... . 

oc 

"' .. 

"' 

2 ··············· 

.. "' "' 

D 0 

"' "' 

"' "' "' 

0 

"' "' 

--- EU:CGEN HYDRO POWERCONSUMPTON 

0 

"' "' 

"' "' "' 

"' "' "' 

0 

"' "' 

0 

"' "' "' .... 

"' 

~ .. 

0 

"' "' 

0 

"' "' 

0 

"' "' 

"' "' 

~ 

"' 

.. "' 

., 

"' "' 

:5: 

.. 

0 

.. 

~ 

0 

0> 

.. 

0 

"' "' 

649 

----

·+ 

., 

g: 

.. "' 

0> 

"' "' 0> 

3.5 

2.5 

~ :::l 

0 1.5 

1 

0.5 

18 

Figure 11. Electricity generation historical energy consumption. A, Natural gas; B, Petroleum; C, Coal; D, Nuclear and hydro. Data from 

Energy Information Administration (1992a). I quad=I0 15 Btu (British thermal units). 
650 THE FUTURE OF ENERGY GASES 

continue to be dominated by the least-cost options which are 

accompanied by the most reliable, efficient, and flexible 

service. Competitive pricing, adequate pipeline capacity, 

and demonstrable operational flexibility will be the keys to 

successful marketing of more natural gas to the industrial 

and electricity generation consumer. Environmental restrictions on specific fuel use in some regions and the cost of 

compliance with emission-control regulations will favor natural gas as the cleanest burning fossil fuel. 

In many applications, natural gas is an attractive choice 

among U.S. energy options. It is a domestically available 

and relatively inexpensive energy product with efficient and 

clean burning characteristics that offers environmental benefits. If the natural-gas industry can successfully expand its 

production and distribution capability, maintain its energy 

price advantage, establish a reputation for reliable and flexible delivery, and continue the development of energy-efficient gas-fired technologies, there is significant opportunity 

for greater consumption of natural gas. 

REFERENCES CITED 

Adams, T.G., 1985, The performance of new dedicated CNG vehicles, in Nonpetroleum Vehicular Fuels V-CNG Fuel, 

symposium papers: Chicago, IL, Institute of Gas Technology, p. 47. 

American Gas Association, 1992, 1992 Gas facts-1991 data: 

Arlington, Va., American Gas Association, 204 p. 

Electric Power Research Institute, 1992, Natural gas for electric 

generation-the challenge of gas and electric industry cooperation: Palo Alto, CA, Electric Power Research Institute 

TR-101239. 

Energy Information Administration, 1991a, Changes in energy 

intensity in the manufacturing sector, 1980-1988: Washington, D.C., Energy Information Administration DOE/EIA0552(80-88), 70 p. 

---199lb, Manufacturing fuel-switching capability 1988: 

Washington, D.C., Energy Information Administration DOE/ 

EIA-0515(88), 132 p. 

---199lc, Inventory of powerplants in the United States 

1990: Washington, D.C., Energy Information Administration 

DOE/EIA-0095(90), 405 p. 

---1992a, Annual energy review, 1991: Washington, D.C., Energy Information Administration DOE/EIA-0384(91), 347 p. 

---1992b, Annual energy outlook 1992, with projections to 

2010: Washington, D.C., Energy Information Administration 

DOE/EIA-0383(92), 148 p. 

Gas Research Institute, 1988, Natural gas vehicles-New targets, 

reprinted from GRID: Chicago, IL, Gas Research Institute, 

10 p. 

---1992, 1992 edition of the GRI baseline projection of U.S. 

energy supply and demand to 2010: Chicago, IL, Gas Research Institute, 146 p. 

Gibbons, J.H., and Blair, P.D., 1990, Energy efficiency-Its potential and limits to the year 2000, in Helm, J.L., ed., EnergyProduction, consumption, and consequences: Washington, 

D.C., National Academy of Engineering, National Academy 

Press, p. 35-51. 

Gott, S. 1992, Natural gas vehicles-The road to 2000: Arlington, Va., Pasha Publications, 150 p. 

Messera, · J.R., 1985, Operating experience of a large CNG vehicle fleet, in Nonpetroleum Vehicular Fuels V-CNG Fuel, 

symposium papers: Chicago, IL, Institute of Gas Technology, p. 69. 

National Petroleum Council, 1992, The potential for natural gas 

in the United States: Washington, D.C., National Petroleum 

Council, six volumes. 

National Research Council, 1990, Fuels to drive our future: 

Washington, D.C., National Academy Press, 223 p. 

Seisler, J., 1992, Strategy for global commercialization of 

NOV's, in proceedings of The Outlook for Natural Gas: 

Chicago, IL, Institute of Gas Technology, 16 p. 

Sprague, R.W., 1985, National Fuel's experience with the installation, maintenance and repair of CNG vehicles, in Nonpetroleum Vehicular Fuels V-CNG Fuel, symposium papers: 

Chicago, IL, Institute of Gas Technology, p. 35. 

Webb, D.O., and Farrell, M.D., 1993, End-use technology advancing in cooling techniques, NGVs, and fuel cells, in Willett, R.E., ed., The 1993 natural gas yearbook: New York, 

Executive Enterprises Publications, p. 195-214. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Methodology for Estimating Volumes 

of Flared and Vented Natural Gas 

By Timothy R. Klett1 and Donald L. Gautier1 

CONTENTS 

Introduction ................................................................... 651 

Estimating of Historical Volumes of Flared and 

Vented Gas .................................................................... 651 

Examples from Saudi Arabia and Nigeria ................... 652 

Worldwide Volumes of Flared and Vented Gas ........... 656 

Conclusion .................................................................... 658 

References Cited ........................................................... 659 

INTRODUCTION 

The common perception in the United States that natural gas produced with oil is a valuable commodity probably dates from the 1940's. Before that time, most 

operators regarded natural gas associated with or dissolved 

in oil as a nuisance. Indeed, most associated/dissolved natural gas produced in the United States before World War 

II probably was flared or vented to the atmosphere. This 

situation has changed in the United States, where flaring 

and venting have decreased dramatically in recent years, 

in part because of environmental concerns, but also because of the changing view of the value of natural gas. 

The idea that gas is a nuisance is beginning to change 

almost everywhere, as markets for gas have developed in 

Europe, Japan, and elsewhere, and as operators have increasingly utilized or reinjected associated-dissolved gas 

in their oil-production activities. Nevertheless, in some 

1

U.S. Geological Survey, Denver Federal Center, Box 25046, Denver, CO 80225-0046. 

areas natural gas continues to be flared or vented to the 

atmosphere. Gas flares in Russia, the Niger Delta, and the 

Middle East are some of the brightest lights on the nighttime Earth (Hansen Planetarium, 1986). 

As we increasingly consider the global availability and 

utility of natural gas, and the environmental impacts of the 

consumption of carbon-based fuels, it is important to 

know how much gas has been flared or vented, how much 

gas is currently being flared or vented, and the distribution 

of flaring or venting through time. Unfortunately, estimates of the volumes of flared and vented gas are generally not available. 

ESTIMATING OF HISTORICAL VOLUMES 

OF FLARED AND VENTED GAS 

The first step in estimating the volumes of flared and 

vented gas is to gather available data. Calculation of volumes of flared and vented gas requires knowledge of oil 

production, produced associated-dissolved gas to produced 

oil (gas/oil) ratios, and the ratio of flared and vented gas to 

total gas production, each as a function of time. Generally 

not all of these data are available, and approximations or 

extrapolations must be made from the information at hand. 

When the data are sparse or nonexistent, we estimate volumes by extrapolating present production data back 

through time. For the purpose of extrapolation, the data 

should include both oil and associated-dissolved gas volumes. Where data for associated-dissolved gas volumes are 

not available, these volumes are calculated by taking the 

difference between volumes of total (gross) gas and dry 

gas. We do not know the proportion of vented to flared gas, 

but we assume that the volumes of vented gas are small. 

Throughout history, some natural gas was produced for the 

651 
652 THE FUTURE OF ENERGY GASES 

extraction of natural gas liquids (condensate), and the excess gaseous phase was flared or vented. Therefore, this 

extrapolation method may underestimate the volumes of 

flared or vented gas. The volume of this type of flared gas 

is small, however, and does not significantly contribute to 

the worldwide total volume of gas flared. 

Next, the associated-dissolved gas volumes must be 

extrapolated back through time. This was done by calculating the equation of an appropria~ regression function 

through the apparent gas/oil ratios calculated from associated-dissolved gas and oil production data versus time. 

This equation was then used to estimate values of associated-dissolved gas volumes for past years. Inasmuch as the 

oil-production data are the most reliable and well documented, and gas/oil ratios do not change drastically with 

time, the regression equation derived from the gas/oil-ratio 

data is generally preferable as a basis for extrapolating associated-dissolved gas values. 

Finally, the volumes of flared and vented gas were estimated using the extrapolated associated-dissolved gas 

values. This estimate accounts for the greatest proportion 

of error because flaring practices have changed significantly through time, particularly during the past fifteen years. 

In most countries, most of the associated-dissolved gas 

was flared or vented until the late 1970's; since then, gas 

production and reinjection technologies have become profitable. In this study, we assumed that before 1978 the volumes of reinjected gas and natural gas associated with 

natural gas condensate production outside the United 

States were small, and flared and vented gas volumes were 

assumed to be roughly equal to the total volume of associated-dissolved gas. Amounts of flared and vented gas and 

reinjected gas after 1978 are generally well reported. 

However, if flared and vented gas data are unavailable for 

certain recent years, the volumes can be estimated by multiplying associated-dissolved gas volumes by the available 

reported proportions of flared and vented gas to associated 

dissolved gas of neighboring years. 

EXAMPLES FROM SAUDI ARABIA 

AND NIGERIA 

Volumes of flared and vented gas were estimated for 

Saudi Arabia and for Nigeria by extrapolating data from 

the Energy Information Administration (EIA), the International Petroleum Encyclopedia, Schatz! (1969), and the. 

Arabian American Oil Company (ARAMCO) (1968). 

These data are shown in tables 1 and 2. The data provided 

from these various sources are incomplete. Data reported 

by EIA and the International Petroleum Encyclopedia are 

inconsistent due to the differences in their respective 

sources, as indicated in tables 1 and 2. 

Gas/oil ratios and associated-dissolved gas volumes 

were calculated by the regression methods described above. 

The data and regression equations used for estimating gas/ 

oil ratios for Saudi Arabia and Nigeria are shown in 

figures 1 and 2. Associated-dissolved gas values were calculated by multiplying the oil-production data by the calculated gas/oil ratios. Because the EIA oil-production data 

500 

450 

400 

:c -

.c 

350 

- 300 --:I 250 u 

- 200 a: 

0 150 " 100 

50 

0 

1975 

• •• • 

• 

• ••• • • 

1980 1985 1990 1995 

Year 

Figure 1. Actual gas/oil ratios (GOR), in cubic feet per barrel 

(cu ftlbbl), calculated from associated-dissolved gas and oil 

production data through time for Saudi Arabia. The regression 

equation is GOR (cu ftlbbl)=27446-(14 X year), having a correlation of r 2

=0.62. 

1400 

1200 

:c - 1000 

.c 

= 800 

:I 

~ 600 

a: 

0 

" 400 

200 

0 

•• 

• I. 

••• • 

• • 

• ........ 

1955 1965 1975 1985 1995 

Year 

Figure 2. Actual gas/oil ratios (GOR), in cubic feet per barrel 

(cu ftlbbl), calculated from associated-dissolved gas and oil 

production data through time for Nigeria. The regression 

equation is GOR (cu ft/bbl)=-12970+(7 X year), having a 

correlation of r 2

=0.27. 
Table 1. Reported oil and gas production data, associated-dissolved gas volumes and gas/oil ratios, and volumes of flared and vented gas from the International 

Petroleum Encyclopedia and International Energy Annual for Saudi Arabia. 

(Associated-dissolved gas volumes and gas/oil ratios and flared and vented gas volumes from the International Petroleum Encyclopedia and International Energy Annual. IPE, International Petroleum 

Encyclopedia; ARAMCO, Arabian American Oil Company; EIA, Energy Information Administration; Bcf, billion cubic feet; MM, million; bbl, barrels. Open space indicates no data] 

Oil Oil Gfoss natural Gross natural Dry natural Associated-dissolved Gas/oil ratio Gas/oil ratio Associated-dissolved 

production production gas production gas production gas production gas (calculated from EIA Data) (calculated from EIA Data) (estimated) gas (estimated) 

Year (MMbblfyr) (MMbbl/yr) (Bcf/yr) (Bcf/yr) (Bcf/yr) (Bcf) (ft 3/bbl) (ft 3 fbbl) (Bcf/yr) 

3: IPE ARAMCO ( 1968) IPE EIA EIA This paper This paper This paper This paper tT1 EIA ...., 

1938 0.5 994 0.5 ::r:: 

0 

1939 4 980 4 tl 

1940 5 5 967 5 0 

1941 4 953 4 " 0 1942 5 939 4 0 

1943 5 926 5 o-< 

1944 8 912 7 'Tl 

1945 21 898 19 0 

1946 60 885 53 :::0 

tT1 1947 90 871 78 vo 1948 143 858 122 ...., 

1949 174 844 147 -

3: 

1950 200 200 830 166 

1951 278 817 227 ~ 

1952 302 803 242 z 

1953 308 789 243 0 

1954 348 776 270 < 

1955 352 352 762 268 0 

" 1956 361 748 270 e 

1957 362 735 266 3: 

1958 370 721 267 tT1 

1959 400 400 707 283 vo 

0 1960 456 456 694 317 'Tl 

1961 508 508 680 346 

1962 555 555 666 370 fl 

1963 595 595 653 388 > :::0 1964 628 628 639 401 tT1 

1965 739 739 625 462 tl 

1966 873 873 612 534 > 

1967 948 948 598 567 z 

1968 1036 1036 585 605 tl 

1969 1092 1092 571 624 < tT1 1970 1295 1295 557 722 z 

1971 1642 1642 544 892 ...., 

1972 2098 2093 530 1109 tT1 

tl 1973 2677 2773 160 516 1431 z 1974 2997 3095 220 503 1556 

1975 2492 2582 220 489 1263 ~ 1976 3054 3139 290 475 1492 e 

1977 3290 3374 121 280 462 1558 ~ 1978 2942 3030 102 330 448 1357 

1979 3377 3479 209 1786 390 1396 401 434 1511 " 0 

1980 3525 3623 310 370 421 1524 > 

1981 3519 3582 435 1850 460 1390 388 407 1458 vo 

1982 2367 2366 591 1185 201 984 416 393 931 

1983 1778 1856 382 950 200 750 404 380 705 

1984 1663 1707 240 1026 253 773 454 366 625 

1985 1203 1237 252 1133 716 417 337 352 436 

1986 1723 1778 329 1430 890 540 304 339 602 

1987 1480 1557 741 1386 946 440 283 325 506 0\ 1988 1723 1861 899 1596 1028 568 306 312 580 VI 

1989 1801 1848 1632 1632 1052 580 314 298 551 UJ 

1990 2267 2340 1401 1741 1077 664 284 284 665 

1991 2978 1590 271 0 
Table 2. Reported oil and gas production data, associated-dissolved gas volumes and gas/oil ratios, and volumes of flared and vented gas from the International 

Petroleum Encyclopedia and International Energy Annual for Nigeria. 

0\ 

Ul 

[Associated-dissolved gas volumes and gas/oil ratios and flared and vented gas volumes from the International Petroleum Encyclopedia and International Energy Annual. IPE, International Petroleum Encyclope- ~ 

dia; EIA, Energy Information Administration; Bcf, billion cubic feet; MM, million; bbl, barrels. Open space indicates no datal 

Oil Oil Gross natural Gross natural Dry natural Associated-dissolved Gas/oil ratio Gas/oil ratio Associated-dissolved 

production production gas production gas production gas production gas (calculated from EIA Data) (calculated from EIA Data) (estimated) gas (estimated) 

Year (MMbbl/yr) (MMbbl/yr) (Bcf/yr) (Bcf/yr) (Bcf/yr) (Bcf) (ft 31bbl) (ft31bbl) (Bcf/yr) 

IPE Schiitzl ( 1969) IPE EIA EIA This paper This paper This paper This paper 

EIA 

1938 

1939 

1940 

1941 

1942 

1943 

1944 

1945 

1946 

1947 

1948 

1949 >-l 1950 

1951 fii 

1952 'T1 

1953 ~ 

>-l 1954 ~ 

1955 Gl 1956 

1957 0 

'T1 1958 0.2 1065 832 0.2 tT1 1959 4 2 891 839 3 z 

1960 6 5 1103 846 5 tT1 

1961 17 7 745 853 14 :;tl 

a 1962 25 21 659 860 21 --<: 

1963 28 25 725 867 24 a 1964 44 30 804 874 39 ;J> 

1965 99 55 852 881 88 Cl:l 

1966 152 112 763 888 135 tT1 Cl:l 

1967 117 895 104 

1968 so 902 46 

1969 197 909 179 

1970 395 916 362 

1971 559 141 923 516 

1972 665 32 930 618 

1973 750 750 60 937 703 

1974 823 823 60 945 777 

1975 651 651 91 952 619 

1976 756 757 633 959 725 

1977 761 761 717 966 735 

1978 692 692 595 973 674 

1979 841 840 366 1061 18 1043 1241 980 824 

1980 753 752 188 987 743 

1981 500 523 66 994 497 

1982 483 473 69 50 1001 484 

1983 450 453 145 536 81 455 1004 1008 453 

1984 518 508 72 583 97 486 959 1015 525 

1985 528 546 96 618 108 510 935 1022 539 

1986 534 535 72 642 116 526 982 1029 550 

1987 452 489 99 583 131 452 923 1036 468 

1988 497 531 126 648 134 514 971 1043 519 

1989 586 626 844 844 166 678 1082 1050 615 

1990 660 661 134 978 131 847 1282 1057 698 

1991 678 115 1064 722 
METHODOLOGY FOR ESTIMATING VOLUMES OF FLARED AND VENTED NATURAL GAS 655 

are more complete for Saudi Arabia than for Nigeria, these from these values for those years for which data are availdata were used to calculate the associated-dissolved gas able are shown in tables I and 2. In addition, gas/oil ratios 

volumes for Saudi Arabia. Likewise, the International Pe- and associated-dissolved gas volumes estimated for all 

troleum Encyclopedia oil-production data were used to cal- years by means of regression equations (figs. I, 2) are also 

culate associated-dissolved gas volumes for Nigeria. The shown in tables I and 2. 

associated-dissolved gas volumes calculated by subtracting Estimates of flared and vented gas volumes for all 

dry from gross gas production and the gas/oil ratios derived years are shown in table 3. These estimates represent all 

Table 3. Comparison of reported (Organization of Petroleum Exporting Countries, 1993) and estimated flared and vented gas volumes for Saudi 

Arabia and Nigeria. 

[Associated-dissolved gas volumes and gas/oil ratios and flared and vented gas volumes from the International Petroleum Encyclopedia and International Energy Annual. IPE, International 

Petroleum Encyclopedia; EIA, Energy Information Administration; OPEC, Organization of Petroleum Exporting Countries; Bcf, billion cubic feet. Open space indicates no data] 

Saudi Arabia Nigeria 

Associated-dissolved Flared and Reported flared Reponed flared Associated-dissolved Flared and Reported flared Reported flared 

gas vented gas and vented gas and vented gas gas vented gas and vented gas and vented gas 

Year (Bcf/yr) (Bcf/yr) (Bcf/yr) (Bcf/yr) (Bcf/yr) (Bcf/yr) (Bcf/yr) (Bcf/yr) 

This paEer This paeer EIA OPEC This eaeer This eaper EIA OPEC 

1938 0.5 0.5 

1939 4 4 

1940 5 5 

1941 4 4 

1942 4 4 

1943 5 5 

1944 7 7 

1945 19 19 

1946 53 53 

1947 78 78 

1948 122 122 

1949 147 147 

1950 166 166 

1951 227 227 

1952 242 242 . 1953 243 243 

1954 270 270 

1955 268 268 

1956 270 270 

1957 266 266 

1958 267 267 0.2 0.2 

1959 283 283 4 4 

1960 317 317 7 7 

1961 346 346 13 13 

1962 370 370 16 16 

1963 388 388 20 20 21 

1964 401 401 35 35 35 

1965 462 462 85 85 91 

1966 534 534 329 116 116 96 

1967 567 567 368 104 104 87 

1968 605 605 390 46 46 46 

1969 624 624 429 179 179 143 

1970 722 722 524 362 362 282 

1971 892 892 703 516 516 452 

1972 1109 I 109 956 618 618 595 

1973 1431 1431 1342 703 703 715 

1974 1556 1556 1380 777 777 926 

1975 1263 1263 1030 619 619 655 

1976 1492 1492 1321 725 725 758 

1977 1558 1558 1321 735 735 740 

1978 1357 1357 1162 674 674 708 

1979 1396 1342 1342 1342 1043 1013 1013 1013 

1980 1528 1230 1355 743 722 829 

1981 1390 903 903 903 497 482 507 

1982 984 755 755 755 484 470 453 

1983 750 576 576 576 455 442 442 442 

1984 773 525 525 149 486 465 465 481 

1985 417 110 110 109 510 460 460 494 

1986 540 98 98 85 526 445 445 491 

1987 440 71 71 71 452 417 417 433 

1988 568 117 117 117 514 433 433 521 

1989 580 138 138 145 678 614 614 663 

1990 664 184 184 267 847 744 744 791 

1991 807 226 463 722 701 800 

Total 29781.5 22820 4819 17591 14311.2 13763 5033 14269 
656 THE FUTURE OF ENERGY GASES 

associated-dissolved gas production until 1978 for both Nigeria and Saudi Arabia and percentages of total associateddissolved gas production after 1978, based on mean ratios 

of flared and vented gas to associated-dissolved gas production in recent years from EIA data. These percentages 

are 80.5 percent between 1979 and 1981 and 28.0 percent 

in 1990 for Saudi Arabia, and 97.1 percent between 1979 

and 1990 for Nigeria. 

Data on the volumes of flared and vented gas have 

been reported by the Organization of the Petroleum Exporting Countries (OPEC) for certain countries, including 

Saudi Arabia and Nigeria, since 1963. These data, which 

are presumed to be reliable (table 3), provide a test of the 

accuracy of the volumes of flared and vented gas estimated by the extrapolation procedure (figs. 3, 6, 7). 

The history of gas flaring in Saudi Arabia and Nigeria 

is shown in figures 3 and 4. On the basis of these calculations, we estimate that from 1963 until 1990, Saudi Arabia 

and Nigeria flared and vented 21.0 and 13.0 trillion cubic 

feet (Tcf) of natural gas, respectively. These values are 

comparable to OPEC data, which show 17 and 14 Tcf 

flared and vented in Saudi Arabia and Nigeria, respectively. We further estimate that a total of more than 23 Tcf 

have been flared and vented in Saudi Arabia and more 

than 14 Tcf have been flared and vented in Nigeria since 

the beginning of oil production in those two countries. 

WORLDWIDE VOLUMES OF FLARED 

AND VENTED GAS 

The extrapolation method used to calculate volumes of 

flared and vented gas in Saudi Arabia and Nigeria can be 

used to estimate the volume of gas flared and vented 

worldwide since the first production of oil. Tables 4, 5, 

and 6 show world oil production through time (data from 

DeGolyer and MacNaughton, 1990, and EIA). Oil-production data are documented for 1918 to the present. Production values prior to 1918 were linearly extrapolated back 

to 1858 when oil was first produced. Because of the lack 

of data, we arbitrarily chose the first-year oil production to 

be 1,000 barrels. This linear extrapolation is reasonable in 

calculating world totals, because the volume of oil produced prior to 1918 is small compared to total world oil 

production. 

Worldwide gas/oil ratios were calculated using the difference between gross gas and dry gas, as described above. 

We used gas/oil ratios from EIA for 1979 to 1991. These 

data indicate a general increase in the produced gas/oil ratios from 1979 to 1991 (fig. 5). The gas/oil ratios increase 

over time for several reasons, mostly because more associated-dissolved gas has been produced in recent years as it 

became more profitable, and most of the world's major oil 

fields are becoming mature; their increasing gas/oil ratios 

1400 

- 1200 ... 

~ 1000 -() 

m 

- 800 

tn 

(Q 

(!' 600 

"C 

Q) 400 ... 

.!!! 

LL 200 

0 

1960 1970 1980 1990 

Year 

Figure 3. Volumes of gas, in billion cubic feet per year (Bcf/ 

yr), flared and vented in Saudi Arabia (Organization of the 

Petroleum Exporting Countries, 1993). 

1400 

- 1200 ... 

~ 1000 -() 

m 

- 800 

tn 

(Q 

(!' 600 

i 400 ... 

(Q 

u:::: 200 

0 

1955 1965 1975 1985 1995 

Year 

Figure 4. Volumes of gas, in billion cubic feet per year (Bcf/ 

yr), flared and vented in Nigeria (Organization of the Petroleum Exporting Countries, 1993). 

are being reflected in the world values. As a consequence 

of using these recent data, however, extrapolated values 

become negative for years prior to 1953. Such negative 

gas/oil ratios are obviously erroneous, but we attempted to 

use available data to suggest possible quantities of total gas 

flared and vented through time. 
METHODOLOGY FOR ESTIMATING VOLUMES OF FLARED AND VENTED NATURAL GAS 657 

Table 4. Reported worldwide oil production, calculated gas-oil 

ratio (CGOR), and gas-oil ratio estimated by regression analysis 

(EGOR). 

[Data for CGOR from DeGolyer and MacNaughton ( 1990) and Energy Information 

Administration. Mbbl, thousand barrels; ft 3

1bbl, cubic feet per barrel. Open space 

indicates no data] 

Year Oil CGOR EGOR Year Oil CGOR EGOR 

(Mbbl) (ft31bbl) (ft31bbl) (Mbbl) (ft31bbl) (ft31bbl) 

1858 I 0.0 1925 1067933 0.0 

1859 8392 0.0 1926 1096823 0.0 

1860 16784 0.0 1927 1262582 0.0 

1861 25176 0.0 1928 1324774 0.0 

1862 33568 0.0 1929 1485867 0.0 

1863 41960 0.0 1930 1411904 0.0 

1864 50352 0.0 1931 1373656 0.0 

1865 58744 0.0 1932 1310298 0.0 

1866 67135 0.0 1933 1441000 0.0 

1867 75527 0.0 1934 1521474 0.0 

1868 83919 0.0 1935 1654494 0.0 

1869 92311 0.0 1936 1791540 0.0 

1870 100703 0.0 1937 2039231 0.0 

1871 109095 0.0 1938 1988041 0.0 

1872 117487 0.0 1939 2086160 0.0 

1873 125879 0.0 1940 2149821 0.0 

1874 134271 0.0 1941 2220657 0.0 

1875 142663 0.0 1942 2093100 0.0 

1876 151054 0.6 1943 2256637 0.0 

1877 159446 0.0 1944 2592289 0.0 

1878 167838 0.0 1945 2594697 0.0 

1879 176230 0.0 1946 2745430 0.0 

1880 184622 0.0 1947 3022139 0.0 

1881 193014 0.0 1948 3433234 0.0 

1882 201406 0.0 1949 3404142 0.0 

1883 209798 0.0 1950 3803027 0.0 

1884 218190 0.0 1951 4282730 0.0 

1885 226582 0.0 1952 4531114 12.9 

1886 234973 0.0 1953 4798055 31.8 

1887 243365 0.0 1954 5016591 50.7 

1888 251757 0.0 1955 5625659 69.6 

1889 260149 0.0 1956 6124676 88.5 

1890 268541 0.0 1957 6438444 107.4 

1891 276933 0.0 1958 6607750 126.3 

1892 285325 0.0 1959 7144860 145.2 

1893 293717 0.0 1960 7674460 164.1 

1894 302109 0.0 1961 8186213 182.9 

1895 310501 0.0 1962 8882710 201.8 

1896 318892 0.0 1963 9540492 220.7 

1897 327284 0.0 1964 10312512 239.6 

1898 335676 0.0 1965 11063254 258.5 

1899 344068 0.0 1966 12021786 277.4 

1900 352460 0.0 1967 12914340 296.3 

1901 360852 0.0 1968 14146318 315.2 

1902 369244 0.0 1969 15222511 334.1 

1903 377636 0.0 1970 16718708 353.0 

1904 386028 0.0 1971 17662793 371.8 

1905 394420 0.0 1972 18600745 390.7 

1906 402811 0.0 1973 20367981 409.6 

1907 411203 0.0 1974 20537727 428.5 

1908 419595 0.0 1975 19502335 447.4 

1909 427987 0.0 1976 20960454 466.3 

1910 436379 0.0 1977 21900695 485.2 

1911 444771 0.0 1978 22158251 504.1 

1912 453163 0.0 1979 22876935 515.4 523.0 

1913 461555 0.0 1980 21760880 541.9 

1914 469947 0.0 1981 20376699 537.4 560.7 

1915 478339 0.0 1982 19412160 573.9 579.6 

1916 486730 0.0 1983 19347559 623.3 598.5 

1917 495122 0.0 1984 19857650 639.0 617.4 

1918 503515 0.0 1985 19584920 652.5 636.3 

1919 555875 0.0 1986 20492117 636.3 655.2 

1920 688884 0.0 1987 20562071 701.8 674.1 

1921 766002 0.0 1988 21369982 678.1 693.0 

1922 858898 0.0 1989 21920463 689.8 711.9 

1923 1015736 0.0 1990 22071915 733.1 730.8 

1924 1014318 0.0 

Table 5. Estimated worldwide minimum flared and vented gas 

(FVGmin) and cumulative minimum flared and vented gas 

(CFVGmin) volumes. 

[Tcf, trillion cubic feet; NA, not applicable] 

Year FYGmin CFVGmin Year FVGmin CFVGmin 

(Tel) (Tel) (Tel) (Tel) 

1858 0.0 0.0 1925 0.0 0.0 

1859 0.0 0.0 1926 0.0 0.0 

1860 0.0 0.0 1927 0.0 0.0 

1861 0.0 0.0 1928 0.0 0.0 

1862 0.0 0.0 1929 0.0 0.0 

1863 0.0 0.0 1930 0.0 0.0 

1864 0.0 0.0 1931 0.0 0.0 

1865 0.0 0.0 1932 0.0 0.0 

1866 0.0 0.0 1933 0.0 0.0 

1867 0.0 0.0 1934 0.0 0.0 

1868 0.0 0.0 1935 0.0 0.0 

1869 0.0 0.0 1936 0.0 0.0 

1870 0.0 0.0 1937 0.0 0.0 

1871 0.0 0.0 1938 0.0 0.0 

1872 0.0 0.0 1939 0.0 0.0 

1873 0.0 0.0 1940 0.0 0.0 

1874 0.0 0.0 1941 0.0 0.0 

1875 0.0 0.0 1942 0.0 0.0 

1876 0.0 0.0 1943 0.0 0.0 

1877 0.0 0.0 1944 0.0 0.0 

1878 0.0 0.0 1945 0.0 0.0 

1879 0.0 0.0 1946 0.0 0.0 

1880 0.0 0.0 1947 0.0 0.0 

1881 0.0 0.0 1948 0.0 0.0 

1882 0.0 0.0 1949 0.0 0.0 

1883 0.0 0.0 1950 0.0 0.0 

1884 0.0 0.0 1951 0.0 0.0 

1885 0.0 0.0 1952 0.1 0.1 

1886 0.0 0.0 1953 0.2 0.2 

1887 0.0 0.0 1954 0.3 0.5 

1888 0.0 0.0 1955 0.4 0.9 

1889 0.0 0.0 1956 0.5 1.4 

1890 0.0 0.0 1957 0.7 2.1 

1891 0.0 0.0 1958 0.8 2.9 

1892 0.0 0.0 1959 1.0 4.0 

1893 0.0 0.0 1960 1.3 5.2 

1894 0.0 0.0 1961 1.5 6.7 

1895 0.0 0.0 1962 1.8 8.5 

1896 0.0 0.0 1963 2.1 10.6 

1897 0.0 0.0 1964 2.5 13.1 

1898 0.0 0.0 1965 2.9 15.9 

1899 0.0 0.0 1966 3.3 19.3 

1900 0.0 0.0 1967 3.8 23.1 

1901 0.0 0.0 1968 4.5 27.6 

1902 0.0 0.0 1969 5.1 32.7 

1903 0.0 0.0 1970 5.9 38.6 

1904 0.0 0.0 1971 6.6 45.1 

1905 0.0 0.0 1972 7.3 52.4 

1906 0.0 0.0 1973 8.3 60.7 

1907 0.0 0.0 1974 8.8 69.5 

1908 0.0 0.0 1975 8.7 78.3 

1909 0.0 0.0 1976 9.8 88.0 

1910 0.0 0.0 1977 10.6 98.7 

1911 0.0 0.0 1978 11.1 109.7 

1912 0.0 0.0 1979 7.8 117.5 

1913 0.0 0.0 1980 3.8 121.3 

1914 0.0 0.0 1981 3.3 * 124.6 

1915 0.0 0.0 1982 3.3 * 127.9 

1916 0.0 0.0 1983 3.8 * 131.7 

1917 0.0 0.0 1984 3.5 * 135.2 

1918 0.0 0.0 1985 3.1 * 138.3 

1919 0.0 0.0 1986 3.0 * 141.3 

1920 0.0 0.0 1987 2.9 * 144.2 

1921 0.0 0.0 1988 3.2 * 147.4 

1922 0.0 0.0 1989 3.4 * 150.8 

1923 0.0 0.0 1990 3.3 * 154.1 

1924 0.0 0.0 Total 154.1 NA 

*Indicates recorded volume (Energy Information Administration). 
658 THE FUTURE OF ENERGY GASES 

Table 6. Estimated worldwide maximum flared and vented gas 

(FVGmax) and cumulative maximum flared and vented gas 

(CFVGmax) volumes. 

[Tcf, trillion cubic feet; NA, not applicable] 

Year 

1858 

1859 

1860 

1861 

1862 

1863 

1864 

1865 

1866 

1867 

1868 

1869 

1870 

1871 

1872 

1873 

1874 

1875 

1876 

1877 

1878 

1879 

1880 

1881 

1882 

1883 

1884 

1885 

1886 

1887 

1888 

1889 

1890 

1891 

1892 

1893 

1894 

1895 

1896 

1897 

1898 

1899 

1900 

1901 

1902 

1903 

1904 

1905 

1906 

1907 

1908 

1909 

1910 

1911 

1912 

1913 

1914 

1915 

1916 

1917 

1918 

1919 

1920 

1921 

1922 

1923 

1924 

FVGmax 

(Tel) 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.0 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.1 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.2 

0.3 

0.3 

0.3 

0.3 

0.4 

0.4 

0.4 

0.5 

0.5 

CFVGmax 

(Tel) 

0.0 

0.0 

0.0 

0.0 

0.0 

0.1 

0.1 

0.1 

0.2 

0.2 

0.2 

0.3 

0.3 

0.4 

0.5 

0.5 

0.6 

0.7 

0.7 

0.8 

0.9 

1.0 

1.1 

1.2 

1.3 

1.4 

1.5 

1.6 

1.8 

1.9 

2.0 

2.1 

2.3 

2.4 

2.6 

2.7 

2.9 

3.0 

3.2 

3.4 

3.5 

3.7 

3.9 

4.1 

4.3 

4.5 

4.7 

4.9 

5.1 

5.3 

5.5 

5.7 

6.0 

6.2 

6.4 

6.7 

6.9 

7.1 

7.4 

7.7 

7.9 

8.2 

8.6 

9.0 

9.4 

9.9 

10.4 

Year 

1925 

1926 

1927 

1928 

1929 

1930 

1931 

1932 

1933 

1934 

1935 

1936 

1937 

1938 

1939 

1940 

1941 

1942 

1943 

1944 

1945 

1946 

1947 

1948 

1949 

1950 

1951 

1952 

1953 

1954 

1955 

1956 

1957 

1958 

1959 

1960 

1961 

1962 

1963 

1964 

1965 

1966 

1967 

1968 

1969 

1970 

1971 

1972 

1973 

1974 

1975 

1976 

1977 

1978 

1979 

1980 

1981 

1982 

1983 

1984 

1985 

1986 

1987 

1988 

1989 

1990 

Total 

FVGmax 

(Tcf) 

0.6 

0.6 

0.7 

0.7 

0.8 

0.7 

0.7 

0.7 

0.7 

0.8 

0.9 

0.9 

1.1 

1.0 

1.1 

1.1 

1.1 

1.1 

1.2 

1.3 

1.3 

1.4 

1.6 

1.8 

1.8 

2.0 

2.2 

2.3 

2.5 

2.6 

2.9 

3.2 

3.3 

3.4 

3.7 

4.0 

4.2 

4.6 

4.9 

5.3 

5.7 

6.2 

6.7 

7.3 

7.8 

8.6 

9.1 

9.6 

10.5 

10.6 

10.1 

10.8 

11.3 

11.3 

7.8 

3.8 

3.3 * 

3.3 * 

3.8* 

3.5 * 

3.1 * 

3.0 * 

2.9 * 

3.2 * 

3.4 * 

3.3 * 

256.8 

*Indicates recorded volume (Energy Information Administration). 

CFVGmax 

(Tcf) 

11.0 

11.6 

12.2 

12.9 

13.7 

14.4 

15.1 

15.8 

16.5 

17.3 

18.1 

19.1 

20.1 

21.1 

22.2 

23.3 

24.5 

25.5 

26.7 

28.0 

29.4 

30.8 

32.4 

34.1 

35.9 

37.8 

40.0 

42.4 

44.9 

47.4 

50.3 

53.5 

56.8 

60.2 

63.9 

67.9 

72.1 

76.7 

81.6 

86.9 

92.6 

98.8 

105.4 

112.7 

120.6 

129.2 

138.3 

147.9 

158.4 

169.0 

179.0 

189.8 

201.1 

212.4 

220.2 

224.0 

227.3 

230.6 

234.4 

237.9 

241.0 

244.0 

246.9 

250.1 

253.5 

256.8 

NA 

We assumed two boundary conditions. Gas/oil ratios 

prior to 1979 were certainly less than the 1979 value of 

515 cu ftlbbl, which was considered to be a maximum 

value for the years before 1979. To estimate minimum values for the gas/oil ratios prior to 1979, we used the regression equation for the years 1978 to 1953, when the gas/oil 

ratio approaches zero. These minimum and maximum values for the gas/oil ratio yield estimates of worldwide total 

volumes of between 154 and 257 Tcf of associated-dissolved gas flared or vented since oil was first produced 

(tables 4, 5, and 6). Because petroleum production has increased dramatically since the 1940's, the bulk of worldwide flared and vented gas has occurred in the last 50 

years. It must again be emphasized that these values are 

estimates based on the extrapolation of recent data and 

should be used with caution. 

CONCLUSION 

Despite the inconsistency and inavailability of data, 

the extrapolation method outlined here provides a reliable 

technique for estimating amounts of natural gas flared and 

vented through time. Figures 6 and 7 compare the calculated and documented volumes of flared and vented gas 

for Saudi Arabia and Nigeria. The correlations between 

the calculated and actual volumes of flared and vented gas 

are excellent (?=0.93 and 0.98 for Saudi Arabia and Nigeria, respectively). This method of estimation can provide 

-:0 

.c 

-

= 

800 

700 

600 

500 

:J 400 () 

-

a: 300 

0 

Cl 200 

100 

0 

• • • 

• ••• •••• 

1975 1980 1985 1990 1995 

Year 

Figure 5. Actual gas/oil ratios (GOR), in cubic feet per barrel 

(cu ftlbbl), calculated from associated-dissolved gas and oil 

production data through time for the world. The regression 

equation is GOR (cu ft/bbl)=-36861+(19 X year), having a 

correlation of r 2

=0.92. 
METHODOLOGY FOR ESTIMATING VOLUMES OF FLARED AND VENTED NATURAL GAS 659 

information where data are sparse or poor. In addition, this 

extrapolation method can be used to provide gross estimates of regional and worldwide volumes of gas flared 

and vented. However, this method should be used with 

caution owing to the variability of production practices 

among different countries and regions. 

1400 

-... • ·--= ~ 1200 -

u • 

m 

- 1000 • 

en • 

aJ • 

G 800 

"C •• 

(I) 600 •• ... 

aJ 

u:: 400 • 

aJ I :::::J 200 • -

u I <( • 

0 

0 500 1000 1500 2000 

Calculated Flared Gas (Bcf/yr) 

Figure 6. Actual (Organization of the Petroleum Exporting 

Countries, 1993) versus calculated volumes of flared and 

vented gas, in billion cubic feet per year (Bcf/yr), for Saudi 

Arabia. 

1200 

-... 

> - 1000 -0 

m 

• 

• -

en 800 

aJ 

G 

"C 600 

.J 

• (I) 

... 

aJ 

u::: 400 .IL 

aJ • :::::J 200 -

u • <( 

0 

0 500 1000 1500 

Calculated Flared Gas (Bcf/yr) 

Figure 7. Actual (Organization of the Petroleum Exporting 

Countries, 1993) versus calculated volumes of flared and 

vented gas, in billion cubic feet per year (Bcf/yr), for Nigeria. 

REFERENCES CITED 

Arabian American Oil Company, 1968, ARAMCO HandbookOil and the Middle East: Dhahran, Saudi Arabia, Arabian 

American Oil Company, 279 p. 

DeGolyer and MacNaughton, 1990, Twentieth Century Petroleum Statistics: Dallas, Texas, DeGolyer and MacNaughton, 

126 p. 

Energy Information Administration, 1980, International Energy 

Annual: 1979: United States Department of Energy, Energy 

Information Administration Report DOE/EIA-0219(79), 

Washington, D.C., 93 p. 

Energy Information Administration, 1981, International Energy 

Annual: 1980: United States Department of Energy, Energy 

Information Administration Report DOE/EIA-0219(80), 

Washington, D.C., 110 p . 

Energy Information Administration, 1983, International Energy 

Annual: 1982: United States Department of Energy, Energy 

Information Administration Report DOE/EIA-0219(82), 

Washington, D.C., 108 p. 

Energy Information Administration, 1984, International Energy 

Annual: 1983: United States Department of Energy, Energy 

Information Administration Report DOE/EIA-0219(83), 

Washington, D.C., 114 p. 

Energy Information Administration, 1985, International Energy 

Annual: 1984: United States Department of Energy, Energy 

Information Administration Report DOE/EIA-0219(84), 

Washington, D.C., 123 p. 

Energy Information Administration, 1986, International Energy 

Annual: 1985: United States Department of Energy, Energy 

Information Administration Report DOE/ElA-0219(85), 

Washington, D.C., 129 p. · 

Energy Information Administration, 1987, International Energy 

Annual: 1986: United States Department of Energy, Energy 

Information Administration Report DOE/EIA-0219(86), 

Washington, D.C., 135 p. 

Energy Information Administration, 1988, International Energy 

Annual: 1987: United States Department of Energy, Energy 

Information Administration Report DOE/EIA-0219(87), 

Washington, D.C., 141 p. 

Energy Information Administration, 1989, International Energy 

Annual: 1988: United States Department of Energy, Energy 

Information Administration Report DOE/EIA-0219(88), 

Washington, D.C., 185 p . 

Energy Information Administration, 1991, International Energy 

Annual: 1989: United States Department of Energy, Energy 

Information Administration Report DOE/EIA-0219(89), 

Washington, D.C., 193 p . 

Energy Information Administration, 1992, International Energy 

Annual: 1990: United States Department of Energy, Energy 

Information Administration Report DOE/EIA-0219(90), 

Washington, D.C., 187 p. 

Energy Information Administration, 1992, International Energy 

Annual: 1991: United States Department of Energy, Energy 

Information Administration Report DOE/EIA-0219(91), 

Washington, D.C., 183 p. 

Hansen Planetarium, 1986, Earth at night [poster]: Salt Lake 

City, Utah, Hansen Planetarium. 
660 THE FUTURE OF ENERGY GASES 

International Petroleum Encyclopedia 1968: Tulsa, Oklahoma, 

The Petroleum Publishing Company, 424 p. 

International Petroleum Encyclopedia 1969: Tulsa, Oklahoma, 

The Petroleum Publishing Company, 400 p. 

International Petroleum Encyclopedia 1973: Tulsa, Oklahoma, 

The Petroleum Publishing Company, 440 p. 

International Petroleum Encyclopedia 1974: Tulsa, Oklahoma, 

The Petroleum Publishing Company, 468 p. 

International Petroleum Encyclopedia 1975: Tulsa, Oklahoma, 

The Petroleum Publishing Company, 480 p. 

International Petroleum Encyclopedia 1976: Tulsa, Oklahoma, 

The Petroleum Publishing Company, 456 p. 

International Petroleum Encyclopedia 1977: Tulsa, Oklahoma, 

The Petroleum Publishing Company, 478 p. 

International Petroleum Encyclopedia 1978: Tulsa, Oklahoma, 

The Petroleum Publishing Company, 446 p. 

International Petroleum Encyclopedia 1979: Tulsa, Oklahoma, 

The Petroleum Publishing Company, 470 p. 

International Petroleum Encyclopedia 1980: Tulsa, Oklahoma, 

Penn Well Publishing Company, 464 p. 

International Petroleum Encyclopedia 1981, Volume 14: Tulsa, 

Oklahoma, The Petroleum Publishing Company, 452 p. 

International Petroleum Encyclopedia 1982, Volume 15: Tulsa, 

Oklahoma, The Petroleum Publishing Company, 464 p. 

International Petroleum Encyclopedia 1983, Volume 16: Tulsa, 

Oklahoma, The Petroleum Publishing Company, 418 p. 

International Petroleum Encyclopedia 1984, Volume 17: Tulsa, 

Oklahoma, The Petroleum Publishing Company, 410 p. 

International Petroleum Encyclopedia 1985, Volume 18: Tulsa, 

Oklahoma, The Petroleum Publishing Company, 394 p. 

International Petroleum Encyclopedia 1986, Volume 19: Tulsa, 

Oklahoma, The Petroleum Publishing Company, 408 p. 

International Petroleum Encyclopedia 1987, Volume 20: Tulsa, 

Oklahoma, The Petroleum Publishing Company, 388 p. 

International Petroleum Encyclopedia 1988, Volume 21: Tulsa, 

Oklahoma, The Petroleum Publishing Company, 388 p. 

International Petroleum Encyclopedia 1992, Volume 25: 

Tulsa, Oklahoma, The Petroleum Publishing Company, 

358 p. 

Organization of the Petroleum Exporting Countries, 1993, Natural gas flared in Saudi Arabia and Nigeria, 1963-1991: unpublished data. 

Schatz!, L. H., 1969, Petroleum in Nigeria: lbadan, Nigeria, Oxford University Press, 257 p. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Energy Gases-The Methane Age and Beyond 

By Nebojsa Nakicenovic 1 

CONTENTS 

Abstract . ... ..... .. .. .. .. .... ............... ...... ... . ........ .......... ... ... . .. 661 

From Resource Scarcity to Decarbonization ...... .. .. ..... 662 

Energy Intensity and Decarbonization .... .................. ... 663 

Carbon Dioxide Mitigation .......................................... 667 

Methane as an Energy Gas of Choice ...... .... ...... .. ........ 668 

Energy Scenarios and Decarbonization ....................... 670 

Methane and Carbon Dioxide Emissions ..................... 671 

Methane Economy as a Bridge to Hydrogen ............... 672 

Conclusion .................................................................... 674 

References Cited ........................................................... 675 

ABSTRACT 

The combustion of fossil fuels results in the emissions 

of gases and pollutants that produce adverse ecological effects. Evidence is also accumulating that suggests they 

may also cause global climate change. The combustion 

gases that are connected with global climate change are 

primarily carbon dioxide (C02) and to a lesser degree 

methane (CH4) (see Cole, this volume). All of these gases 

already occur in low concentrations in the atmosphere and, 

in fact, together with other greenhouse gases, such as 

water vapor, have made the earth habitable. The risk, however, is that the additional emissions of greenhouse gases 

associated with energy use and other human activities are 

rapidly increasing the atmospheric concentrations of these 

gases and may therefore lead to additional global warming 

1

Environmentally Compatible Energy Strategies Project, International Institute for Applied Systems Analysis, A-2361 Laxenburg, Austria; telephone no. (+43-2236) 71521-0; telefax no. (+43-2236) 71313. 

during the next century. Although the greenhouse gases 

that result from energy use are the most important cause 

of these concerns, the energy gases also offer a potential 

solution to this problem. 

Natural gas consists mostly of methane and is a very 

potent greenhouse gas if released into the atmosphere; 

however, after combustion occurs, the amount of resulting 

carbon dioxide is much smaller per unit primary energy in 

comparison to other fossil energy sources. Natural gas 

emits roughly one-half of the carbon dioxide in comparison to coal for an equal amount of energy. Thus, a possible shift to a methane economy during the next decades 

offers a genuine mitigation strategy. Beyond that, natural 

gas could pave the way for more environmentally compatible energy systems in distant future that could use hydrogen and electricity, both of which are carbon-free energy 

carriers, that could be produced by nonfossil sources of 

primary energy. This transition to the "methane age" and 

beyond to carbon-free energy systems would enhance the 

reduction of other adverse impacts on the environment by 

human activities. 

In fact, carbon dioxide emissions represent the largest 

mass flow of waste into the environment in comparison to 

wastes from all other anthropogenic activities. Current energy-related carbon dioxide emissions are on the order of 

6 gigatons of carbon (GtC) or more than 20 GtCOz per 

year. This is more .than 20 times larger than, for example, 

annual global steel production of about 700 megatons 

(Mt). Decarbonization is a notion that denotes reduction of 

carbon dioxide emissions per unit primary energy and per 

unit economic activity, and dematerialization refers to the 

reduction of materials used per unit economic activity. Decarbonization would also help reduce the emission of 

other energy pollutants and wastes, and it would also enhance the dematerialization in general. Other measures 

that would lead to decarbonization, in addition to a shift to 

a methane economy, include efficiency improvements and 

661 
662 THE FUTURE OF ENERGY GASES 

energy conservation, carbon removal and storage, or a 

shift to carbon-free sources of energy, such as solar and 

nuclear energy. 

FROM RESOURCE SCARCITY 

TO DECARBONIZATION 

In the aftermath of the so-called energy crisis of the 

early 1970's, a number of studies have been conducted to 

assess long-term national and global energy prospects. In 

the wake of increasing energy prices and serious supply 

shortages, most of these studies focused on securing the 

long-term supply. Often these studies resulted in calls for 

commercializing large amounts of nonconventional fossil 

energy resources, such as oil shales, and promoting nuclear power and fusion. A number of studies also considered 

renewable energy sources and solar energy as additional 

strategies for enhancing the supply of energy in the long 

run. In any case, the paradigm of oil shortage and depletion of conventional fossil energy resources predominated. 

As the sophistication of methodological approaches 

for analyzing energy futures increased, research also shifted to the questions of improving efficiency, end use of en-

.!!!5 

·a. 

~4 

c33 

"' c 

~ 2 Bio 

Gas 

Oil 

0 

ergy, and enhancing conservation. The studies became 

more balanced in treating supply and demand. Today, the 

predominate question is how to reduce the adverse impacts of energy use in the world, while allowing for sufficient increase of energy services in the developing 

countries. This is a formidable task considering that global 

population is expected to double during the next century 

and that 80 percent of humanity shares less than 20 percent of global wealth. At the same time, it is becoming 

increasingly evident that fossil energy resources are much 

more abundant than it was anticipated in the 1970's and 

early 1980's. Both resources and reserve bases of oil and 

natural gas have increased and, in fact, new natural gas 

discoveries have outpaced oil. The absolute finiteness of 

energy resources does not appear to be a problem facing 

humanity in the next few hundred years. The question is 

rather how to utilize the available energy resources in supplying adequate services, while arresting the further environmental degradation and global warming. 

This dilemma of the need to increase energy services 

and reduce the adverse impacts of energy-use is illustrated 

in figure 1. It shows per capita emissions of the greenhouse gases carbon dioxide and methane for the major 

world regions. 

~ 

Figure 1. C02 and CH4 greenhouse-gas emissions per capita versus population for different world regions and by energy 

source in 1988. Height of bars gives carbon dioxide and methane emissions per capita in tons of carbon equivalent, and 

width of bars shows regional population. Four main sources of the greenhouse gas emissions are shown: carbon dioxide 

emissions resulting from (1) coal, (2) oil, and (3) natural gas consumption, and (4) the combined carbon dioxide emissions 

of all nonfossil energy sources, such as biomass burning, and also all of the anthropogenic methane sources, both energy 

and nonenergy. (I kg CH4=21 kg C02). Ce=total greenhouse-gas emissions in tons of carbon. 
ENERGY GASES-THE METHANE AGE AND BEYOND 663 

The combined carbon dioxide and methane emissions 

are clearly the highest in the industrialized countries, reaching 6 tons of carbon (tC) equivalent per capita in North 

America and Australia and not much lower in some parts of 

Eastern Europe and the former Soviet Union. For example, 

the eastern states of Germany that constituted the former 

German Democratic Republic had almost the same per capita carbon dioxide emissions as the United States, but had a 

much lower standard of living and energy services. This 

was due to the high degree of inefficiency of the energy 

systems, a very high share of coal in the energy mix, and a 

high level of material use per unit economic activity in 

general. A similar situation still exists in the economies of 

Eastern Europe, Russia, and the other Commonwealth 

(former Soviet) Republics. 

In contrast to the energy-intensive economies of Eastern Europe, Japan and Western European countries 

achieve much higher levels of economic activities with 

substantially lower per capita energy consumption and 

greenhouse gas emissions. The standard of living in most 

of the Western European countries is comparable to that of 

the United States, however, the emissions of greenhouse 

gases are half as large in Western Europe. In the more 

efficient industrial countries of Western Europe and Japan, 

emissions are on the order of 3 tC equivalent per capita, 

whereas they are twice that amount in North America. 

These regions constitute about 20 percent of the world 

population today. 

The other 80 percent of the world population accounts 

for only 20 percent of the global carbon dioxide and methane emissions. Figure 1 clearly shows this disparity in the 

emissions levels. For example, China, with one billion people, has combined carbon dioxide and methane emissions 

that barely exceed 1 tC per capita. It is also of interest to 

observe that the structure of the emissions is different in 

most developing countries in comparison to the industrialized countries. Using China again for an example, we see 

that most of the emissions are due to coal consumption, 

nonfossil carbon dioxide, and methane emissions, indicating low shares of oil and natural gas in the primary energy 

mix. As the developing countries continue to grow: the total 

emissions will increase, and if the development process 

continues, per capita emissions will most likely also increase. The current plans in India and China are to expand 

coal production and use, with emissions reaching perhaps 

3 Gt in a few decades. This source of carbon dioxide alone 

would represent half of the current total emissions. Therefore, it is quite apparent that economic and social development in the world are strong determinants of future 

greenhouse gas emissions. The potential risks of climate 

change, on the other hand, suggest a need to slow down the 

growth of emissions and even decrease them in the next 

century. There is a need to reconcile this opening gap between the energy needs for development and reduction of 

emissions as a precaution to guard against global warming. 

ENERGY INTENSITY AND 

DECARBONIZATION 

Global emissions will continue to increase along with 

further economic development and population growth in 

the world. The most important determinants of future energy-related carbon dioxide emissions could be represented as products of the following factors: (1) population 

growth, (2) per capita value added, (3) energy per value 

added, ( 4) carbon emissions per energy on one side, and 

(5) total carbon dioxide emissions on the other side of the 

identity (Yamaji and others, 1991 ). Two of these factors 

are increasing and two are declining at the global level. 

[C02=(C02/E)x(E/GDP)x(GDP/P)xP, where E represents 

energy consumption, GDP the gross domestic product or 

value added, and P population. Changes in C02 emissions 

can be described by changes in these four factors.] 

At present, the world's global population is increasing 

at a rate of about 2 percent per year. The longer-term historical growth rates since 1800 have been about 1 percent 

per year. Most population projections expect at least another doubling during the next century; for example, the 

World Bank (Vu, 1985) and United Nations (1991) projections. Productivity has been increasing in excess of global 

population growth since the beginning of industrialization 

and thus has resulted in more economic activity and value 

added per capita. In contrast, energy intensity per unit 

value added has been decreasing at a rate of about 1 percent per year since the 1860's and at about 2 percent per 

year in most countries since the 1970's. Carbon dioxide 

emissions per unit of energy have also been decreasing but 

at a much lower rate, about 0.3 percent per year. 

Figure 2 shows the extent of global decarbonization of 

energy since 1900, as the change in the ratio of average 

carbon dioxide emissions per unit of energy consumed. Decarbonization occurred owing to the gradual replacement of 

carbon-rich sources of energy by carbon-poorer sources of 

energy. First, wood and coal were replaced by oil and later 

by natural gas and more recently, to a lesser degree, by 

nuclear energy. Figure 2 also illustrates decarbonization 

rates implicit in a number of global energy scenarios. For 

example, the United States Environment Protection Agency's (EPA) Rapidly Changing World (RCW) scenario actually anticipates an increase of carbon intensity in the world 

and thus a reversal of the historical development trend (Environment Protection Agency, 1990). This is primarily due 

to a heavy reliance on coal in this scenario. The Intergovernmental Panel on Climate Change (IPCC) has developed 

a whole range of scenarios; the median one is shown in 

figure 2 and anticipates continuation of the current level of 

carbon emissions per unit energy consumed in the world 

(Intergovernmental Panel on Climate Change, 1992). The 

Environmentally Compatible Scenario (ECS'92) developed 

at International Institute for Applied Systems Analysis 

(IIASA) in 1992 (Nakicenovic and others, 1993) and the 
664 THE FUTURE OF ENERGY GASES 

-.... 

~ .1!: 

0 (...) 

II) 

- Q) 

c: c: :::::J c: .... 

Q) g a. "C II) Q) c: 

0 E 

·u; :::::J 

II) II) 

.E c: 

0 Q) (.) 

c: >. 

Cl 0 Cii -e c: ra Q) (...) 

~ ra 

E 

c. 

0.8 

0.7 

0.6 

0.5 

0.4 

0.3 

1900 1920 1940 1960 

Year 

ECS '92 

and WEC 

.. Methane/zero " .. .. carbon economy ", 

1980 2000 2020 2040 ' 

Figure 2. Global decarbonization of energy since 1900 and scenarios for the future in tonnes of 

carbon per kilowatt year (tC!kWyr) of energy. Four future scenarios are shown: (1) Environmental 

Protection Agency's (EPA) Rapidly Changing World scenario, (2) the Intergovernmental Panel on 

Climate Change (IPCC) Energy and Industry Subgroup's median scenario, and (3) the International Institute for Applied Systems Analysis (IIASA) Environmentally Compatible Scenario '92, as 

well as (4) the World Energy Council's (WEC) reference scenario, which has essentially the same 

carbon intensity of energy as ECS '92. The lower dashed line shows the further reduced emissions of a methane/zero-carbon economy. 

World Energy Council scenario (World Energy Council, 

1992) represent a continuation of the historical trends and 

thus a certain degree of decarbonization in the future. The 

lower dashed line with the arrow into the future in figure 2 

symbolizes the need to achieve even higher rates of decarbonization in order to offset future population and economic growth in the world. A scenario that relies on the higher 

contribution of energy gases in primary energy consumption could achieve this goal, and such a scenario will be 

described in this paper. To stabilize energy-related carbon 

emissions at current annual levels of almost 6 GtC for a 

primary energy demand between 15 and 18 terawatt years 

(TWyr) by the year 2020 (compared to 12 TWyr in 1992), 

the rate of decarbonization would have to range from 0.8 to 

1.4 percent per year (two to four times the annual rates 

achieved in the past). 

In addition to energy decarbonization, one must also 

consider the reduction of energy intensity in economic activities as a second factor that is also causing a decrease in 

the carbon dioxide emissions mentioned above. Figure 3 

shows the historical decrease in energy intensity per unit 

value added in a number of countries. Energy development 

paths in different countries have varied enormously and 

consistently over long periods, but the overall tendency is 

toward lower energy intensities. For example, France and 

Japan have always used energy more efficiently than the 

United States, the United Kingdom, or Germany. This 

should be contrasted with the opposite development in 

some of the rapidly industrializing countries, where commercial energy intensity is still increasing, such as in Nigeria. The present energy intensity of Thailand resembles the 

situation in the United States in the late 1940's. The energy 

intensity of India and its present improvement rates are 

similar to those of the United States about a century ago. 

The reforming countries of Eastern Europe and the former 

Soviet Union have relatively high energy intensities, between those of the United States (lower) and India (higher). 

Figure 4 shows the decarbonization and energy deintensification achieved in a number of countries since the 

1870's. It illustrates salient differences .in the policies and 

structures of energy systems among countries. For example, Japan and France have achieved the highest levels of 

decarbonization; in Japan this has been achieved largely 

through energy-efficiency improvements over recent decades, while in France largely through vigorous substitution of fossil fuels by nuclear energy. Most countries have 

achieved decarbonization through the replacement of coal, 

first by oil and later by natural gas. 

At the global level, the long-term reduction in carbon 

intensity of value added has been about 1.3 percent per 
>-

t:: 

·~ w 

1--

z 

>-

C) 

a: 

w 

z 

w 

C) 

z 

(jj 

<( 

w 

a: 

() 

w 

0 

a_ 

0 

C) 

Uj 

co 

ENERGY GASES-THE METHANE AGE AND BEYOND 

(/) 

2.4 

2.2 

ca 2.0 

0 

"0 

0 

co 

Q) 

c 

cL 

0 

C) 

-c 

ro 

en 

c 

0 

0 

...... 

Q) 

0.. 

...... 

1.8 

1.6 

1.4 

1.2 

1.0 

0.8 

0.6 

>. 

~ 0.4 

Wyrj$1980 

0. 2 • Primary electricity accounted as 

1 Wyr = 8. 76 kwh (equivalence method) 

1860 1880 1900 

2.4-3.0 

China 

••• Thailand 

·· ... 

1920 1940 1960 1980 2000 

Year 

Figure 3. Primary energy intensity, including biomass, of value added in kilowatt year (Wyr) per constant 

gross domestic product (GOP) in 1980 dollars. Primary electricity is accounted as I Wyr=8.76 kWh 

(equivalence method). 

2.0 

1.5 

* 1870 

c 1913 

• 1950 

• 1970 

' 1988 

;CHINA 

:1988.2.77/0.93 

UK 

* ; INDIA 

;USA 

: 1820-2.47/1.27 

USA 

1850 

665 

~ 1.0 

Figure 4. Global decarbonization and 

deintensification of energy in kilograms of carbon per kilogram of oil 

equivalent (kgC/kgoe), and in kgoe 

per $1 ,000 gross domestic product 

(GOP) (Griibler, 1991 ). 

{fi 

(J) 

~ 

(jj 

0 

Ol 

~ 0.5 

0.0 

.. --- FRANCE I 

0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 

kg C/kgoe 

DECARBONIZATION OF ENERGY 
666 THE FUTURE OF ENERGY GASES 

year-decarbonization of energy occurs at about 0.3 percent per year and reduction of energy intensity of value 

added occurs at about 1 percent per year. This falls short 

of what is required to offset the effects of global economic 

growth of about 3 percent per year. This means that global 

carbon dioxide emissions have been increasing at about 

1.7 percent per year during most of this century. Today, 

global carbon dioxide emissions are still increasing at 

close to 2 percent per year, implying a doubling before the 

2030's, and this is in fact quite close to the emissions levels projected in some of the global scenarios. 

Figure 5 gives an overview of the major energy scenarios for the world. It shows the current energy-related 

carbon emissions of almost 6 GtC in 1990 and the anticipated increase of emissions during the next three decades. 

It shows the EPA's RCW scenario with highest emissions 

exceeding 10 GtC by 2020 (Environmental Protection 

Agency,. 1990). It shows again the Intergovernmental 

Panel on Climate Change (IPCC) midrange scenario with 

slightly lower emissions, although it should be mentioned 

that the lowest lPCC scenarios actually lead to a reduction 

of global emissions with respect to 1990 during the next 

the century (Intergovernmental Panel on Climate Change, 

1992). Figure 5 also shows the WEC reference scenario 

and the ECS'92 scenario from IIASA to be in the lower 

range of emissions (Nakicenovic and others, 1993). 

The shaded area represents what could be called "the 

consensus view" of future energy emissions. This range of 

emissions is based on assessments of the International Energy Workshop (lEW). Since 1981, Stanford University 

and IIASA have jointly organized a series of lEW Workshops with the aim of comparing energy projections made 

by different groups around the world and analyzing their 

differences (Manne and Schrattenholzer, 1992). The projections are analyzed on the basis of a standardized poll. 

The median response derived from the polls corresponds, 

in our interpretation, to the "consensus view" and reflects 

the "conventional wisdom" of the international energy 

community. These projections mostly describe surprisefree business-as-usual middle-of-the-road scenarios. 

According to the results of the most recent lEW poll 

(Manne and Schrattenholzer, 1992), today's projections 

anticipate a more modest growth of global primary energy 

consumption between now and the year 2020 than the 

long-term trend of 2 percent per year. The lEW median 

projection corresponds to an average annual growth rate of 

1.4 percent, which would lead to an absolute increase 

from 11.8 to 18 TWyr/yr. 

Together, the lEW comparisons of projections show 

that the energy community is anticipating a substantial increase in global carbon dioxide emissions during the next 

30 years-the median represents an increase of more than 

12 ,-----------------------------------------------, 

c 

0 

-e 10 eel 

u 

rJ) 

c 

.8 

c 

.Q 8 

[i) 

6 

ECS '92 

:<::·:·:·:·: lEW & range 

1990 2000 

IPCC IRS91a EPA- RCW 

2010 2020 

WEC REFERENCE CHALLENGE 

G2100 

Figure 5. Global primary energy consumption 1990-2020. Range of the International Institute 

for Applied Systems Analysis International Energy Workshop (IIASA lEW) projections, including the Environmental Protection Agency Rapidly Changing World (EPA RCW) scenario, 

the World Energy Council (WEC) reference scenario, the Intergovernmental Panel on Climate 

Change scenario (IPCC IRS9la), the International Institute for Applied Systems Analysis Environmentally Compatible Scenario (IIASA ECS'92), and the International Institute for Applied Systems Analysis (IIASA) Challenge G2100. See text for discussion of shaded areas. 
ENERGY GASES-THE METHANE AGE AND BEYOND 667 

30 percent. On the other hand, international assessments 

such as that by the IPCC clearly point to the need to reduce the emissions to the fullest extent possible. Furthermore, the Framework Convention on Climate Change that 

was signed by 153 countries at the Rio de Janiero Summit 

in 1992, to be ratified in the near future, calls for reduction of emissions as a precautionary principle toward 

arresting climate change (lntern'ational Negotiating Committee, 1992). 

CARBON DIOXIDE MITIGATION 

There are basically three courses of action to deal with 

carbon dioxide emissions: (1) mitigate the emissions in the 

future, (2) deal with the adverse impacts of climate change 

and compensate for incurred damages, and (3) adapt to climate change and learn to live in the warmer weather. All 

of these alternatives are surrounded by numerous uncertainties. Mitigation measures and options have been studied in greater detail than impacts and adaptation. In this 

paper, mitigation strategies that involve greater use of energy gas in the future with the intention of reducing emissions of greenhouse gases will be considered. For 

completeness, a brief overview of other mitigation options 

will be given. The technological and economic measures 

to minimize energy-related greenhouse gases emissions include efficiency improvements, conservation, enhanced 

use of low-carbon fuels, carbon-free sources of energy, 

and other options, such as afforestation, enhancement of 

natural carbon sinks, and the creation of new sinks. Thus, 

the mitigation strategies encompass the whole energy system from primary energy extraction to actual energy use, 

including various conversion, transport, distribution, and 

end-use systems. 

Four types of technological strategies can be distinguished for stabilizing and eventually also reducing energy-related carbon dioxide emissions. The first is an 

incremental one, emphasizing energy-efficiency improvements (see also Mills, this volume). In this case, devices 

or operational practices are replaced by more efficient 

ones without major changes in the technology of the device itself or technologies upstream in the energy supply 

chain. For example, this could mean replacing a refrigerator or a gas-fired power plant by a more efficient model, 

while using the same electricity and fuel supply chains. 

Three other strategies are more radical. They include 

changes in technological design and operational practices 

with and without changes in the energy chains. These are 

changes in technological "trajectories." In the simplest 

case, the end-use technology is changed but with the same 

upstream energy chain, for example, switching from a gasoline to a diesel car. Alternatively, the end use and conversion technologies may stay the same but the primary 

energy input changes, such as switching from an oil- to a 

gas-fired combined-cycle power plant. Finally, Jt JS possible to change the trajectories of end-use, conversion, and 

primary energy-supply technologies (in other words, the 

whole energy chain), such as switching from a gasoline 

car with oil as the primary energy source to an electric 

vehicle with photovoltaic panels. 

There is a clear ranking of the four different technological strategies with regard to costs (Nakicenovic and 

others, 1993). The incremental improvements have the 

lowest cost because they do not require changes in technological trajectories. These are also the easiest to implement 

and take the shortest time. They are followed by measures 

that involve a change in the primary energy source and 

those involving changes in end-use technologies. Generally, the most difficult and costly measures to implement 

will be those where both end-use and primary energy-supply technologies have to be changed. Here, changes are 

required in all related components of the energy system, 

meaning that entirely new energy chains have to be developed and built-new energy-supply systems, infrastructures, diffusion of new end-use devices, and delivery 

outlets. 

A similar conclusion also holds for carbon removal 

and disposal technologies. The more remote from the disposal site and diluted the source of emissions, the more 

difficult and expensive are the carbon control measures. 

Again, demand-side measures such as improved efficiency 

and emission avoidance are cheaper than post-combustion 

scrubbing of stack gases, which, in turn, is cheaper than 

carbon removal from the atmosphere by micro-algae carbon fixation or other technologies. From this perspective, 

it is not surprising that most assessments of mitigation options identify energy efficiency improvements and end-use 

demand-management measures among the most cost-effective measures, followed by fuel substitution. More traditional energy supply-side measures, or even extensive 

industrial and infrastructural restructuring measures, are 

generally more difficult to implement and are certainly 

also more expensive. 

In this paper, the implications of carbon dioxide and 

methane emissions from increasing reliance on combustion of natural gas in the future are considered. Although 

natural gas (mostly methane) results in lower specific carbon dioxide emissions than other fossil fuels, it has not 

been explored in detail as a mitigation strategy for arresting global warming. Often, reservations are expressed in 

connection to wider use of natural gas because methane is 

a potent greenhouse gas. We will demonstrate that a stronger reliance on natural gas in the future would lead to relatively modest increases in carbon dioxide emissions 

compared with scenarios that are based on more traditional mitigation strategies. We will also show that methane 

emissions do not pose a major problem provided that leakage rates could be maintained at least at levels of 4 percent of gas consumption or less in the future. 
668 THE FUTURE OF ENERGY GASES 

METHANE AS AN ENERGY GAS 

OF CHOICE 

A global scenario in which a major share of primary 

energy is natural gas is of interest for several reasons: (I) 

The historical replacement of coal by oil and later by natural gas indicates such a trend .. Primary energy substitution 

(Marchetti and Nakicenovic, 1979; Nakicenovic, 1990) 

suggests a likelihood that natural gas will become the 

major global source of energy during the next century. (2) 

New markets for natural gas appear to be opening because 

natural gas is more environmentally desirable than other 

fossil fuels. Methane has the highest hydrogen to carbon 

atomic ratio and the lowest carbon dioxide emissions of 

all fossil fuels. The historical transition from wood to coal 

to oil and to gas has resulted in gradual decarbonization of 

energy, or to an increasing hydrogen to carbon ratio of 

global energy consumption. Natural gas use is also highly 

desirable from a regional environment standpoint because 

of minimal sulfur dioxide and particulate emissions. (3) 

Recent assessments suggest that gas resources may be 

more abundant than was widely believed only a decade 

ago. New discoveries have outpaced consumption. Additionally, discoveries of gas hydrates and natural gas of ultradeep origin indicate truly vast occurrences of methane 

throughout Earth's crust (see Wyman; Gold; Kvenvolden; 

this volume). There is increasing evidence of multiple economic and geopolitical benefits from a worldwide shift to 

natural gas (Lee and others, 1988). 

Figure 6 shows primary energy substitution in the 

world. The competitive struggle between five main sources 

of primary energy is dynamic and quite regular so that it 

10 2 

101 

~~od ~ '-.~Coal 

can be described by relatively simple rules (Marchetti and 

Nakicenovic, 1979; Nakicenovic, 1979, 1986). The dynamics of this process are captured by logistic equations 

that describe the rise of new energy sources and the senescence of old ones. The substitution process clearly indicates the dominance of coal as the major energy source 

between the 1880's and 1960's after a long period during 

which fuel wood (and other traditional energy sources) 

were in the lead. The massive expansion of railroads, the 

growth of steel, steamships, and many other sectors are 

associated with and based on the technological opportunities offered by the mature coal economy. After the 1960's, 

oil assumed a dominant role simultaneously with the maturing of the automotive, petrochemical, and other modern 

industries. 

Figure 6 projects natural gas as the dominant source 

of energy during the first decades of the next century, although oil still maintains the second largest share until the 

2040's. For such an explorative "look" into the future, additional assumptions are required because potential new 

competitors, such as nuclear, solar, and other renewable 

energy sources have not yet captured sufficient market 

shares to allow estimation of their growth rates. To explore the behavior of the logistic substitution model when 

the competition between energy sources is extended into 

the future, we assume that nuclear energy would diffuse at 

comparable rates to oil and natural gas half a century earlier. This implies that the current share of nuclear energy 

in the world would be unchanged for a decade, when 

growth would resume but at a lower rate than in the past. 

Nevertheless, such a scenario would require a new generation of nuclear installations, and today prospects for such 

0.99 

0.90 

Natu~gas 0.70 !£ 

. "'-~ ~ / - c: 

0.50 0 

:-- ll 

~ 

1850 

L ....... ........ ../ ~/ ~ 

~ pY ~ 

~~ ~ 

LZ / 

/ / 

Oil A / 

1900 

~ 

~L 

Nuclea~ 

1950 

Year 

/ 

2000 

0.30 

~ / 

/<_ 0.10 

"'-., " ~/ 

Soli us~ 0.01 

2050 

e! 

LL 

Figure 6. Global primary energy substitution. Smooth lines represent model calculations and 

jagged lines are historical data. "Solfus" is a term employed to describe a major new energy technology, for example solar or fusion. 
ENERGY GASES-THE METHANE AGE AND BEYOND 669 

installations are at best questionable. This leaves natural 

gas with the lion's share in primary energy during the next 

50 years. In the past, new sources of energy have emerged 

from time to time, coinciding with the saturation and subsequent decline of the dominant competitor. "Solfus" is a 

term employed to describe a major new energy technology 

(for example solar or fusion) that could emerge during the 

2040's at about the time that natural gas would reach maximum share of total energy (Marchetti and Nakicenovic, 

1979; Nakicenovic, 1990). 

Figure 6 demonstrates that the diffusion of new energy 

sources and the replacement of older energy sources by 

newer ones takes on the order of almost I 00 years at the 

global level. All too often there is over optimism about 

how rapid the diffusion of new technologies might be. The 

historiography (history and geography) of technological 

change clearly demonstrates that the diffusion of innovations with some economic and social significance may 

take on the order of decades and sometimes even centuries. Longer periods are required for the pervasive transformation of economic activities by a whole cluster of 

technological and organizational innovations. The analysis 

of primary energy substitution and market penetration suggests that natural gas may become the dominant energy 

source and remain so for half a century, perhaps to be replaced by carbon-free energy sources such as nuclear, 

solar, or fusion. Thus, the primary energy substitution implies a gradual continuation of the decarbonization of energy in the world. The "methane economy" could 

represent a first step toward a carbon-free energy future. 

For this reason the dynamics of primary energy substitution is used as a scenario for determining carbon dioxide 

and methane emissions associated with a stronger reliance 

on natural gas as a fuel of choice in the future. This approach was employed more than 15 years ago to determine future energy-related carbon dioxide emission 

scenarios and was used again a few years ago in a more 

comprehensive assessment of future carbon dioxide and 

methane emissions (Marchetti, 1979; Ausubel and others, 

1988; Victor, 1990). 

Market penetration and substitution analysis provides 

a method for calculating shares of different primary energy sources in the world. What is required is a scenario 

describing the levels of global primary energy consumption. Thereafter, the calculation of carbon dioxide emissions becomes a straightforward matter; the following are 

carbon dioxide emissions factors per unit energy (kWyr): 

Wood 0.844 tC/kWyr; coal 0.735 tC/kWyr; oil 0.849 

tC/k Wyr; and natural gas 0.442 tC/kWyr (Ausubel and 

others, 1988). 

We examine a methane economy scenario with two 

overall levels of energy consumption in the world, both 

are population driven and based on World Bank estimates 

(Vu, 1985). One variant of the methane economy scenario, 

the "efficiency case," holds per capita energy consumption 

at the current level so that the primary energy consumption increases at the same rate as world population growth. 

This leads to a primary energy consumption rate of about 

20 TWyr/yr by the end of the next century, when the population reaches 10 billion. The second variant, the "longwave case," stipulates another growth pulse in per capita 

primary energy consumption leading to a threefold increase by the end of the next century and to staggering 

levels of global primary energy consumption. The two 

cases cover a large domain encompassing some of the 

highest and lowest projections from the literature. Figure 7 ~. 

shows the primary energy consumption in the two variants 

of the methane economy scenario. 

The carbon dioxide emissions are simply calculated as 

the product of the market shares of different energy sources (fig. 6), the scenario of global primary energy consumption (fig. 7) and individual emissions factors (discussed 

above). Figure 8 shows the resulting carbon dioxide emissions for the two methane economy variants. In the efficiency variant, emissions stay roughly constant over the 

next 50 years, peaking shortly before 2050 and falling 

thereafter. The results of this case are close to the lowest 

of the IPCC scenarios and consistent with gradual stabilization of atmospheric carbon dioxide concentrations (In- -

tergovemmental Panel on Climate Change, 1992). In the 

long-wave case, emissions peak steeply at a level close to 

15 GtC per year shortly before 2050 and also decline 

thereafter falling to 7 GtC in the year 2100. The two cases 

bracket virtually all reasonable scenarios of primary energy consumption in the future and they result in substantially lower carbon dioxide emissions than other long-term 

1012~------------------~------------------~ 

f 

c 

0 

:g_ 

E 

10 11 

~ 1010 

0 

(J 

,., 

E" 

<ll 

c 

w 

1850 1900 1950 

Year 

/ 

/ 

Long wave case 

..... -

_ ..... / 

/ 

/ ---- /? _..--;;;ic1ency case 

2000 2050 2100 

Figure 7. Primary energy consumption (historical data (solid 

line) and the two variants (dashed lines) of the "methane economy" scenario). 
670 THE FUTURE OF ENERGY GASES 

20 

L W - Long wave case 

E - Efficiency case 

1850 1900 1950 2000 2050 2100 

Year 

Figure 8. Global carbon dioxide emissions in gigatons of carbon 

per year (GtC/yr) (historical data and the two variants of the 

"methane economy" scenario). E, efficiency variant; LW, longwave variant. 

scenarios. Because the same market shares are used for 

both variants, the methane economy scenario has the same 

carbon intensity of primary energy consumption in both 

cases. In fact, the scenario achieves high decarbonization 

rates in the world, higher than those experienced (fig. 2) 

and higher than assumed in the majority of other energy 

and carbon dioxide projections. 

ENERGY SCENARIOS AND 

DECARBONIZATION 

Table 1 summarizes the structure of current (1990) primary and final energy supply and resulting carbon emissions as well as a range of scenarios for the period 2020 to 

2025. As a measure of the degree of decarbonization, we 

calculate the primary energy carbon intensity as total energy-related carbon emissions divided by the total primary 

energy consumption. The efficiency case of the methane 

economy scenario is compared with five other scenarios. 

Two views of the future emerge from table 1 (see also 

fig. 2). One view implies a discontinuity in the historically 

observed trend of decarbonization of energy systems. Instead, the fuel mix becomes more carbon intensive. This is 

due to increased reliance on coal and synthetic fuel production in the scenarios. The EPA's RCW and (to a lesser 

degree) the Energy and Industry Subgroup of Intergovernmental Panel on Climate Change scenario are examples 

(Environmental Protection Agency, 1990; Energy and Industry Subgroup of Intergovernmental Panel on Climate 

Change, 1991). A second view adopts basically a "dynamics-as-usual" perspective, which is a continuation of historical trends in energy decarbonization as, for example, 

reflected in the ECS'92 scenario (Nakicenovic and others, 

1993) or the recent reference scenario of the World Energy 

Council (World Energy Council, 1992). However, these 

improvements, as impressive as they are especially in 

comparison with other scenarios, are not sufficient to reverse the rising trend in global energy-related carbon 

emissions. Both scenarios still result in global emissions 

between 8.06 and 8.4 GtC by the year 2020. 

In comparison, the methane economy scenario is more 

dynamic. Carbon intensity falls because the increased natural gas use "bridges" the time period to a massive market 

penetration of zero-carbon energy sources such as solar or 

nuclear energy in the second half of the 21st century. 

Table 1 reproduces the efficiency variant of the methane 

economy scenario. The implied energy-efficiency improvement strategy results in a primary energy demand of only 

some 15 TWyr by the year 2025; traditional biomass uses 

(currently estimated at 1.5 TWyr) are excluded in the scenario (if included, total energy demand would be quite 

close (10 to 15 percent lower) to the ECS'92 or the WEC 

scenario). This, together with a drastic shift in the energy 

supply structure (natural gas accounting for 68 percent of 

primary energy supply by 2025), is reflected in the carbon 

emissions estimate of 6.16 GtC, which is basically a stabilization of current emission levels. 

A Renewables-lntensive Global-Energy Scenario 

(RIGES) has been suggested by Johansson and others, 

( 1992). In their scenario, the final energy demand of 

12.4 TWyr is close to that in the ECS'92 scenario described 

above. RIGES suggests that renewables would be competitive against fossil fuels and could penetrate massively as 

primary energy supply. Sustainable biomass and other renewables account for close to 43 percent of primary/secondary energy supply (>15.26 TWyr) by the year 2025. 

(Primary energy production is only given for biomass and 

coal. For nuclear and hydropower we have assumed a substitution equivalent based on the average efficiency of fossil 

electricity generation in the scenario (40 percent). For oil, 

gas, geothermal, and intermittent renewables, only secondary energy equivalents are given, this also explains why the 

primary energy carbon intensity of RIGES is not presented 

in figure 2.) It must be emphasized, however, that such a 

rapid market penetration of nonfossil energy sources in this 

scenario is without precedent for any primary energy 

source in history. For example, it took about 80 years for 

the market share of oil to grow to 40 percent of the global 

primary energy supply. The carbon emissions in RJGES 

would amount to 4.97 GtC per year, a stabilization (even 

slight reduction) of current energy-related carbon dioxide 

emissions. 
ENERGY GASES-THE METHANE AGE AND BEYOND 671 

Table 1. Primary and final energy consumption, carbon emissions, and carbon intensity (1990 and seenarios for the period 2020 to 2025). 

[IPCCIEIS 2025, Intergovernmental Panel on Climate Change Energy and Industry Subgroup's median scenario; EPA RCW 2025, 

Environmental Protection Agency's Rapidly Changing World scenario; IIASA ECS'92, International Institute for Applied Systems 

Analysis Environmentally Compatible Scenario '92; WEC reference, World Energy Council's reference scenario; RIGES 2025, Renewabies-Intensive Global-Energy Scenario (Johansson and others, 1992). TWyr, terawatt year; GtC, gigatons carbon; tC/kWyr, tons of 

carbon per kilowatt year;--, no data; n.a., not applicable] 

Category 1990 

Primary energy consumption (TWyr): 

Coal 2.94 

Oil 4.19 

Gas 2.22 

Nonfossil 2.35 

Total 11.70 

Final energy consumption (TWyr): 

Coal 

Oil 

Gas 

Electricity and heat 

Other 

Total 

Carbon emission (GtC): 

Final energy use 

Energy sector 

Total" 

Carbon intensity (tC/k:Wyr): 

Primary energy 

Final energy 

"Efficiency scenario. 

bExcluding biomass. 

1.22 

3.52 

1.42 

LIO 

1.20 

8.46 

3.02 

2.48 

5.50 

0.470 

0.357 

IPCC/ 

EIS 

2025 

7.56 

7.07 

5.48 

4.53 

24.64 

3.28 

5.89 

4.04 

3.61 

1.08 

17.90 

7.77 

4.68 

12.45 

0.505 

0.434 

EPA 

RCW 

2025 

8.73 

4.96 

3.09 

3.70 

20.49 

4.09 

5.12 

2.52 

2.81 

14.54 

7.31 

3.81 

ll.l2 

0.547 

0.503 

WEC liAS A "Methane RIGES reference ECS'92 economy" 2025 2020 2020 2025" 

4.55 3.87 0.53 2.82 

5.26 6.20 1.92 2.43c 

3.95 3.92 1.59 2.95c 

5.16 4.10 2.36b 7.06c 

18.92 18.10 15.34b >15.26c 

n.a. 1.58 n.a. 2.16 

n.a 5.06 n.a 2.43 

n.a 2.54 n.a 1.87 

2.59 2.29 n.a. 2.42 

n.a. 1.37 n.a. 3.52 

n.a. 12.85 n.a. 12.40 

n.a. 5.12 n.a. 3.95 

n.a. 3.53 n.a. 1.02 

8.40 8.06 6.16 4.97 

0.444 0.445 0.402 >0.330 

n.a. 0.398 n.a. 0.319 

cFor oil, gas, geothermal, and intermittent renewablcs only secondary energy equivalent. Primary energy requirements, therefore, would be higher. This uncertainty also affects the primary energy carbon intensity. 

METHANE AND CARBON DIOXIDE 

EMISSIONS 

Carbon dioxide is the major energy-related source of 

global warming and the single most important greenhouse 

gas. Methane is also a natural constituent of air, arising 

from many natural processes. Recent increases in the concentration of atmospheric methane are usually attributed to 

diverse anthropogenic activities, such as the growth of animal population, rice production, and organic waste depositories. However, using methane as a source of energy also 

contributes to the atmospheric increases. Major energy-related sources of methane come from coal mining, oil and 

natural gas production, and natural gas transport, distribution, and end use (see Clayton and others, this volume). 

Figure 9 shows the atmospheric carbon dioxide concentrations that result from the methane economy scenario 

corrected for methane leakage. Simple models of atmospheric carbon dioxide and methane concentrations have 

been used (Ausubel and others, 1988; Victor, 1990; Grtibler 

and Fujii, 1991). For carbon dioxide, an airborne fraction of 

close to a half of annual emissions was used together with a 

slow decay of atmospheric concentrations. Methane leaks 

from the natural gas extraction, supply, and distribution 

system are assumed to be 2.5 percent, and methane is assumed to be 24 times as effective as carbon dioxide (by 

volume) in greenhouse forcing. The dotted lines in figure 9 

are for two additional calculations, one without leakage of 

natural gas (methane emissions from coal are included) and 

a methane forcing factor of 16 times that of carbon dioxide 

(low case) and the other with 4 percent leakage and a methane forcing factor of 32 times that of carbon dioxide (high 

case). Two methane forcing factors compared to carbon dioxide are used to encompass the range given in the literature, the high factor of 32 and low one of 16 (Victor, 1990). 

The atmospheric concentrations of carbon dioxide and 
672 THE FUTURE OF ENERGY GASES 

700 

600 Long wave case 

-.....___~---

.!!l 

c 

w 

'" 500 > ·s 

0"" 

w --~~-~-------------­ .,. .. -""" 

0 

0 

E 400 Q_ 

Q_ 

300 

Efficiency case 

200 

1950 2000 

Year 

2050 2100-

Figure 9. Atmospheric C02 and CH4 concentrations from the "methane economy" scenario 

expressed as C02 equivalents in parts per million. Simple models of C02 and CH4 concentrations and different values for CH4 forcing have been used for estimating C02 equivalents of 

CH4 concentrations. Higher set of curves are for the long-wave case and lower ones are for 

the efficiency case of the scenario. Lower dotted curves show only C02 emissions, solid lines 

are C02 and CH4 emissions for 2.5 percent leakage, and higher dotted curves are for 4 percent 

leakage and high CH4 forcing. 

methane are given in parts per million of C02 equivalents. 

For this calculation, methane concentrations are converted 

to C02 equivalents using the methane conversion factors 

discussed above and a methane atmospheric lifetime of 9.6 

years. 

This sensitivity analysis of methane-emissions inclusion indicates that the methane economy scenario yields 

substantial reductions in greenhouse gas emissions, even 

when large methane leaks are included. However, it is acknowledged that the role of methane leaks is not trivial. 

As energy use increases, especially in the long-wave variant, the problem of methane leaks becomes more important (Victor, 1990). This means that the greenhouse 

forcing, owing to increased levels of energy consumption 

with the same structure of the energy system, is not linear. 

This finding identifies the additional advantage of lower 

energy scenarios toward the absolute and relative reduction of greenhouse gas emissions. 

The lower rate of decarbonization in all scenarios, except the methane economy, over the rates achieved historically illustrates the difficulty of achieving stabilization of 

energy-related carbon emissions under the premises of 

population growth and economic development. Very massive restructuring of future energy systems along with vigorous efficiency improvement efforts will be required to 

come close to stabilizing global emissions. 

METHANE ECONOMY AS 

A BRIDGE TO HYDROGEN 

The analysis of the methane economy scenario has 

demonstrated that it achieves substantial carbon dioxide 

emission reductions during the next century compared 

with alternative scenarios that rely more on other fossil 

energy sources in the future. As such the methane econo-. 

my could make a significant contribution toward emissions 

reduction; however, it is important to observe that most of 

the carbon dioxide would be originating from natural gas. 

Thus, further mitigation in this scenario would have to be 

· focused on natural gas itself. This means that ways have 

to be investigated for limiting carbon emissions associated 

with natural gas use. 

There are basically two alternative approaches in reducing carbon dioxide emissions from methane use-one 

is to remove carbon after combustion and the other before. 

In the first case, the most promising technologies involve 

carbon scrubbing from flue gases. There are three main 
ENERGY GASES-THE METHANE AGE AND BEYOND 673 

scrubbing processes that could be used: chemical and 

physical absorption, cryogenic distillation, and membrane 

separation (Nakicenovic and others, 1993). The chemical 

absorption process is widely used to remove oxides of sulfur (SOx) and oxides of nitrogen (NOx) from flue gases, 

and there are a few pilot plants that remove carbon dioxide by the same method. The various absorbents include 

potassium carbonate and amines. Scrubbing would clearly 

increase energy costs. The monoethanol-amine process 

would, for example, increase electricity costs by perhaps 

80 percent, leading to carbon dioxide mitigation costs of 

about $140 per tC removed (Blok and others, 1991; Nakicenovic and others, 1993). The major problems associated 

with scrubbing are to reduce the costs and minimize losses 

in plant efficiency owing to the energy spent in separating 

carbon dioxide from flue gases. Further, scrubbing processes are more suited for larger concentrations of carbon 

dioxide, as in powerplant flue gases. They are less suited 

for distributed combustion of natural gas in individual 

homes and end-use devices. Thus, scrubbing would be applicable on larger scales, mostly in electricity generation. 

The other alternative would be to remove carbon from 

natural gas prior to consumption, leaving hydrogen as the 

energy carrier. The basic process would involve methane 

steam reforming, followed by a shift reaction and physical 

absorption or other separation of carbon dioxide. Hydrogen would then be transported to the user and converted to 

the desired energy form, heat, or work, without any carbon 

dioxide emissions. This is clearly a more elaborate mitigation strategy than carbon scrubbing, but it offers greater 

possibilities in the long run including a bridge to the "hydrogen" economy, after the saturation of the natural gas 

contribution to global energy supply. This mitigation strategy offers a transition from the current global reliance on 

a carbon-intensive mix of fossil fuels via methane to a carbon-free energy system in the distant future. 

Both scrubbing and removal generate large amounts of 

carbon that are not released into the atmosphere. The 

amounts of carbon generated by scrubbing alone would be 

truly enormous. As was mentioned above, global carbon 

dioxide emissions from energy use amount to close to 

6 GtC per year, of which about 2 GtC or about 7 GtC02 per 

year is from ~lectricity use. The amount of carbon dioxide 

generated today in electrical powerplants alone dwarfs all 

possible market demands for this carbon dioxide. Thus, an 

important question is how such a large mass flow can be 

managed. There are two possibilities: (l) to utilize carbon 

to the maximum degree possible in other activities or (2) to 

store the collected carbon in permanent disposal sites. The 

possible uses of carbon dioxide include enhanced oil recovery, chemical fee~stocks, building materials, carbonization 

of beverages, food conservation, sewage treatment, fertilizers in greenhouse horticulture, fire extinguishing equipment, and gas welding. Of all of these potential commercial 

uses of collected carbon dioxide, only the first three provide 

permanent means of disposal; however, the quantities utilized would · be limited compared with ·the potential 

amounts of carbon dioxide requiring disposal. 

Additionally, carbon dioxide may also be permanently 

stored in natural underground reservoirs, such as aquifers 

or depleted natural gas fields, or alternatively deposited in 

the deep ocean. It is difficult to estimate the quantities of 

accumlflated carbon dioxide that could be stored in aquifers and gas and oil fields with any degree of certainty. 

The potential capacity might be as high as 750 GtC (Nakicenovic and others, 1993). It is clear, however, that this is 

a rough estimate and not a practical estimate of storage 

capacity for future carbon emissions, but the orders of 

magnitude involved show that capacity exists to store current levels of carbon emissions for at least the next half a 

century. Thus, the storage potential is indeed large by any 

standards. 

In comparison, the potential for carbon disposal in the 

deep ocean is vast. The global carbon cycle involves the 

annual exchange of around 200 GtC between oceans, the 

atmosphere, and the biosphere. The largest amount of the 

carbon is "stored" in the oceans and is estimated to be 

about 36,000 GtC. As the largest carbon reservoir on 

Earth, the deep ocean might be a possible repository for 

the carbon generated by scrubbing and removal. There are 

various disposal schemes: (1) to pump carbon dioxide in 

high-pressure pipes to the ocean floor, (2) to inject liquid 

carbon dioxide into the ocean at depths of about 3 km that 

would then continue to sink, (3) to release solid carbon 

dioxide (ice) that would sink by itself to the ocean floor, 

and ( 40 to disperse carbon dioxide into a suitable thermohaline current that would carry it to the ocean floor. 

The gist of Marchetti's (1976) proposal to dispose of 

carbon dioxide was to generate a "gigamixer" by injecting 

carbon dioxide into sinking thermohaline currents that 

eventually reach the deep ocean where the carbon dioxide 

enriched water might reside for thousands of years, owing 

to the slow rate of natural mixing. The ·proposal involved 

using the Gibraltar subduction undercurrent and would 

provide a storage capacity of 10 GtC per year, which easily exceeds the volume of carbon dioxide generated by energy-related sources in the methane economy scenario 

during the next half a century. In a more practical scheme, 

carbon dioxide collected in continental Europe could be 

transported by pipeline for disposal at Gibraltar. The theoretical mitigation potential of this scheme is vast because 

there are other sinking thermohaline currents including 

subduction currents in the Red Sea (Bab-al-Mandab current), the Weddell Sea, and the North Atlantic. 

Clearly, all of these different schemes for storing carbon dioxide in either liquid or solid pools on the ocean 

floor or dissolved in the deep ocean still require concept 

proof before even a pilot project could be started. Among 

the major outstanding uncertainties are the possible ecological effects of higher concentrations of carb<?n dioxide 
674 THE FUTURE OF ENERGY GASES 

in the oceans and their effects on local water chemistry in 

the vicinity of storage sites. 

The methane economy scenario with carbon removal 

presents the possibility of achieving global energy decarbonization and eventually eliminating carbon emissions altogether. Thus, methane (natural gas) fulfills most of the 

obvious future requirements for becoming the major source 

of energy. A bonus is that the reliance on natural gas can 

pave the way for a very clean, hydrogen future. Figure 10 

illustrates the possibility and timing of such an evolutionary 

transition from fossil fuels to hydrogen (see also Veziroglu 

and Barbir, this volume). It shows global decarbonization 

as the increasing ratio of hydrogen to carbon in the average 

energy mix. The data show the actual hydrogen and carbon 

content of global primary energy consumption as specified 

in figure 10 for wood, coal, oil, and natural gas. The change 

in hydrogen to carbon ratio is presented as a "substitution" 

process of hydrogen for carbon in the total primary energy 

consumption during the last century and as the continuation 

of this process in the future. The extrapolation in figure 10 

shows that, after this century, the hydrogen-to-carbon ratio 

may exceed the level of the 4:1 ratio that can be achieved 

by the use of pure methane, implying that some additional 

hydrogen would be needed to supplement the increasing 

reliance oil methane. 

A possible way of both increasing the share of methane in global energy and the hydrogen-to-carbon ratio is 

carbon removal and disposal. For example, methane could 

be separated into carbon dioxide and hydrogen in the 

proximity of the production site. This would require the 

development of large-scale steam-reforming processes, but 

it is conceivable that the separation could be achieved economically. The separated carbon dioxide could be reinject0.99 

World 

101 0.90 

:c u 

:;; 

II 

+ 

g 

:;; c 100 I 

0.50 II 

.... 

c: 

0 

;;:: "fl 

e 

u. 

w-1 Wood HiC=0.1 :1 0.10 

Coal HiC=1 :1 

Oil HiC=2:1 

!H = 320 years Gas HiC=4:1 

10-2 0.01 

1800 1900 2000 2100 

Year 

Figure 10. Hydrogen-to-carbon ratio of global primary energy 

including historical data and future projection (Marchetti, 1982). 

ed into the depleted natural gas field or used for enhanced 

oil recovery, and hydrogen could be piped like methane. 

Marchetti (1991) made such a proposal for Russian natural 

gas and hydrogen delivery to Europe and use of separated 

carbon dioxide for enhanced oil production in the Ukraine. 

Initially, hydrogen could be added to the natural gas in the 

same pipeline and if required separated at consumption 

sites by membranes or other methods or simply used as 

mixture of methane and hydrogen,. As the quantities of 

separated carbon dioxide and hydrogen increase it might 

become necessary to build dedicated hydrogen and carbon 

dioxide pipelines. In the first stages of the "hydrogen 

economy" of the distant future, separated carbon dioxide 

might have to be deposited in the deep ocean, as the fluxes 

become too difficult to be absorbed by declining oil-production needs. Eventually, methane could be replaced as 

the source of hydrogen by carbon-free options, collectively called solfus (see fig. 6). Hydrogen and electricity 

would provide virtually pollution-free and environmentally 

benign energy carriers. To the extent that these energy carriers might be produced from methane, the separated carbon dioxide could be contained within the energy sector or 

stored. As the methane contribution to global energy needs 

saturates and subsequently proceeds to decline, carbonfree sources of energy would takeover, eliminating the 

need for carbon handling and storage. 

CONCLUSION 

The findings in this paper indicate that methane and 

hydrogen could become means for reducing energy-related 

emissions of greenhouse gases. The issue of climate warm-

. ing is likely to be a major planetary concern during the 

next century along with the need to provide sufficient energy for further social and economic development in the 

world. Methane and later hydrogen offer the possibility for 

reconciling these conflicting objectives. The findings show 

that evolutionary development of the global energy system 

toward a larger use of natural gas is consistent with the 

dynamics of the past 130 years. Continuation of this process in the future leads to carbon dioxide and methane 

emissions that are low compared with other, more conventional scenarios. The reasons for the moderate emissions 

associated with the emergence of the methane economy are 

that natural gas emits less carbon dioxide than other fossil 

fuels and that the scenario assumes the development of 

zero-carbon sources of energy, collectively called solfus, in 

the future and their major role in energy production by 

2100. The current phase in the development of the global 

energy system may be just midway through the "hydrocarbon- era." Decarbonization in the world can continue as 

methane becomes the major energy source. From this perspective, methane is the transitional hydrocarbon, and the 

great energy breakthrough that we must look, hope, and 
ENERGY GASES-THE METHANE AGE AND BEYOND 675 

work for during the next decades is the production of hydrogen without fossil fuels (Ausubel and others, 1988). In 

the meantime, the natural gas share in total primary energy 

should continue to grow at the expense of dirtier energy 

sources--coal and oil. This transition to the methane age 

and beyond to carbon-free energy systems represents a 

minimum-effect option because it would also enhance the 

reduction of other adverse impacts of energy use on the 

environment in addition to substantial reductions of carbon 

dioxide emissions. 

REFERENCES CITED 

Ausubel, J.H., Grtibler, A., and Nakicenovic, N., 1988, Carbon 

dioxide emissions in a methane economy: Climatic Change, 

v. 12, p. 245-263 (reprinted at International Institute for Applied Systems Analysis, RR-88-7). 

Blok, K., Faria, J., Hendriks, C., and Turkenburg, W., 1991, Carbon dioxide removal-A review: presented at the International Symposium on Environmentally Sound Energy 

Technologies and their Transfer to Developing Countries 

and European Economies in Transition (ESETT '91), October 1991, ENI San Donato Milanese, Italy. 

Energy and Industry Subgroup of Intergovernmental Panel on 

Climate Change, 1991, Energy and Industry Subgroup report: Geneva, Switzerland, Intergovernmental Panel on Climate Change. 

Gold, T., 1985, The origin of natural gas and petroleum, and the 

prognosis for future supplies: Annual Review of Energy, 

v. 10, p. 53-88. 

Grtibler, A., and Fujii, Y., 1991, Inter-generational and spatial equity issues of carbon accounts: Energy, v. 16, no. ll-12, 

p. 1397-1416 (reprinted at the International Institute for Applied Systems Analysis, RR-92-6). 

Intergovernmental Negotiating Committee, 1992, Annex I to the 

report of the Intergovernmental Negotiating Committee for a 

framework convention on climate change: United Nations 

Framework Convention on Climate Change, document 

NAC.237/18, part li/Add.l, New York, United Nations. 

Intergovernmental Panel on Climate Change, 1992, 1992 Intergovernmental Panel on Climate Change Supplement: Geneva, Switzerland, Intergovernmental Panel on Climate 

Change. 

Johansson, T.B., Kelly, H., Reddy, A.K.N., and Williams, R.H., 

1992, Renewable fuels and electricity for a growing world 

economy, in Johansson, T.B., Kelly, H., Reddy, A.K.N., and 

Williams, R.H., eds., Renewables for Fuels and Electricity: 

Washington, D.C., Island Press, p. 1-71. 

Lee, T.H., 1988, Combined cycle systems-technology and implications, in Lee, T.H., Linden, H.R., Dreyfus, D.A., and 

Vasko, T., eds., The Methane Age: Dordrecht, Netherlands, 

Kluwer Academic Publishers, p. 737-745. 

Manne, A.S., and Schrattenholzer, L., 1992, International Energy 

Workshop-Overview of poll responses, January edition: 

Laxenburg, Austria, International Institute for Applied Systems Analysis. 

Marchetti, C., 1976, On geoengineering and the C02 problem: 

Laxenburg, Austria, International Institute for Applied Systems Analysis, RM-76-17. 

---1979, Multicompetition and the diffusion of new technology in the energy system: Chemical Economy and Engineering Review, v. 11, no. 4, p. 7-13. 

---1982, When will hydrogen come?: Laxenburg, Austria, 

International Institute for Applied Systems Analysis, WP-82-

123. 

---1991, How to solve the C02 problem without tears: Laxcoburg, Austria, International Institute for Applied Systems 

Analysis, RR-91-6. 

Marchetti, C., and Nakicenovic, N., 1979, The dynamics of energy systems and the logistic substitution model: Laxenburg, 

Austria, International Institute for Applied Systems Analysis, 

RR-79-13. 

Nakicenovic, N., 1979, Software package for the logistic substitution model: Laxenburg, Austria, International Institute for 

Applied Systems Analysis, RR-79-12. 

---1986, The automobile road to technological change--diffusion of the automobile as a process of technological substitution, Technological Forecasting and Social Change, 

v. 29, p. 309-340. 

---1990, Dynamics of change and long waves, in Vasko, T., 

Ayres, R., and Fontvielle, L., eds., Life Cycles and Long 

Waves: Berlin, Springer-Verlag, p. 747-792. 

Nakicenovic, N., Grtibler, A., Inaba, A., Messner, S., Nilsson, S., 

Nishimura, Y., Rogner, H., Schafer, A., Schrattenholzer, L., 

Strubegger, M., Swisher, J., Victor, D., and Wilson, D., 

1993, Long-term strategies for mitigating global warming: 

special issue in Energy, v. 18, no. 5, p. 407-609. 

United Nations, 1991, World population prospects 1990: New 

York, United Nations Population Studies No. 120. 

U.S. Environmental Protection Agency, 1990, Policy options for 

stabilizing global climate: Washington, D.C. 

Victor, D.G., 1990, Greenhouse gas emissions from high-demand, natural-gas-intensive energy scenarios: Laxenburg, 

Austria, International Institute for Applied Systems Analysis, 

WP-90-01. 

Vu, M.T., 1985, World population projection 1985: Baltimore, 

John Hopkins University Press. 

World Energy Council, 1992, Energy for tomorrow's worlddraft summary of the World Energy Council commission 

global report: London, World Energy Council. 

Yamaji, K., Matsuhashi, R., Nagata, Y., and Kaya, Y., 1991, An 

integrated system for C02/energy/GNP analysis-Case studies on economic measures for C02 reduction in japan, paper 

presented at the workshop on C02 reduction and removalmeasures for the next century, 19-21 March 1991: Laxenburg, Austria, International Institute for Applied Systems 

Analysis. 
Among the problems associated with gas exploration, 

storage (particularly of hydrogen gas), and transportation 

(particularly of liquefied natural gas) are a formidable array 

of logistical and technological requirements. One report 

herein describes the research program on natural gas that 

is overseen by the Department of Energy, and another 

describes the data bases available from the U.S. Bureau of 

Mines on natural-gas analyses for all of the United States. 

Finally, there is a report that compares fossil fuels with 

hydrogen, an energy gas that does not occur in large 

amounts naturally. Hydrogen is typically created synthetically; it can be used as an energy carrier to hold energy 

converted from another form and pass it along for another 

use. Synthetic gases are alternatives when the original 

energy source is unusable or not transportable. 

TECHNOLOGY 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Logistical Considerations for the Exploration and 

Production of Natural Gas 

By Russ D. Cunningham1 and Daniel R. Rowe 1 

CONTENTS 

Abstract .......................................................................... 677 

Introduction ........................................................ :.' .......... 677 

Prospect Definition and Acquisition Strategy ............... 678 

Geologic Evaluation................................................ 678 

Prospect Definition and Land Evaluation ............... 678 

Project Development Strategy ......... ........ ..... .. ........ 679 

Predrilling Administrative Procedures .......................... 679 

Well Proposal .......................................................... 679 

Prespud Operations................................................. 679 

Drilling Operations ...... .......... ................. .. ...... .. ... ........ .. 680 

Wellsite Supervision ...................... ...... ........ .. .... ..... 680 

Office Administration Procedures ........................... 680 

Casing-Point Election ............................................. 680 

Completion Operations.................................................. 682 

Define Completion Program................................... 682 

Natural-Gas Marketing ........................................... 682 

Legal and Administrative Procedures..................... 682 

Summary........................................................................ 682 

ABSTRACT 

The exploration, production, and marketing of natural 

gas is a multidisciplined, rigorous process requiring contributions from a variety of technically trained personnel. 

The process consists of geologic, engineering, and legal 

evaluations. 

1

GHK Co., 3030 Northwest Expressway, 18th Floor, Oklahoma 

City, OK 73112-5467. 

The exploratory phase requires evaluation on a megaregional scale of lithospheric interactions influencing 

structure, stratigraphy, and thermal maturity. A regional 

geologic analysis follows and delineates the geologic conditions associated with natural-gas traps and production. 

Finally, a drilling location is proposed after detailed geologic analysis is completed and an area of prospective 

natural-gas accumulation is identified. 

Permission to drill and the ultimate extraction of natural gas from reservoirs at depth is acquired after specific 

ownership of mineral rights is determined and the appropriate legal and business contracts are consummated. Government and regulatory permits must be obtained and 

procedures must be followed to legally drill for and produce natural gas. Engineers propose a drilling and completion program. This program is executed by specialized 

companies who are contracted to perform the drilling and 

evaluation procedures associated with the well. After successfully drilling and testing a natural-gas well, complicated legal contracts are negotiated and signed to market the 

natural gas to end-users. 

INTRODUCTION 

Exploring for natural gas is a complex process that 

requires the extensive time and effort of many people 

from varying technical backgrounds. Exploratory drilling 

for natural gas in the United States has undergone several 

cycles. For example, from 1940 until the early 1960's 

approximately 100 exploratory wells per year were drilled. 

In 1962, 300 exploratory and approximately 5,000 development wells were drilled. Activity decreased through the 

late 1960's and early 1970's, until a large increase in activity occurred in the late 1970's and early 1980's. The 

677 
678 THE FUTURE OF ENERGY GASES 

peak of this boom was reached in 1981 with the drilling of 

710 exploratory wells. In 1992 activity again decreasedonly 100 exploratory wells were drilled. 

Drilling an exploratory well takes little more than 

money, but determining where to drill and administering 

the drilling procedures is an involved process. The cost 

estimates are based on consulting fees and do not include 

company administrative overhead. This overhead includes 

support staffs, personnel departments, accounting departments, legal departments, and contract-administration departments in addition to the general office expenses. 

PROSPECT DEFINITION AND 

ACQUISITION STRATEGY 

GEOLOGIC EVALUATION 

Regional geologic evaluation must be completed to relate natural-gas production to specific geologic conditions 

in producing areas. This evaluation includes regional subsurface structure maps, facies and isopach maps of 

productive reservoirs, and cumulative production by stratigraphic horizon maps. These data need to be integrated into 

a mega-regional framework that includes tectonic history, 

succession of stratigraphic units, burial history, source-rock 

maturation, and migration of hydrocarbons. 

Geologic cross sections through productive areas are 

also necessary to define natural-gas trapping mechanisms; 

this definition consists of the trap geometry, timing of entrapment, and trap type. Trap types can be broadly defined as structural, stratigraphic, or some combination of 

the two. Extensive seismic data are necessary to define 

structural traps. Conversely, if most traps are stratigraphic, more detailed subsurface geologic facies maps are required to define them. Drilling and production practices 

for a specific objective must be defined and cost estimates for these procedures must also be projected. 

Maps showing cumulative production by horizon 

help to define the economic benefits that can be expected if the exploration program is successful in discovering and producing natural gas. These benefits can be 

compared to the projected costs of evaluation. Economic 

feasibility of a project can be determined after defining 

the probability of success. 

The expected economic benefits, the cost of achieving 

those benefits, and the probability of success can be estimated by the regional analysis. Regional analysis is the first 

critical evaluation in the process of exploration and production of natural gas. If the risked economic benefits are not 

greater than the acquisition costs, the play is uneconomic 

and should not be pursued. The costs involved in regional 

analysis include data acquisition and processing as well as 

labor for a team of technical and support personnel. The 

technical professionals include geologists, geophysicists, 

and petroleum engineers. Necessary data includes seismicreflection profiles, open-hole wireline logs of previously 

drilled wells, historical production data, and base maps 

showing legal land surveys and well locations. The effort 

and cost of this analysis depend on the size of the area 

involved, the number of producing horizons evaluated, and 

the amount of detail required. The analysis may take from 2 

weeks up to several months of work. A cost estimate for 

this evaluation may be obtained by assuming a company 

contracts a team of professionals that consists of a structural geologist, stratigrapher, geophysicist, and engineer. 

These professionals need the support of at least two technicians and one secretary. Domestic professionals charge approximately $700 per day, whereas international fees may 

be as high as $1 ,200 per day. Assuming a domestic exploration project that employs four professionals, two technicians, and one secretary, the daily cost for the regional 

study may be as high as $4,000. A regional study requiring 

2 months to complete will cost approximately $200,000 for 

the staff alone. Data acquisition and processing costs must 

be added to the estimate. Of course, this study may recommend no exploration potential exists and the company will 

move on to another area. 

PROSPECT DEFINITION AND LAND EVALUATION 

After determining the play is economically feasible, 

prospects worthy of drilling can be delineated. The geophysicist acquires and interprets seismic-reflection profiles 

in a prospective area delineated by regional geologic evaluations. The geologist then refines the regional maps with 

detailed local data and a drillsite is proposed. Domestic 

exploration requires the skills of a quasi-technical person 

with a legal and business background. This person is 

commonly referred to as a "Iandman." The Iandman is an 

integral part of the exploration and production team because without the legal permission to drill for natural gas, 

the best technical evaluations have no value. . 

The Iandman determines the mineral rights ownership 

of a prospective area. This is accomplished by reviewing 

county and state records of ownership, which begin with 

the issuance of a land patent by the Federal Government to 

the original land and mineral owner. The land patent is the 

official document issued by the Government of the United 

States granting exclusive ownership of the land to the 

homesteader. The ownership must be carefully traced 

through time and all transactions involving the prospective 

land tract are noted. Land transactions that affect mineral 

rights ownership include sale or transfer of rights, division 

of ownership among heirs, liens or mortgages against the 

properties, and current mineral leases in effect. After this 

rigorous analysis determines mineral rights availability, a 

strategy is planned to acquire the mineral rights and optimize the leasehold position. Land procurement for pros-
LOGISTICAL CONSIDERATIONS FOR THE EXPLORATION AND PRODUCTION OF NATURAL GAS 679 

pects includes acquiring mineral leases on prospective 

tracts and executing business transactions with other companies that may already have leasehold rights in the area of 

interest. This procedure is time intensive and may require a 

group of people 2 weeks or more to finish the evaluation. 

The duration of this task is dependent on the complexity of 

the historical land transactions and the format of the legal 

records. A land evaluation requiring three people 2 weeks 

to complete may cost approximately $10,000. 

PROJECT DEVELOPMENT STRATEGY 

When the prospect is technically defined and all the 

appropriate land work is completed, a strategy is formulated for the drilling of the initial wildcat test well and subsequent field development. This strategy is dependent on 

the technical evaluation, the land situation, drilling-rig 

availability, and economic parameters such as natural-gas 

prices and gas-market conditions. Natural-gas wells frequently have a long productive life. This necessitates price 

projections of natural gas far into the future, 20 to 30 

years in some cases. Marketing considerations include the 

availability of pipelines to transport the natural gas to user 

markets, the carrying costs charged to natural-gas producers by the transportation companies, and, finally, the demand for natural gas. 

PREDRILLING ADMINISTRATIVE 

PROCEDURES 

WELL PROPOSAL 

Once a play has been determined to be economically 

feasible, and after a prospect has been defined and the 

available mineral rights have been secured, a well proposal is made to other mineral rights owners. Other entities 

who may own mineral rights in the defined prospect 

include the Federal Government (Bureau of Land Management), state governments, competing companies, and 

individual people or estates. Drilling regulations vary 

from state to state, and we will consider the situation in 

Oklahoma, which is governed by the Oklahoma Corporation Commission (OCC). 

The OCC encourages exploration and production of 

natural resources. This is accomplished by a procedure 

called "pooling" of common source and supply of a given 

resource. Geologic and engineering evaluations of producing horizons define the areal extent affected by a well bore 

capable of producing natural gas. In Oklahoma, the common practice is to define the areal extent as one section of 

land (I mi2 or 640 acres) surrounding the well bore. Any 

person or entity owning rights in that section of land owns 

their proportionate share of all the natural gas produced 

from the well bore. For example, an entity or person who 

owns 10 percent of the section will also own I 0 percent of 

all natural gas produced from the well bore, even if the 

well bore is not located on their tract of land. 

Under pooling regulations, the other mineral rights 

owners in a given section of land normally have three options when responding to a well proposal. These are to 

participate and pay their proportionate share of the well 

costs; to "farm out" their interest, that is, assign their interest to the proposing company, but retain a small interest 

in the production from the well; or to sell their interest to 

the proposing company for fair market value as determined by the OCC. 

This pooling process involves the initial well proposal with an accompanying authorization for expenditure 

(AFE). The AFE is an estimate of the well costs including 

site preparation, drilling the well, and equipping the well 

with the appropriate production facilities. These estimates 

are obtained from service and supply companies that determine the availability and cost of the necessary equipment. Also, experts on mineral rights leases must prepare 

documentation to determine the fair market value in the 

area of interest. The fair market value reflects current prices paid as well as drilling and production activity in the 

area. After all parties have made their decision on participation in the proposed well, an attorney prepares a "drilling title opinion." This document verifies the legal 

ownership in the section and all interest owners are committed to the proposed well. 

PRESPUD OPERATIONS 

The beginning of actual drilling operations is called 

"spudding the well." Before the well is spud, appropriate 

service contractors must be selected; federal, state, and 

local permits, where applicable, must be secured; working interest owners' requirements for data distribution 

and well evaluation must be obtained; and environmental 

studies and recommendations must be addressed. Government agencies require the filing of several documents, 

including an application for a permit to drill, the land 

surveyors map that describes the coordinates and elevation of the drilling location, and a casing program that 

describes the proposed surface and production casing. 

Drilling and evaluation of the prospective horizon is a 

complex problem requiring a wide range of specialists. The 

well is drilled by a company who owns the drilling rig. The 

drilling operation includes a hydraulic system consisting of 

water and drilling mud. The mud is composed of water, 

chemicals, and other additives that keep the well bore from 

caving in as the well is being drilled and when the drill pipe 

is removed from the hole. The rocks are studied by a 

wellsite geologist. The penetrated horizons are evaluated by 

wireline logging tools. The logging tools measure the 
680 THE FUTURE OF ENERGY GASES 

porosity and resistivity of the rock formations to indicate 

the presence of natural gas. These logging tools measure 

characteristics of the rocks and are supplied by a specialized company. Potential production from a formation is 

tested by another specialized service company. If the well 

contains natural gas, another company will supply the tubular goods to produce it. These goods include casing, which 

is cemented in the hole, and tubing, which is inserted inside 

the casing to facilitate the natural gas flow from reservoir 

depth to the surface. The casing is cemented in place by 

another specialized company. The casing and formation are 

perforated and the reservoir rock is treated with fluids that 

stimulate the flow of natural gas through the rock by another specialized service company. The companies providing 

specialized services are normally selected from two or three 

who are asked to bid on the work prior to the need for the 

service. These companies will make design recommendations and cost estimates. The operating company must then 

select a contractor for each service. 

The design of the drilling operations must also consider the requirements of the well's other working interest 

owners. Some companies require certain well tests be performed. These tests may in tum require certain specifications of the well bore including hole diameter, depth 

below prospective horizon, and intermediate casing depth. 

Consequently, these test results have an impact on the selection of drilling equipment and drilling contractors. All 

of these factors must be considered by the operating company. Also, communication requirements between the operating company and other working interest owners must 

be determined. 

The amount of time and labor needed to accomplish 

the predrilling administrative tasks depends on the 

project's complexity. In general, a staff of three professionals and two support persons may require 3 to 4 weeks 

to accomplish all of the administrative tasks. The well proposal normally requires 2 weeks for response from the 

other working interest owners. 

The OCC docket is generally busy; therefore, it may 

take 30 days from the application date to the hearing date. 

Generally, the OCC takes 1 week to issue a ruling and the 

affected parties have 2 weeks to make their election. In 

summary, it takes approximately 9 weeks from the initial 

well proposal to final participation decisions by all parties. 

The drilling plan and selection of service contractors can 

be accomplished during this administrative period. 

DRILLING OPERATIONS 

WELLSITE SUPERVISION 

The supervision of drilling operations is accomplished 

by a drilling engineer, rig supervisor ("tool pusher"), and 

weBsite geologist. Each individual is responsible for monitoring progress and planning for successful completion of 

the drilling phase. The supervisors work as a team in 

solving problems that arise during the drilling of the well. 

The engineer is responsible for the actual drilling operations in addition to various accounting tasks that include 

invoice approval and expenditure projections. The tool 

pusher ensures the rig is safe and in good operational 

condition. He or she also supervises the crews who work 

on the rig's three daily shifts (tours) of 8 hours each. The 

wellsite geologist is responsible for describing the rocks 

penetrated during the drilling. He or she must also note 

indications of hydrocarbons in the drill cuttings and make 

recommendations for testing prospective hydrocarbonbearing horizons. 

OFFICE ADMINISTRATION PROCEDURES 

The information communicated from the wellsite during the drilling operation must be relayed to the appropriate technical personnel in the office. The drilling 

department is in daily contact with the rig personnel. The 

geologist in the office reviews sample descriptions provided by the weBsite geologist and compares these to other 

wells in the area to monitor progress and project possible 

zones of interest. Comparison data must be communicated 

to the wellsite geologist. Daily and cumulative drilling 

costs are monitored by the engineer on location and communicated to the office accounting department. Invoices 

are then prepared and sent to the other working interest 

owners. Accounts payable and receivable are maintained 

by the company operating the well. In addition to collecting and reviewing the daily drilling data, all of this information must be forwarded to the working interest owners. 

Most companies participating in drilling wells require detailed daily reports faxed to their office. Frequently there 

may be a dozen or more working interest owners in each 

well requiring the daily distribution of data. A summary 

of the drilling operations can be expressed in graphic 

form. The critical parameters in drilling a well are time 

versus depth and cost versus depth. A typical time versus 

depth curve showing projected and actual time is shown 

in figure 1. A cost versus depth curve (projected versus 

actual) is shown in figure 2. 

CASING-POINT ELECTION 

After the well bore has been drilled through the objective horizon, the most important decision regarding the 

well must be made. Does the well appear to have natural 

gas in economic volumes? The decision to run casing and 

test a horizon for production is made by carefully analyzing a great deal of available information. This information 

includes wireline logs, sample descriptions, open-hole test 
LOGISTICAL CONSIDERATIONS FOR THE EXPLORATION AND PRODUCTION OF NATURAL GAS 681 

results, side-wall cores, penetration rate, and, of course, 

natural gas showing in borehole cuttings and the drilling 

fluids during the drilling operations. All of these data considered together allow the reservoir engineer and geologist 

to evaluate whether the well may contain economic quantities of natural gas. This critical decision point is called 

"casing point" (that is, is it necessary to cement production casing in the well bore to test for and hopefully produce natural gas). The decision is critical because the 

casing cost may be as much as 20 to 30 percent of the 

cost to drill the well to this point. Additionally, the expenses to this point are mostly intangible costs and can be 

treated as tax deductions by the company. However, costs 

incurred from the casing point through completion are 

mostly tangible expenses that must be capitalized over the 

t; 

w 

"-

0 

5000 

10000 

- 15000 

~ w 

0 

20000 

25000 

30000 

0 

y~ 

40 

r:::::: f:::: r-x- '< - r--. 1--. 1-'<--

r--

life of the well. The decision to run casing and attempt a 

completion is based on an economic analysis. The cost of 

the completion attempt, including casing, subsequent reservoir treatments and the installation of surface facilities is 

weighed against the projected natural-gas recovery. The 

most significant production forecast is the initial rate of 

production and decline rate. These factors control the 

length o.f payout and the ultimate rate of return. 

If the operating company elects to run casing in the 

bore hole, they make this recommendation to the other 

working interest owners. The others usually have 48 hours 

to elect to participate in the completion attempt or elect to 

be "nonconsent." Nonconsent relieves them of any obligation to pay future costs in the well, but they are also excluded from any production of natural gas resulting from 

DAYS 

80 120 

t'-x- x- -x ... 

r--. --....... 

r--~ ~ ~ 

--r--:: ~X 

1---PROJECTEDOEPTH -X-ACn.JALDEPTH 

Figure 1. Time versus depth, showing projected and actual figures, for drilling a well. 

§ ~ 8 8 ~ ~- <'> ... 8 

... ~ ~ ~ 

~ ... ~ oi 

; ~ ! 5 ~ "' .... :£. : 

a ~ .. .. .. .. ~ ~ 

~------ ~-----------

0 

5000 

10000 

---- --- ----- ---- ffi 

"-

- 15000 

w 

~ 0 

------=:::.-- 20000 

25000 

30000 

1-PROJEClEODEPlH ---- AClUALOEPTH 

Figure 2. Cost versus depth, showing projected and actual figures, for drilling a well. 

5000 

10000 

15000 

20000 

25000 

30000 
682 THE FUTURE OF ENERGY GASES 

the completion of the well. Conversely, if the operating 

company elects to plug and abandon the well bore, the 

other working interest owners have the option to agree to 

plugging or they may elect to take over the well. They 

may then attempt a well completion on their own or with 

other working interest owners. 

The duration of the drilling operations depends on the 

objective depth, problems encountered during drilling, and 

the condition of the drilling rig. Generally, shallow wells 

less than 4,000 feet deep require 15 to 20 days to drill. 

Deep tests of greater than 18,000 feet in complex geologic structures may take over 300 days to drill to total 

depth. Technical and support personnel including weBsite 

and office staffs are necessary to monitor the entire drilling process. 

COMPLETION OPERATIONS 

DEFINE COMPLETION PROGRAM 

Engineers design the completion program after the decision to set casing has been made (fig. 3). The program 

includes reservoir evaluation and production-facilities design. The reservoir evaluation consists of perforations, 

clean-up acid treatment, and in some cases, fracture stimulation with proppants at high injection rates to increase the 

reservoir's permeability near the bore hole. The reservoir's 

production capacity is determined by designing flow tests 

and bottom-hole pressure build-up tests. The flow rates 

and pressure data reflect the projected ultimate recovery 

from the reservoir. The physical production facilities include the downhole equipment as well as surface-production facilities. This equipment must be designed to handle 

the expected rates of natural-gas production. Corrosive 

gases such as C02 and H2S are present in many reservoirs; therefore, the equipment must also be designed to 

withstand the effects of the~e gases. The surface facilities 

strip water from the natural gas, cool the gas produced 

from deep reservoirs, separate heavier gases (ethane, propane, and butane) from methane, and provide the means 

for gas to travel from the wellhead to the gathering system. The completion design and production testing usually 

requires 1 to 2 weeks and requires office and field engineers with their associated support staff. 

NATURAL-GAS MARKETING 

Gas gathering and marketing contracts are negotiated 

with transportation and marketing companies to move the 

gas from the wellhead to the user market. The pipeline 

company will have an in-house or independent engineer 

review the reservoir data to determine if it is economically feasible for them to construct a pipeline to the well. 

The pipeline company will make its profit from transportation fees, which are based on the proximity of the well 

to their existing lines, and whether or not the gas must be 

compressed or treated before it can be moved into their 

local gathering system. These fees may be as high as 15 

percent of the sales price per unit volume of natural gas. 

From this gathering system, the gas will be moved into a 

larger transmission line and carried to an industrial purchaser. This purchaser may be a public utility or a specialized industrial end user. The marketing of the gas 

determines the purchaser and the profit realized by the 

owners of the gas well. The marketing fees are variable 

and determined by the quality and quantity of the natural 

gas produced. 

The addition of a small "leg" to the gathering system 

for a new well commonly requires several weeks to complete. It normally involves placing a T-shaped joint on the 

existing line, trenching the ground to lay new pipe, and 

installing a meter to measure the amount of gas flowing 

from the new well into the pipeline system. If the new 

well is within 2 or 3 miles of existing pipelines, it may be 

on line within days of the completion. 

LEGAL AND ADMINISTRATIVE PROCEDURES 

Well-testing information is distributed to the working 

interest owners daily. Also, accounting books are kept and 

appropriate billings are sent to working interest owners. 

Attorneys prepare a "division order title opinion" that is 

more detailed than the drilling title opinion. The division 

order states precisely the net revenue interest to at least 5 

decimal places for each interest owner in the well. The 

disbursement of revenue is established by this legal document. The gas purchaser pays the operator the previously 

agreed upon price per unit (usually measured in thousands 

of cubic feet of gas, Mcfg). The operator then deducts and 

pays costs of transportation to gathering and pipeline companies, and any federal, state, or local taxes. The balance 

of the proceeds is then disbursed to the working interest 

owners. This process is labor and time intensive, and it 

requires a sophisticated accounting system; the system includes accounts payable, accounts receivable, and proceed 

disbursements. 

SUMMARY 

Regional geologic and engineering analyses define the 

expected economic rewards of an exploration play. The 

cost of achieving those rewards and the probability of successfully attaining those rewards is also determined by the 

regional analysis. After a company determines an exploration play to be economically feasible, an evaluation of the 

acreage is completed by the Iandman. The Iandman deter-
LOGISTICAL CONSIDERATIONS FOR THE EXPLORATION AND PRODUCTION OF NATURAL GAS 683 

risk 

analysis 

Prospect Definition & 

Acquisition Strategy 

mineral 

rights 

ownership 

geologic 

maps 

cross 

sections 

recoverable 

reserve 

estimates 

detailed 

geologic 

maps detailed 

seismic 

interpretation 

proposal 

location 

Land current 

leasehold 

obtain 

permits 

working 

interest 

ownership 

Pre-Drilling Administrative 

Procedwres 

Pre-Spud 

Operations 

\ 

appoint - drilling 

formation -------contractors 

evaluation 1 "'-. ----------drilling fluids 

(logging) well "'-. 

testing 

Drilling Operations 

well site 

geologist 

technical 

evaluation 

~ 

tool/ \ geologist 

pusher drilling 

engineer 

wire line 

logs_;_--

rock ------------ .-r samples 

open hole 

tests 

pertoration 

"--

penetration 

rate 

communication 

\ 

field to 

office 

Administration data 

distribution 

I 

accounting ~ working 

interest 

expected owners 

recovery 

production rate 

payout 

term 

rate of 

return 

division order 

title opinion 

------ reservoirI \ 

Define 

Program 

Completion 

Operations 

Legal & Administrative 

Procedures 

stimulation 

pressure 

tests 

/ facilitiesdownhole / 

surtace 

gathering & 

pipelines 

/ 

transportation 

contracts 

purchaser ___- end-users 

contracts 

I 

gathering fees 

/ 

accounting 

I ""' ------------- revenue ""' disbursements 

royalties ;axes 

Figure 3. Summary of logistical considerations for the exploration and production of natural gas. 

mines acreage availability and projects the cost of lease 

acquisition. 

Detailed geologic and geophysical studies are necessary to delineate a specific prospect and select a drillsite 

location. The mineral rights are leased and business deals 

are made to secure all the parties holding mineral interest 

in the proposed well. A drilling plan is designed and specialized contractors are chosen to drill and evaluate the 

well. 

: Upon successfully drilling to the objective horizon, the 

geologist and engineer determine the productive capabilities of the possible natural gas-bearing reservoirs. If the 
684 THE FUTURE OF ENERGY GASES 

Table 1. Estimates of time and cost for phases of natural-gas exploration. 

[Cost in thousands of dollars; cost includes direct consulting expenses only. not overhead expenses] 

Procedure Staff Time Cost 

Regional analysis---------- Geologists, geophysicists, 4 weeks $80 

and engineers. 

Prospect definition -------- Geologists and I week $15 

geophysicists. 

Land work------------------ Landman and staff-------------· 2 weeks $25 

Government permits------ Administration------------------· 9 weeks $15 

Drilling of a shallow well Wellsite and office geologic 5 weeks $400 

(includes drilling costs). staff, engineering staff, 

and support staff. 

Completion of a well Wellsite and office 2 weeks $200 

(includes treatment and engineering staff, and 

tangible costs such as support staff. 

casing and facilities). 

Pipeline hook up ---------- Noncompany personnel-------· 4 weeks N/ A 

Total----------------------------------------------------------------------------- $735 

well is productive, marketing contracts are negotiated with 

natural-gas purchasers and pipelines are built to transport 

the natural gas from the wellhead to end users. 

factors including scale of regional analyses, administrative 

and governmental procedures, depth to horizon, and pipeline availability. A summary of the exploration process is 

The process of exploring and developing natural gas shown in table 1. 

requires a team of trained professionals and their support 

staff. Additionally, an entire service industry exists to perform the physical work of drilling, testing, and producing 

natural gas. The necessary professionals are geologists, 

geophysicists, engineers, attorneys, and landmen. Exploration for natural gas is a time-intensive endeavor that begins 

with a geologic idea of where natural gas may be found and 

produced at a profit. 

The exploration process may require as much as 6 

months from the initial geologic idea to first sales of natural 

gas into the pipeline. This estimate is dependent upon many 

One prospect requires a team of professionals and support staff 6 months to finish or a year for a deep test. The 

drilling and completion costs for a deep test may be 10 

times those of a shallow well. This may result in a total 

project cost of $4.8 million. The geologic exploration phase 

is a relatively small expense compared to the drilling costs. 

An effective, thorough geologic evaluation can save a company millions of dollars in dry-hole costs. 

The complexity of the step by step procedure for the 

exploration and production of natural gas is summarized in 

figure 3. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Overview of the U.S. Department of Energy/Morgantown 

Energy Technology Center Natural Gas Program 

By Abbie W. Layne1 

CONTENTS 

Abstract .... ........ .... .. . ... .. .... .. .... .. . ... .. ....... .... .. .. ... .. ... ........ 685 

Background ................................................................... 685 

DOE/METC Role ......................................................... 686 

Program Elements . ... ................... ................. ... ..... .... ... . 687 

Resource and Extraction ........................................ 688 

Delivery and Storage ............................................. 688 

Utilization .............................................................. 688 

Environmental and Regulatory Impact .................. 688 

Program Direction ........................................................ 689 

Selected References ...................................................... 689 

ABSTRACT 

The m1ssJon of the U.S. Department of Energy's 

(DOE) natural gas program is to enhance the Nation's energy security, economic growth and efficiency, and enviro'nmental quality. This mission will be accomplished with 

the following: (1) by removing technical and( or) regulatory barriers to the expanded use of natural gas, (2) development of cost-effective and environmentally sound gas 

supply, storage, transmission, and utilization technologies, 

(3) improving competition, and (4) technology transfer. 

The Morgantown Energy Technology Center (METC) 

supports the DOE natural gas mission through research, 

development, and demonstration (RD and D) of gas supply and utilization technologies. Projects are structured to 

1

U.S. Department of Energy, Morga~town Energy Technology Cen-

"ter, PO Box 880 Collins Ferry Road, Morgantown, WV, 26507-0880. 

foster eventual industry commercialization of these technologies. In addition, METC's RD and D is integrated 

with projects and activities being sponsored by other funding organizations. Program goals include increasing user 

confidence in the long-term supply of natural gas, verification of adequate gas reserves, and development and commercialization of high-efficiency, cost-effective extraction 

and utilization technologies. METC's program includes 

gas utilization projects such as advanced gas turbine systems, fuel cells, and conversion of gas to liquid products. 

METC's vision for the year 2010 is the following: Gas 

recovery and low-cost environmental technologies will insure a reliable U.S. gas supply of at least 23 trillion cubic 

feet per year; advanced turbine systems operating on gas 

have been demonstrated in the utility market and are available commercially; fuel cells and small advanced combustion turbine systems supply a distributed power market 

with gas-fueled devices in the I to 50 megawatt electrical 

(MWe) range, whereas the 50MWe and larger size range 

are being commercialized in the large industrial and commercial cogeneration markets. 

BACKGROUND 

Recent studies show that the lower 48 States have a 

natural gas resource base of about 1,295 standard trillion 

cubic feet (Tcf), given continued research, development, 

and demonstration (RD and D) for the commercialization 

of advanced supply technologies, access to resources, and 

adequate delivery and storage systems (National Petroleum Council, 1992). Natural gas is plentiful in the United 

States, relatively inexpensive, and environmentally less 

damaging than any other fossil fuel. Despite these advantages, the demand for gas has fallen off between the early 

685 
686 THE FUTURE OF ENERGY GASES 

1970's and 1990. One,reason for the decline is a continuing Jack of confidence in the stability of future supply; this 

is a legacy of the curtailment years of the 1970's. In response to the shortages and curtailments of the mid1970's, the Power Plant and Industrial Fuel Use Act was 

enacted in 1978 as part of the National Energy Pl~n. The 

result was a production capacity surplus and a lack of 

long-term natural gas contracts. 

Gas usage is seasonal and this leads to underutilizatiO!J 

of pipelines and storage systems in off-peak times: Development of usage technologies which are nonseasonal could 

lead to better utilization of pipelines and possible gains in 

utilization and storage facilities. Currently, several Federal 

regulations are being reformed to promote greater use of 

natural gas. These will affect the way the transportation and 

delivery services of natural gas are priced. Legislative efforts are underway to provide transportation service equ1,1.l 

in quality for all gas supplies, whether customers purchase 

gas from the pipeline or from another supplier, and to allow 

expansion of natural gas into the power generation and 

commercial/industrial markets. These markets will help reduce the seasonal swings in natural gas usage and generate 

long-term natural gas contracts. 

Successful research in such areas as high-efficiency 

gas turbines, natural gas fuel cells for electric power generation, and conversion of natural gas to liquid transportation fuels will contribute to increased nonseasonal demand 

and decrease U.S. dependence on imported oil. Increasingly stringent environmental regulation (for example, control 

of nitrogen oxides (NOx), sulfur dioxide (SOz), parti~ulate, carbon monoxide (CO), and methane (CH4) emissions) and growth in the Nation's demand for electric 

power capacity will favor natural gas consumption. Demand increases of about 4 Tcf (from 19 Tcf in 1990 to 23 

Tcf) are envisioned by the 2000-2010 time period, with 

conventional gas resources (economic recovery in the 

$2.00 to $2.50 per million British thermal units price 

range (1990 dollars)) continuing to play a dominant role 

through the end of this century, while nonconventional gas 

resources capture an increasing share of the market (fig. 1). 

In Aprill992, the United States Department of Energy 

(DOE) "Natural Gas Strategic Plan and Multi-Year Program 

Crosscut Plan, fiscal year 1993-1998" was released (United 

States Department of Energy, 1992). This summarized tlie 

DOE natural gas strategy and RD and D programs. 

The overall DOE natural gas program is designed to 

(1) enhance U.S. energy security, environmental quality, 

and economic strength by increasing natural gas recovery 

and utilization, (2) develop, in conjunction with industry, 

improved gas technologies, (3) restore and maintain confidence in long-term gas supply, (4) provide competitive 

and cost-effective means of gas use in both new and existing markets, (5) contribute to the gas industry's advances 

in technologies and techniques for lowering underground 

natural gas storage and delivery costs, and (6) minimize 

environmental and regulatory barriers to efficient market 

operation. 

DOE/METC ROLE 

Morgantown Energy Technology Center (METC) 

p~ays an important role in development and implementation of the DOE natural gas strategy and RD and D program. In support of the DOE Natural Gas Strategic and 

Multi-Year Program Crosscut plans, METC's role is to 

manage RD and D projects, ensure that program elements 

comply with all applicable Federal, State, and local laws 

and regulations, and foster success of DOE's natural gas 

program by promoting cooperation of Federal, State, and 

local governments as well as the cooperation and support 

of the gas industry. 

Project management and planning is conducted in 

three program areas: (I) resource and extraction, (2) delivery and storage, and (3) utilization. Projects are maintained throughout a planning time frame to address and 

resolve strategic issues. Program objectives and goals are 

directed toward increasing user confidence in the longterm supply of gas and verification of adequate natural gas 

reserves and development and commercialization of highefficiency, cost-effective supply and utilization technologies. METC's gas supply and utilization technology RD 

and D projects are structured to foster eventual commercialization. of the technologies through cooperative, cofunded research with industry. 

Cooperation with industry is in the form of joint government/industry RD and D and technology transfer. 

Projects are cost shared with industry in a way that will 

give industry greater control over the projects. This encourages greater industrial participation and allows companies 

more freedom in managing projects. METC's programs are 

closely integrated with the programs of the Gas Research 

Institute (GRI), a major source of private sector funding for 

RD and D in gas related topics. GRI and DOE are cosponsoring RD and D in the areas of tight-sandstone recovery, 

well-bore drilling and stimulation, low quality gas upgrading, and gas atlases. METC also works with other industry 

organizations as well as individual companies. 

Another industry partner is the Electric Power Research Institute (EPRI), a consortium of electric utilities 

whose collective expertise covers a wide range of issues 

and technologies. 

Cooperative efforts continue with the National Petroleum Council (NPC). NPC has recently completed a comprehensive analysis of the potential for natural gas to 

make a larger contribu~ion to our Nation's energy supply 

(National Petroleum Council, 1992). 
OVERVIEW OF DOE/METC NATURAL GAS PROGRAM 687 

PROGRAM ELEMENTS 

There are four elements of the DOE natural gas program: (I) resource and extraction, (2) utilization, (3) delivery and storage, and (4) environmental/regulatory impact. 

Each program element has its own unique mission that 

contributes to the goals of the program. The overall mission is to enhance the Nation's energy security, environmental quality, and economic strength by increasing 

efficient use of natural gas. In support of ·this mission are 

program elements that will improve confidence in the continued availability of a long-term natural gas supply (resource and extraction area), provide more cost-effective 

and competitive means to use natural gas (utilization area), 

develop improved and less costly means of delivering and 

storing natural gas (delivery and storage area), and minimize barriers to efficient market operation by promoting 

cost-effective regulation based on improved environmental 

assessments and improving availability of low-cost wastemanagement and waste-minimization technology (environmental research/regulatory impact area). 

Detailed budgets and strategic plans are given in the 

DOE "Natural Gas Strategic Plan and Multi-Year Crosscut 

Program Plan, FY 1993-1998" (U.S. Department of Energy, 1992). The 1993 DOE natural gas budget request reflects the emphasis on utilization RD and D. The total 

1993 DOE natural gas budget was $157.6 million, with 

the following distribution among program sectors: (1) resource and extraction, 12.8 percent of total, (2) delivery 

and storage, 0.0 percent of total, (3) utilization, 84.5 percent of total, and (4) environmental and regulatory impact, 

2. 7 percent of total. 

35 Western Hemisphere and Algeria 

-Canada and Mexico (gas) 

II Tight formations 

- sands, shales, coals 

30 

25 

1.... 

ct:S 

Q) 

~ 20 

(.) 

I-

~ 15 

(!) 

10 

5 

• 35 Tct 

-Algeria (liquified natural gas) 

• 35 Tcf 

I 

Conventional 

natural gas 

700 Tcf 

consumed 

850 Tcf 

remaining 

• 375 Tcf 

Sustained level of 

supply= 23 Tcf/yr 

Expanded 

imports 

+ 0 Speculative 

resources 

+ 

Synthetic 

gas 

0~~--------~----------~----------~----------~~ 

1900 1950 2000 

Year 

2050 

Figure 1. Natural gas supply outlook projected to the year 2100. Tcf, trillion cubic feet; yr, year. 

2100 
688 THE FUTURE OF ENERGY GASES 

RESOURCE AND EXTRACTION 

The goal of the resource and extraction program is to 

enlarge and stabilize the domestic natural gas supply reserve 

base for a period of time adequate to increase public confidence in the long-term availability of affordable natural gas. 

The DOE offices involved in the resource and extraction program are the Office of Fossil Energy (FE) and the 

Office of Energy Research (ER). METC implements the 

program elements in which the Office of Fossil Energy is 

·involved. These include the resource and extraction categories of conventional gas, nonconventional gas, and environmental research. 

The resource and extraction program is divided into 

nine project areas: (1) secondary gas recovery (cosponsored 

by GRI to extract a greater percentage of gas-in-place from 

complex mature reservoirs), (2) gas database consolidation 

(gas atlas series covering the Appalachian Basin and northern Gulf of Mexico and consolidation of a database system), 

(3) low-quality gas (develop methods to clean up low-quality gas) (4) drilling, completion, and stimulation technology 

(development of drilling, completion, and stimulation tools 

for special reservoir applications), (5) fracture technology 

and diagnostics (cosponsored by GRI to conduct large-scale 

laboratory and field-based stimulation RD and D and natural-fracture prediction/detection/mapping, which includes 

testing and diagnostics), (6) recovery from low-permeability formations (cosponsored by GRI to develop and demonstrate tight-sands production technology), (7) fundamental 

geoscience research (long-range geoscience research conducted by the Office of Energy Research), (8) gas hydrates 

(to increase confidence in hydrate resources and reserves), 

and (9) deep sedimentary basin gas (to increase confidence 

in deep natural gas resources and reserves) as a long-term 

supply source. 

DELIVERY AND STORAGE 

The purpose of the delivery and storage program is to 

develop cost-effective expansion of storage capacity, enhanced deliverability, and increased end-user confidence in 

natural gas. It is divided into four basic areas: (I) capacity 

development, (2) delivery enhancement, (3) storage efficiency, and ( 4) storage/market opportunities. 

The DOE Offices involved in this program area are 

the Office of Fossil Energy, the Office of Energy Information Administration, the Office of Energy Research, the 

Office of Fuels Programs, and the Office of Policy, Planning, and Analysis. METC implements program elements 

in which the Office of Fossil Energy is involved. This includes all of the four basic areas. 

UTILIZATION 

The utilization program is the main focus of the DOE 

natural gas program with over 80 percent of total program 

funds supporting utilization technology RD and D. The utilization program consists of elements supported by the Office of Efficiency and Renewable Energy, the Office of 

Fossil Energy, and the Office of Energy Research. The primary focus is to develop high-efficiency, low-pollution 

technologies and to overcome obstacles to their adoption. 

P~oject areas are combustion systems, heat pumps, gas turbmes, natural gas vehicles, fuel cells, gas-to-liquids conversion, demand-side management, and integrated resource 

planning. METC implements the utilization research in-

.volving advanced gas turbines, fuel cells, and gas-to-liquids 

conversion technologies. 

The gas-turbine program is being conducted in cooperation with the Office of Efficiency and Renewable Energy and focuses on advanced gas-turbine systems for 

electric power production in the utility and industrial sectors. These systems will have ultrahigh efficiency, be cost 

effective, and have low NOx emissions. The program consists of four phases: (1) limited system scoping/feasibility 

studies, (2) critical component testing (3) testing of largescale components and integrated subsystems, and (4) system demonstration. · 

The fuel-cells program area focuses on development of 

fuel-cell technology for stationary power plants. Emphasis 

is placed on development and applications of fuel-cell 

power plants for use in electric utility, industrial, and commercial sectors with 50 to 60 percent efficiencies to provide economic and environmental benefits. The program 

consists of technology development, pilot scale plants, 

demonstration plants, and commercialization for molten 

carbonate and solid oxide fuel cell systems. 

Fuel cells and small advanced combustion turbine systems will supply a distributed power market with gasfueled devices in the I to 50 megawatt (MWe) electrical 

range, whereas the 50 MWe and larger size range are 

being commercialized in the large industrial and commercial cogeneration markets. 

The gas-to-liquids conversion program area is a multidisciplinary effort emphasizing the development of an economic, direct conversion process that will convert natural 

gas to higher value liquid fuels and thus provide a means 

of transporting gas from remote locations to the marketplace. Catalytic, noncatalytic, and biological conversion 

processes are investigated to develop better understanding 

and control of chemical reactions during conversion, enhance conversion rates and selectivity, and improve separation and recovery of the products. 

ENVIRONMENTAL AND REGULATORY IMPACT 

The environmental and regulatory impact program consists of projects related to environmental research, compliance and impact, and regulations. Specific project areas 

deal with natural gas production and end use, reduction of 
OVERVIEW OF DOE/METC NATURAL GAS PROGRAM 689 

environmental impacts, and the role of methane in global 

climate change. Natural gas production projects identify 

and resolve environmental and safety issues related to natural gas production. Lower cost environmental compliance 

techniques are developed with the environmental compliance and impact projects, whereas cost-effective technologies are developed with the environmental impact reduction 

projects. 

PROGRAM DIRECTION 

As of 1992, the DOE gas program has been restructured 

using a "systems approach," which includes all components 

of the gas system - resource and extraction, utilization, 

delivery and storage, and environmental/regulatory impact. 

DOE's role in natural gas will continue to evolve in 

fiscal year (FY) 1993, resulting in better delineation of appropriate areas for RD and D. Throughout 1993 and future 

years, a continued programmatic emphasis will be placed 

on utilization technology RD and D. DOE's strategic planning will be significantly influenced by the increasing pace 

of change in the gas industry. Industry cost sharing will 

increase as research moves from development to demonstration. Owing to funding constraints, DOE will target 

budget allocations to those project areas that provide maximum opportunity and benefits. 

DOE anticipates that the Natural Gas Strategic Plan 

and Multi-Year Program Crosscut Plans will reduce the 

technical risks for companies developing new technologies 

and for companies entering the marketplace. The development and dissemination of technical information and analytical capabilities can provide cost-effective benefits to 

industry that might not otherwise occur. 

For FY 1994, some programs will be modified or take 

new direction, such as those under the recovery from lowpermeability formations area; and the drilling, completion, 

and stimulation areas. The resources and extraction program will emphasize cost reduction of natural gas recovery technologies (for example, lower drilling costs and 

improved recovery techniques). Secondary gas recovery 

research will complete its shift from the Texas Gulf of 

Mexico sandstone reservoirs to a new geologic basin area 

(midcontinent deltaic sandstones) and reservoir classes in 

the other regions of the United States. 

The fracture technology and diagnostics program area 

related to natural fracture detection and mapping will complete the move from its initial data acquisition and processing tasks into data analysis and interpretation. 

The delivery and storage program will be aimed at increasing end user confidence in gas and improving its 

market opportunities. Program activities will focus on 

technologies leading to cost-effective expansion of storage 

capacity, storage efficiency, and enhanced deliverability. 

The program area will focus on an integrated RD and D 

approach to provide reliable deliverability systems for expanding markets such as the power and industrial sectors. 

The utilization program will continue to be emphasized in 1993 and in future years. This program focuses on 

developing advanced high-efficiency, low-pollution technologies for use in the gas industry and overcoming obstacles to their adoption. Some of these technologies include 

advanced high-efficiency turbines that will provide costeffective, low-emission technology for actual power and 

industrial electricity production. This will increase the 

market for natural gas and help reduce the seasonal changes in natural gas demand. Low-NOx combustion technology will receive special attention, whereas gas-to-liquids 

advances may help displace some imported oil in the 

transportation sector. Expansion of the zero-emissions 

fuel-cell program is aimed at using high-efficiency technology for both dispersed and central power applications. 

SELECTED REFERENCES 

National Petroleum Council, 1992, The potential for natural gas 

in the United States; executive summary: Washington, D.C., 

National Petroleum Council, 5 p. 

U.S. Department of Energy, 1992, Natural gas strategic plan and 

multi-year program crosscut plan, FY 1993-1998: U.S. Department of Energy/Office of Fossil Energy-0251 P, 176 p. 

---1993, Natural gas strategic plan and multi-year program 

crosscut plan, FY 1994-1999: U.S. Department of Energy/ 

Office of Fossil Energy-0251 P (Draft document to be released in summer of 1993). 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Alternative Development Strategies for Natural Gas 

By Emil D. Attanasi 1 

CONTENTS 

Abstract ..... .. ..... ... .. .... .... ...... ... ....... ........ .. .......... .. ...... ... . 691 

Introduction ................................................................... 691 

Worldwide Natural Gas Reserves ................................ 692 

Reserves, Production, and Consumption ....... .. . ..... 692 

Discoveries and Field Growth ....... .. .............. .... ... . 692 

International Gas Trade .. .... .. ........ .. . ..... .... .. . .. .... ... . 694 

Comparative Analysis of LNG and Gas-To-Liquids 

Conversion .................................................................... 696 

LNG Supply Project .............................................. 696 

Delivered LNG Costs ............................................ 697 

Gas to Synthetic Liquid Fuels Conversion ........... 698 

Summary and Implications for Gas-Development 

Strategies ....................................................................... 700 

References Cited ........................................................... 701 

ABSTRACT 

Significant increases in worldwide natural-gas consumption during the last decade indicate that gas is increasingly considered a valuable and economic commodity. 

A summary of worldwide natural-gas reserves, production, 

and consumption statistics shows that worldwide gas use is 

not resource constrained. Only 10 percent of the gas produced is traded internationally and less than 3 percent is 

converted to liquefied natural gas (LNG). LNG is the principal alternative to pipeline transport of gas. Herein, the 

risks and economic returns of producing and using LNG 

are compared to converting gas to synthetic liquid fuel. 

Huge front-end investments in liquefaction plants, special1

U.S. Geological Survey National Center MS 920, 12201 Sunrise 

Valley Dr., Reston, VA 22092-0001. 

ized LNG tankers, and regasification plants along with uncertainty associated with a highly concentrated buyers' 

market are significant downside risks for new market entrants. For the gas to synthetic liquids conversion alternative, the technological uncertainty dominates because unit 

costs of the products from commercial-scale plants must be 

competitive with the fuel products refined from crude oil. 

For either alternative, the energy policy of the host country 

must encourage and permit development of low-cost sources of gas. 

INTRODUCTION 

Worldwide demand for natural gas has increased by 

nearly 4 percent per year over the last decade. Natural gas 

is increasingly regarded as a valuable resource, rather than 

an unwanted byproduct of oil and condensate production. 

Major gas markets are concentrated in the industrialized 

countries of the Far East, Europe, and North America. 

Many markets are located far from lowest cost accumulations of gas resources. 

Many less developed countries are rich in natural resources, such as natural gas, but they lack a domestic market for these products. These countries often try to 

generate foreign exchange from their resources by supporting industries that will either develop and export these 

resources or utilize these resources locally when manufacturing products for export. While pipeline transmission is 

the least costly and most efficient method of gas transportation, the development of international pipeline networks 

is largely restricted by physical distances, rugged topography, bodies of water, huge initial capital requirements, as 

well as national security considerations. 

Gas can also be converted to liquid forms through either of two conversion processes. In liquid forms, it can be 

transported long distances in tanker-ships and traded internationally over the oceans. Liquefaction processes convert 

691 
692 THE FUTURE OF ENERGY GASES 

methane to liquefied natural gas. LNG is transported in 

specially engineered insulated tankers to remotely sited receiving terminals where the cargo is regasified. LNG liquefaction facilities and transportation systems have significant 

downside risks because large front-end investments are required to produce a product that has a very limited market. 

The alternative to LNG is conversion by chemical 

processes to synthetic liquid fuels. The economic incentives for converting gas to liquid fuels increase as the cost 

of crude oil increases. Higher costs for crude oil result in 

higher prices for crude-oil derivatives, such as distillate 

and residual fuel oils, and lead to wider disparities between 

the price per equivalent energy unit for gas and crude-oil 

products. When considering development of facilities to 

convert natural gas to synthetic liquid fuels, the principal 

economic uncertainty is whether unit-production costs will 

decline sufficiently as plant size and throughput increase 

and as process innovation increases efficiency. Synthetic 

fuels must, however, be competitive with the alternative 

refined oil products to be profitable. 

WORLDWIDE NATURAL GAS RESERVES 

RESERVES, PRODUCTION, AND CONSUMPTION 

From 1980 to 1989, worldwide consumption of natural 

gas increased at a rate of 3. 7 percent per year. Tpis growth in 

gas consumption is evidence that gas is increasingly regarded as an economic commodity. Because the economic value 

attributed to a resource largely determines the quantity and 

quality of resource data that are available, the information on 

gas occurrence and consumption have steadily improved 

along with the expanding international trade. 

350 

300 

250 

::; 

" >. ~ Middle East 

Data on reserves, current production, and cumulative 

production of natural gas for individual countries as of 

January 1, 1991, are presented in table l. Regionally, the 

distribution shows the following areas and associated 

shares of worldwide gas reserves: Eastern Europe (almost 

all in Russia), 34 percent; Middle East, 33 percent; North 

America, 10 percent; the Far East and Oceania, 8 percent; 

Africa, 6 percent; South America, 5 percent; and Western 

Europe, 4 percent. In contrast, North America has accounted for just over half of the world's past cumulative gas 

production, and Eastern Europe and North America together account for 60 percent of the world's natural-gas 

consumption (table 1). Eastern Europe, Western Europe, 

and the Far East had the largest absolute increases in gas 

consumption during the 1980's. Annual world gas consumption is still less than 2 percent of reserves; this statistic suggests that production is not resource constrained. 

DISCOVERIES AND FIELD GROWTH 

Estimates of annual gas discoveries expressed in 5-year 

averages for various areas are shown in figure 1. Since 

1965, the amount of gas reported discovered offshore in 

South America, Western Europe, Africa, the Middle East, 

and non-Communist Asia has exceeded gas discoveries onshore. These reported discoveries reflect the improved economic value associated with gas, that is, even higher cost 

offshore gas is becoming economically attractive. Although 

the graph shows a precipitous decline in the annual gas 

discovery rate in recent years, this decline is likely due, in 

part, to incomplete data on recent discoveries, especially in 

foreign areas. 

~ 2 

u 

:E 

" " 

200 c::=J Eastern Europe. Russia, and Asia 

!22Z1 Western Hemisphere. 

·c: !50 Africa. and Western Europe 

~ 

c: 

~ 

=:s 100 

= 

~ 

0 " 50 

1910 1930 1950 1970 1990 

Year 

Figure 1. World natural-gas discovery rate averages for 5-year periods from 1915 

to 1989. Annual production also· shown. Modified from Masters and others, 1991. 
ALTERNATIVE DEVELOPMENT STRATEGIES FOR NATURAL GAS 

Table I. Estimated production, reserves, and consumption of natural gas. 

[Tcf, trillion cubic feet; •, includes 1.26 Tcf for individual South American countries for which consumption statistics are unavailable; -, no statistic available; 

CIS, Commonwealth of Independent States] 

North America-----------------------

Canada--------------------------

Mexico -------------------------

United States------------------

South America-----------------------

Argentina-----------------------

Bolivia--------------------------

Brazil ---------------------------

Chile ----------------------------

Colombia-----------------------

Ecuador-------------------------

1990 Gas production 1 (Tcf) 

22.4 

3.8 

1.4 

17.2 

2.3 

0.8 

0.1 

0.1 

0.1 

0.1 

Peru----------------------------- 0.0 

Trinidad ------------------------

Western Europe----------------------

Italy-----------------------------

Netherlands--------------------

Norway-------------------------

United Kingdom --------------

Other----------------------------

Eastern Europe ----------------------

Romania------------------------

CIS------------------------------

Other ----------------------------

Africa ---------------------------------

A I g eri a--------------------------

Egypt ---------------------------

Gabon---------------------------

Libya----------------------------

Nigeria--------------------------

Tunisia--------------------------

Other----------------------------

Middle East --------------------------

Bahrain -------------------------

Iran------------------------------

Iraq------------------------------

Kuwait--------------------------

Oman ---------------------------

Qatar---------------------------

Saudi Arabia-------------------

Syria----------------------------

United Arab Emirates--------

Other ----------------------------

Asia/Oceania-------------------------

Afghanistan--------------------

Australia/New Zealand 

Burma --------------------------

China ---------------------------

India ----------------------------

Indonesia-----------------------

Malaysia/Brunei---------------

Pakistan ------------------------

Thailand-----------------------

Other----------------------------

World ---------------------------------

0.2 

7.0 

0.6 

2.6 

1.0 

1.7 

1.1 

30.4 

. 1.2 

28.8 

0.5 

2.2 

1.6 

0.3 

0.2 

0.1 

4.2 

0.2 

0.8 

0.1 

0.1 

0.3 

1.4 

1.1 

0.1 

5.1 

0.9 

0.5 

0.4 

1.4 

0.3 

0.4 

1.1 

73.7 

Cumulative production 

to 1991 2 

872.9 

81.6 

24.6 

766.7 

40.9 

11.0 

1.9 

2.0 

2.9 

2.6 

0.1 

l.l 

3.0 

134.0 

14.6 

57.1 

11.4 

26.4 

24.5 

437.3 

31.0 

387.1 

19.3 

34.6 

18.4 

1.8 

0.3 

6.0 

5.9 

0.1 

2.1 

61.6 

2.0 

18.4 

3.4 

5.6 

0.6 

3.2 

15.4 

1.5 

8.8 

2.6 

86.5 

1.0 

8.5 

2.2 

18.1 

2.2 

15.8 

5.3 

6.2 

29.2 

1667.9 

Reserves in Tcf1/1/91 

337.6 

96.7 

71.5 

169.3 

178.6 

20.5 

4.6 

4.1 

4.0 

4.2 

4.0 

7.1 

9.2 

225.7 

11.4 

69.5 

108.7 

19.2 

16.8 

1593.3 

3.7 

1575.9 

13.7 

289.8 

116.5 

10.9 

0.4 

43.0 

93.3 

3.1 

22.7 

1338.3 

6.1 

600.5 

109.7 

53.0 

10.0 

162.0 

184.2 

6.4 

186.6 

19.8 

363.2 

77.3 

5.1 

33.2 

21.1 

101.8 

65.5 

22.7 

14.5 

22.0 

4326.5 

1Twentieth Century Petroleum Statistics, 1991, DeGolyer and MacNaughton, Dallas, Texas. 

2M asters and others ( 1991 ). 

3Energy Information Administration, International Energy Annual, 1990. 

1990 Consumption3 in Tcf 

22.27 

2.47 

0.98 

18.82 

2.21 * 

0.83 

0.15 

0.17 

9.95 

1.67 

1.49 

0.07 

2.03 

4.69 

29.58 

1.44 

25.5 

2.64 

1.39 

0.69 

0.28 

0.17 

0.17 

0.06 

0.02 

3.72 

0.19 

0.82 

0.43 

0.10 

0.22 

1.09 

0.73 

0.14 

5.31 

0.72 

0.53 

0.33 

0.57 

0.31 

0.49 

2.36 

74.42 

693 
694 THE FUTURE OF ENERGY GASES 

Table 2. Estimates, in billion cubic feet, of ultimate recovery of cumulative gas discovered by region from 

1981 to 1990 as recorded by Petroconsultants, Ltd. 

Region 1981 

South America---------------------- 28,524 

Western Europe -------------------- 229,685 

Middle East------------------------- 628,045 

Africa-------------------------------- 134,299 

Non-Communist Asia------------- 83,972 

Total--------------------------- 1,104,525 

Another source of additions to proved gas reserves is 

from the field-growth phenomenon. In the United States 

and Canada, it has long been recognized that initial estimates of oil and gas field si_zes are conservative. Field-size 

estimates typically increase from the initial estimates as 

new discoveries are placed into production and fully developed. In the United States, from 1977 to 1988, for example, the estimates of oil and natural gas contained in 

pre-1978 discoveries increased by 21 billion barrels of oil 

(Bbo)-from 145 to 166, or 14 percent-and by 148 trillion cubic feet (Tcf) of natural gas-from 735 to 883, or 

20 percent-respectively (Energy Information Administration, 1990). 

Field growth is not unique to the United States and 

Canada. Petroconsultants, Ltd. provides quarterly estimates 

of the ultimate recovery of oil and gas for each field. Table 

2 shows Petroconsultants' estimate of the amount of gas 

contained in fields discovered between 1900 and 1980 in 

selected international regions. These data were computed 

from estimates made in 1981, 1984, 1987, and 1990 of pre1980-discovered field sizes. Comparison of the 1981 and 

1984 data indicates that many fields discovered before 1980 

were still unannounced as of 1981, and consequently, were 

unaccounted for in the 1981 data. By 1984, many more pre1980 field discoveries were confirmed and announced; 

these announcements led to significant differences between 

the 1981 and 1984 estimates. By 1987, however, pre-1980 

discoveries would then have been at least 8 years old and 

most should have been confirmed and publicly announced. 

The table shows the difference between the 1987 and 1990 

resource estimates for fields discovered before 1980. The 

difference of 790 Tcf represents a 41 percent increase in 

estimates of ultimate field recovery. Without the Middle 

East data, the difference in estimates is 213 Tcf, which 

represents a 29 percent increase over the 1987 estimates. 

This dramatic increase in estimates of gas resources in 

past discoveries is, in part, a result of the improved economics for natural gas. Whereas natural gas had previously 

been essentially discarded (vented or flared) as an unwanted byproduct of oil production, the development of applications for natural gas has increased its demand and 

Year 

1984 1987 1990 

59,757 80,920 116,228 

265,926 321,763 318,798 

846,308 1,174,011 1,753,278 

176,460 177,780 272,777 

175,745 168,100 254,622 

1,524,196 1,922,574 2,715,703 

economic value. Without the market and means of transporting gas, there had been little incentive to accurately 

measure or develop gas resources. There are several reasons for the generally conservative reserve estimates for 

both oil and gas fields. Initial reserve evaluations need only 

be detailed enough to determine a minimum field size that 

would justify an operator's investments in development 

drilling and production facilities. Penalties for reserve 

overestimation might include excessive expenditure on 

field development. These penalties are generally much 

greater than penalties for underestimation of reserves. 

Higher prices allow more intensive field development 

and also allow commercial development of lower quality 

reservoirs. 

INTERNATIONAL GAS TRADE 

The nature of gas transportation accounts for the contrast between the proportion of gas production that is traded internationally compared to that of oil. About 10 

percent of the gas produced each year is traded internationally whereas almost half of the oil produced is traded 

internationally. On an annual basis, Russia is by far the 

largest pipeline gas exporter (more than 3 Tcf), followed 

by Canada (1.3 Tcf), the Netherlands (1.2 Tcf), and Norway ( 1 Tcf). Less than 3 percent of the gas produced annually is traded in the form of LNG. Internationally traded 

LNG transactions for 1990 as reported by CEDIGAZ 

(1991) are shown in table 3. Japan leads importers with 

just over 64 percent of the worldwide LNG trade, whereas 

Indonesia accounted for about 41 percent of the worldwide LNG exports. Asia and Western Europe account for 

69 and 27 percent of the total LNG trade, respectively. 

Production of U.S. gas peaked in 1973 and gas shortages 

developed in the mid-1970's, after the crude-oil price increases of 1973. The shortages were particularly severe at the 

terminus of the domestic gas pipeline network, particularly 

in Northeastern States. Distrigas, a Cabot Corporation subsidiary, began receiving Algerian LNG at its terminal near 

Boston in 1971 to augment tight domestic supplies. Other 
Table 3. Estimates of international gas trade, in billion cubic feet, by liquefied natural gas (LNG) tanker in 19901

• 

[Export figures are boldface! 

Export 

North I I Import I Africa Middle East I America 

United States Algeria Libya Total Abu-Dhabi Australia 

North America ----------------------------- 87.2 87.2 

United States------------------------- 87.2 87.2 

Western Europe 582.1 43.8 625.9 

Belgium _______________________ : _______ 137.7 137.7 

France --------------------------------- 328.6 328.6 

Italy------------------------------------ 1.1 1.1 

Spain----------------------------------- 113.0 43.8 156.7 

United Kingdom--------------------- 1.8 

Asia/Oceania 48.0 3.2 3.2 113.0 139.1 

Japan----------------------------------- 48.0 3.2 3.2 113.0 139.1 

South Korea --------------------------

Taiwan---------------------------------

Total exports --------------------- 48.0 672.5 716.2 113.0 139.1 

1

Data from CEDIGAZ, 1991. 

Asia/Oceania 

Brunei Indonesia Malaysia Total 

42.5 941.3 303.9 1426.8 

42.5 829.2 303.9 1314.7 

108.7 108.7 

3.4 3.4 

42.5 941.3 303.9 1426.8 

Total LNG 

imports 

' 

87.2 

137.7 

328.6 

1.1 

156.7 

1.8 

1591.0 

1478.9 

108.7 

3.4 

2304.0 

:> 

Ci 

tT1 

~ 

~ :;:: 

tT1 

0 

tT1 

< tT1 

t""' 

0 

"0 

~ z 

>-l 

(ll 

>-l 

Cl 

~ m 

(ll 

'T1 

0 

~ 

z 

~ c:: 

~ t""' 

Cl 

:> 

(ll 

o--

\0 

U1 
696 THE FUTURE OF ENERGY GASES 

U.S. pipeline operators built terminals to receive Algerian 

LNG at Cove Point, Maryland (Columbia and Consolidated 

Gas), Elba Island, Georgia (Southern Natural Gas), and Lake 

Charles, Louisiana, (Trunkline-Panhandle Eastern). 

In the early 1980's, the Algerian suppliers tried to attain gas-price parity with oil by raising prices beyond what 

pipelines and utilities could recover from customers. Purchase contracts were canceled and all U.S. receiving terminals were mothballed as the operators underwent financial 

reorganization. With the improvement of natural-gas markets in 1990, Distrigas reopened its Boston terminal and 

the Lake Charles terminal reopened about a year later. The 

Algerian LNG supplier priced the gas on a "netback" basis. 

The netback pricing scheme obligated the supplier to accept a fixed percentage of the price received by the terminal from the gas purchaser. The current annual capacity of 

the operating and mothballed receiving terminals is 0.9 

Tcf. If all plants were expanded to their maximum capacity, 1.3 Tcf could be received annually. 

LNG production and export projects are best located in 

countries or regions with significant natural-gas resources 

and limited local gas demand, where the opportunity cost or 

in-situ value of the gas resource may be low. Host countries 

typically offer some subsidies (including favorable tax 

treatment) in exchange for equity positions in such projects. 

Because of the required large front-end capital investment 

and accompanying substantial downside risks, LNG 

projects are built only after most of the plant's output is 

committed to long-term purchase contracts. Contract prices 

may be indexed to prices for crude oil or a specified bundle 

of fuels at a specified delivery point. For example, Japanese 

import LNG contract prices are indexed to the price of 

imported oil. Indonesian LNG export prices are similarly 

tied to prices received for Indonesian crude-oil exports. 

For overseas LNG projects built to supply the Japanese 

market, the Japanese purchasers, electric utilities, typically 

use Japanese trading houses to link Japanese project financing with purchase commitments for Japanese-manufactured plant equipment. From the perspective • of the 

Japanese Government, the substitution of LNG gas for oil 

or coal in electrical power generation meets two national 

policy objectives; diversification of primary energy use and 

supply sources, and, in urban areas, the reduction of sulfur 

and carbon emissions from coal and petroleum consumption. Japanese LNG import policies do not provide inexpensive fuels for consumers, but the policies do appear to 

have accomplished the two policy objectives. 

COMPARATIVE ANALYSIS OF LNG AND 

GAS-TO-LIQUIDS CONVERSION 

LNG SUPPLY PROJECT 

LNG production systems consist of the following 

components: a source of natural gas, an LNG plant, port 

facilities, a tanker fleet, and a receiVmg terminal where 

LNG is regasified. To simplify the analysis, natural gas is 

assumed to be purchased by the plant operator and sold to 

the receiving terminal. The input gas, or feed gas, used in 

the process is assumed to be l billion cubic feet (Bcf) per 

day. A standard plant with three process trains, each designed to produce 2.2 million tonnes of LNG annually, 

will accommodate this quantity of input gas. 

Basic system cost components were initially developed by Chern Systems (Chern Systems, 1989) for the 

U.S. Department of Energy. These costs were updated 

using the end of year 1991 factors from Chemical Engineering's new plant-construction index published in the 

December 1992 issue. These direct investment cost estimates are the basis for computing indirect investment 

costs including construction overhead, engineering fees, 

process license fees, and an allocation for contingencies. 

All liquefaction processes for LNG production consist 

of a gas pretreatment step followed by successive stages 

during which the gas is eventually chilled to a liquid form at 

-262 °F ( -162.1 °C). Plant design and costs are well established and major cost reducing technological advances are 

not expected. Processes differ in terms of their basic refrigerants and pressures and are designed for specific operating 

conditions. Chern System's cost estimates are based on a 

generic LNG plant design. Locational cost adjustments reflect the level of industrial development in the host country. 

Plant configurations include the gas pretreatment process, the liquefaction process, utilities, storage and loading 

facilities, and marine facilities. Basic investment costs 

used in this analysis are presented for two host sites in 

table 4. Investment costs for site I represent costs that 

might be incurred in the Caribbean, Algeria, or the Arabian Gulf coastal areas. Costs associated with site II are representative of Nigeria or the coastal areas of Indonesia or 

Malaysia. Annual liquefaction plant operating costs exclusive of the feed gas costs for the two sites are also presented in table 4. Even at a price of $0.50 per million 

British thermal units (MMBtu), the feed gas costs account 

for about 75 percent of annual plant operating costs. 

Transportation is a large investment component of any 

LNG project. The transportation system consists of a number of special tanker ships to deliver the plant's liquid output. The number of tankers of standard-sized, 125,000 

cubic meters of LNG (equivalent to 2.67 Bcf, billion cubic 

feet, of gas), is based on the quantities required, the shipping distance from loading facilities to purchasers' receiving terminals, the average ship speed, and the number of 

days allowed for loading and off-loading cargo. As indicated by recent tanker orders, costs for new tankers have 

reached $260 million (Pastuhov, 1991). Tanker construction is assumed to take two years and the economic life of 

a tanker is assumed to be 20 years. 

To simplify this analysis, an assumption is made that 

the entire plant output is committed to a purchaser ser-
ALTERNATIVE DEVELOPMENT STRATEGIES FOR NATURAL GAS 697 

Table 4. Capital and operating cost estimates for representative 

liquefied natural gas plant. 

[Estimates in millions of dollars1 and based on I billion cubic feet of input per day] 

Capital investment cost 

Site I Site II 

Direct 

Gas pretreatment and liquefaction------------

Utilities and services ---------------------------

Storage, loading, and marine facilities-------

! n d irect2 -------------------------------------------

Contingency3 -------------------------------------

Fees4 ----------------------------------------------

Infras true ture -------------------------------------

Total investment cost---------------------

446 

435 

201 

379 

219 

168 

112 

1,960 

Annual production cost (exclusive of feed gas) 

Materials ------------------------------------------

Variable cost -------------------------------------

Overhead 

General and direct-------------------------------

Insurance ----------------------------------------

Annual operating cost--------------------

.4 

23.0 

15.2 

29.4 

68.0 

469 

457 

234 

406 

235 

180 

502 

2,483 

.4 

24.0 

15.9 

37.3 

77.6 

1

Cost from Chern Systems (1989) and updated to 1991 dollars. 2

Indirect costs include construction, overhead, and engineering fees. 

They are computed as 35 percent of direct costs. 3

Contingency computed as 15 percent of base plant cost, which is 

the total of direct and indirect capital investment cost 

4

Fees (and commissions) computed as 10 percent of base plant and 

contingency. 

viced by the receiving terminal at Cove Point, Maryland, 

located on the U.S. East Coast. Tankers are operated 340 

days per year, have an average steaming speed of 18.5 

knots, and are allowed 36 hours port time at both ends of 

the trip. Tankers are powered by boil-off LNG and boiler 

fuel oil. Boil-off LNG is methane that is generated from 

the vaporization of the cargo of LNG. Average daily boiloff LNG used for steaming is equivalent to 0.125 percent 

of the initial ship capacity. The fuel-oil requirement is 61 

tonnes per day during the trip and 41 tonnes per day while 

in port. Other annual operating costs are calculated as 

fractions of the ship's value (Vidas, 1988). 

DELIVERED LNG COSTS 

Several additional assumptions are made to calculate 

the total cost of LNG delivered to the Cove Point terminal. 

Costs presented herein are intended to represent resource 

costs. Taxes and inflation were ignored in this analysis. 

Further, the project was assumed to be financed entirely 

with equity investment and the required return to capital 

was assumed to be 15 percent. The productive life of the 

project is 20 years with an additional 5 years allowed for 

construction. The costs presented in table 4 were used as 

well as the transportation costing procedure discussed in 

the "LNG Supply Project" section. The sources of the LNG 

are assumed to be in the Caribbean, Algeria, and Nigeria. 

From these locations, ocean distances to Cove point are 

1900, 3685, and 5300 nautical miles, respectively. 

Assuming a feed gas cost of $0.50 per MMBtu and a 

required rate of return of 15 percent, liquefaction and 

transportation costs per MMBtu are $2.70, $3.22, and 

$4.07 for the Caribbean, Algerian, Nigerian producers, respectively. The transportation costs alone are $0.64, $1.11, 

and $1.54 per MMBtu, respectively. For these producers, 

transportation costs represent from 28 to 34 percent of the 

delivered LNG cost. The cost of delivery to a receiving 

terminal as a function of the required rate of return used in 

the discounted cash-flow analysis is shown in figure 2. 

Once delivered to the receiving terminal, the LNG must 

also be regasified before it can be sold to a pipeline or 

final purchaser. Costs associated with this component of 

the LNG system amount to about $0.50 per MMBtu and 

should be added to the costs shown in figure 2. 

Additional computations were made to determine the 

sensitivity of delivered costs to underlying model assumptions. For every 1 cent per MMBtu increase in the cost of 

the plant input feed gas, the landed cost of LNG increases 

by about 1.1 cents per MMBtu. For example, if the input 

feed gas cost increased from $0.50 to $1.00 per MMBtu the 

landed costs would increase to $3.25, $3.77, and $4.63, 

respectively. As rate of return on initial plant investment is 

increased (or decreased) by 20 percent, delivered cost 

would increase (or decrease) by about 8 percent. If the 

assumed productive life of the plant and tanker fleet were 

increased to 25 years from the assumed 20-year plant life, 

the delivered costs would decline by less than 2 percent. 

Alternatively, if the productive project life were shortened 

by 5 years, delivered costs increase by more than 8 percent. 

::::> 

f-

"' :;;: 

:;;: 

;;;; 

~ 

~ 

0 

u 

\J 

z 

..J 

"' 0) 

~ "' 

~ 0 

u 

UJ " 

::i "' 

10 

9 

8 

6 

5 

4 

2 

I 

0 

0 

EXPLANATION 

o Caribbean 

<> Algena 

X N1gcna 

4 6 I 0 12 14 16 18 20 22 24 26 28 30 

Required rate of return in percent 

Figure 2. Delivered cost of LNG (liquefied natural gas) in 1991 

U.S. dollars (per MMBtu, million British thermal units) to U.S. 

East Coast from the Caribbean, Algeria, and Nigeria as a function of the cost capital or nominal return to equity where the 

system includes liquefaction plant and facilities and tanker fleet. 

Cost based on input feed gas cost of $0.50 per MMBtu. 
698 THE FUTURE OF ENERGY GASES 

LNG imports generally represent a high cost or marginal gas supply source in places where there are indigenous 

supplies of gas. For example, in the U.S. wellhead gas prices for the first 6 months of 1992 averaged $1.52 per Mcf, 

pipeline imports averaged $1.95 per Mcf (million cubic 

feet), and city gate prices averaged $2.80 per Mcf (Energy 

Information Administration, Monthly Energy Review, 

1992). If the gas is principally delivered to residential and 

commercial consumers for space-heating applications, fluctuations in weather will cause significant fluctuations in gas 

demand. Even if imported LNG is used to generate baseload electricity, changing economic conditions will also 

introduce LNG gas-demand variability. The cost penalties 

associated with various levels of long-term excess plant 

capacity can be inferred from data shown in figure 3. For 

example, if the plant's average unused capacity is 25 percent over the plant's life, calculated delivered or landed 

costs of LNG increase by about 28 percent over the costs 

associated with full-capacity operation. If energy markets 

are competitive, the higher costs of LNG could reduce demand for the plant's output even further. 

Contract provisions have been used by producers to · 

manage the downside risks associated with projects that 

carry heavy front-end investments. To assure that transaction prices reflect current market conditions, "indefinitepricing" provisions are added to long-term contracts. An 

indefinite-pricing clause may tie gas contract prices to cost 

indices, prices of substitute sources of gas, or prices of 

crude oil or refined products. "Market-out price ceiling" is a 

contract provision that relieves the purchaser of contractual 

obligations when the contract price resulting from indefinite 

pricing clauses exceed some predetermined ceiling price. 

"Take-or-pay" contract provisions require the gas purchaser 

EXPLANATION 

o Caribbean 

o Algeria 

X Nigeria 

0 +---,----.---.---,---.---,---,----,-----~ 

0 10 15 20 25 30 35 40 45 50 

Unused capacity as percent of total capacity 

Figure 3. Delivered cost of LNG (liquefied natural gas) in 1991 

U.S. dollars (per MMBtu, million British thermal units) to U.S. 

East Coast from the Caribbean, Algeria, and Nigeria as a function of unused system capacity assuming a 15 percent cost of 

capital or required nominal return and input feed gas cost of 

$0.50 per MMBtu. 

to either take a specified quantity of production at the contract price or pay for contracted quantities not taken. This 

assures the producer a predictable stream of revenue regardless of market demand. 

Simulation experiments have been conducted to assess 

the effects of these three contract provisions on project 

profitability. A more detailed account of the experiments 

and results is given in Attanasi (1991). To summarize 

those results, when indefinite pricing contract clauses induce positive serial correlation (that is, when the values in 

a time series separated by one step are positively correlated) in transactions prices over the life of project, downside 

project risks are magnified. More specifically, if the indefinite price clause induces an increase in the serial correlation in the price distribution over the life of the project, 

the mean and median of the distribution of project returns 

are reduced while the variance increases. Market-out price 

ceilings tend to reduce the mean of the distribution of returns. Take-or-pay clauses, if set sufficiently high (above 

85 percent of plant capacity), can effectively shift the risk 

of demand variability to the purchaser (Attanasi, 1991). 

GAS TO SYNTHETIC LIQUID FUELS 

CONVERSION 

One alternative to LNG development of gas resources 

is chemical conversion of gas to liquid synthetic fuels. The 

general economic characteristics of the gas-to-liquid conversion systems are examined here, in the context of the 

Shell middle distillate synthesis (SMDS) process. This 

process converts natural gas to a mixture of liquid fuel 

products including gasoil, kerosene, diesel fuel, and light 

distillate fuels. A demonstration plant that will convert I 00 

Mcf per day of feed gas to 12,000 barrels of liquid fuels 

per day is scheduled for completion in 1993, in Bintulu, 

Malaysia (Shell Malaysia, 1989). Products from this process can be used in refineries to enhance feedstock quality 

or can be sold as liquid fuels. The apparent thermal efficiency of the plant is just over 62 percent. 

The SMDS process first converts natural gas into syngas (hydrogen and carbon monoxide). A modified version of 

the Fischer-Tropsch process reacts the syngas components 

to form long-chain paraffins using a special Shell catalyst. 

The long-chain paraffin molecules are then cracked (that 

is, broken into less complex compounds) under mild hydrocracking conditions. The final process, a fractionation 

process, splits the product stream into various component 

products. Because the initial component is natural gas, the 

final products are free of sulfur and particulates (Williams 

and Bekker, 1990). 

One of the few public studies on this process was prepared by Chern Systems (1990) for the Department of Energy. The standard size plant is assumed to produce 28,500 

barrels per day. Costs from that study were slightly modified 
ALTERNATIVE DEVELOPMENT STRATEGIES FOR NATURAL GAS 699 

Table 5. Capital and operating cost estimates for a gas to 

synthetic luquid fuel plant using the SMDS process. 

[SDMS, Shell middle distillate synthesis; estimates in millions of dollars 1 

and based on a 28,500 barrels of liquid per day output] 

Capital investment cost 

Site I Site II 

Direct 

Syngas sythesis 91 97 

Oxygen plant 134 143 

Fuel sythesis 276 296 

Gas processing 22 24 

Fractionation 38 41 

H ydrocracking 36 39 

Utilities 311 333 

Indirect2 227 243 

Contingency3 170 183 

Fees4 59 63 

Catalyst chemicals 24 24 

. Infrastructure 80 460 

Total capital investment 1,469 1,946 

Annual production cost (exclusive of feed gas) 

Variable cost 22.3 22.3 

Fixed cost 

Overhead 14.5 14.5 

Maintenance 35.9 38.4 

Insurance 19.6 21.0 

Annual operating cost 92.3 96.2 

1

Cost from Chern Systems (1990) and updated to 1991 dollars. 2

Indirect costs include construction, overhead, and engineering fees, computed as 38 percent of direct cost subtotal. 3

Contingency computed as 15 percent of base plant cost. 4

Fees (and commissions) computed as 4.5 percent of baseplant and contingency. 

and incorporated in one of the cases presented here (table 5). 

The Chern Systems costs appear to have been computed 

without reference to the process configuration used in the 

Shell demonstration plant. 

Additional details from Shell regarding the demonstration plant indicate that the $660 million estimate includes 

all utilities, ancillary facilities, and infrastructure. The 

plant represents one process train. Shell expects substantial scale economies when the process is scaled up. A 

commercial-size plant would require a scaling up of the 

process train and additional process trains (oral commun., 

1991, to C.D. Masters from P.L. Zuideveld of Shell Inc.). 

The chemical-process industries have historically experienced significant plant economies of scale. The decline 

in unit-capital costs per unit of installed capacity reflects 

economies of scale and results from economies of increased dimensions and plant indivisibilities. Indivisibilities are due to standard sizes of machinery and process 

trains. In the so-called scale-up relationship, Ia = Ib 

(Ca/Cb)n where I is investment cost, C is capacity, a and b 

signify different capacity plants, and the exponent n has 

been empirically demonstrated to be between 0.4 and 0.8 

(Axtell and Robertson, 1986, p. 21). Economies of scale 

also reduce operating costs. The capital and operating costs 

of a gas-to-liquid-fuel conversion plant will also decline as 

the industry develops operating experience. In other words, 

cost will be reduced by industry learning and further process innovation. For the chemical-process industries, cost 

reductions from industry learning and process innovations 

have exceeded cost reductions attributable to static scale 

economies (Chapman, 1991; Lieberman, 1984). 

The commercial-scale Chern System plant is 2.375 

times the plant capacity of the demonstration plant, whereas the Chern Systems plant costs are 2.88 times the Shell 

demonstration plant costs. Assume the Shell demonstration 

plant is scaled up to use 0.4 Bcf per day input feed gas 

and produces 48,000 barrels of product per day. If the exponential plant scale factor is 0.6, the scaled-up plant 

would require an investment cost of 2.30 times the demonstration plant cost. Alternatively, if the exponential scale 

factor were 0.4, the investment cost would be 1.74 times 

the cost of the demonstration plant. The differences in unit 

costs between the Chern Systems estimates and the estimates obtained by applying the scale-up factors that are 

typical of chemical process industries represent a wide 

range in uncertainty in future costs of gas-to-liquid conversion processes. 

For purposes of presentation, the plants with exponential factors 0.6 and 0.4 are denoted as scale-up A and scaleup B, respectively. Unit costs are expressed in terms of 

dollars per gallon because kerosene, aviation fuel, and 

other light distillate prices are quoted in those terms. The 

unit costs for a site I (Caribbean, Algeria, or Arabian Gulf 

coastal areas) plant based on an input gas cost of $0.50 per 

MMBtu are shown in figure 4. At a 15 percent required 

return, plant tailgate (without delivery) unit costs for the 

Chern System plant, scale-up A, and scale-up B are $1.09 

per gallon, $0.69 per gallon, and $0.61 per gallon of product, respectively. The unit costs for the site II (Nigeria, 

Malaysia, or Indonesia coastal areas) plants, assuming a 15 

percent required return, are 15 to 21 percent higher than 

the site I costs. If the input feed gas cost is increased by I 

cent per MMBtu, the output costs increase by about 0.2 

cents per gallon (about 7.5 to 8.5 cents per barrel depending on the process assumptions used). 

The principal reason for converting gas to liquid fuels 

is ease of transport. The SMDS plant output can be transported in vessels used to transport refined oil products. 

Transportation costs for refined products from Africa or 

the Caribbean to the United States represents only 1 to 2 

percent of the product costs. Output of individual plants 

represents a negligible part of the market and has little effect on prices. Consequently, the plant operator could reasonably be expected to sell all the plant's output at the 

prevailing market prices. To place the values of figure 4 in 

perspective, U.S. refinery prices for kerosene and number 

2 diesel oil in June 1992 were between $0.60 and $0.64 
700 THE FUTURE OF ENERGY GASES 

per gallon (Energy Information Administration, Monthly 

Energy Review, 1992). 

SUMMARY AND IMPLICATIONS FOR 

GAS-DEVELOPMENT STRATEGIES 

During the past decade, worldwide consumption of 

natural gas has increased by almost 40 percent. Although 

the transition of natural gas to an economic commodity is 

evident by the reported additions to reserves from new 

discoveries and by the continued growth of past discoveries, annual worldwide consumption remains less than 2 

percent of global reserves. About 10 percent of the gas 

produced is traded internationally, and less than 3 percent 

of the gas produced is converted to LNG. The high cost of 

transporting gas from areas where there is no local market 

is an obstacle to the expansion of gas development worldwide (fig. 5). 

An analysis comparing a representative LNG project 

to a gas-to-synthetic-liquid-fuels project was prepared. For 

the LNG project, the risks are associated with high frontend investment in the plant, a specialized LNG tanker 

fleet, and regasification systems. LNG markets are concentrated geographically and have few purchasers. Moreover, 

for many of these markets, LNG represents the high-cost, 

marginal gas source used only to meet peak demand. Contract provisions such as indefinite pricing, market-out price 

ceilings, and the take-or-pay contracts have been used to 

mitigate project risks. 

2.2 

_g " 1.8 -;; 

"' 1.6 ~ c. 

Jj 1.4 

0 

-o 1.2 .5 

~ 

0 

<..> 

" 0.8 ;; 

~ .§ 0.6 

" " 0.4 0:: 

0.2 

0 

0 4 6 

EXPLANATION 

o Scale-up plant A 

X Scale-up plant B 

o Plant C 

I 0 12 14 16 18 20 22 24 26 28 30 

Reqmred rate of return m percent 

Figure 4. Plant tailgate cost per gallon of commercial scale 

SMDS (Shell middle distillate synthesis) for a plant located in 

North Africa or the Caribbean. Plant C is based on the Chern 

Systems scale up to a 28,500 bbVd (barrels of liquefied natural 

gas per day) plant, plants A and B are based on the scale up of 

the demonstrations using exponential factors of 0.4 and 0.6, to a 

48,000 bbVd. Feed gas cost for all plants assumed to be $0.50 

per MMBtu (million British thermal units). 

For the gas-to-liquid fuels project, there is uncertainty 

about unit costs of output from a commercial-size plant 

and its competitive position with products refined from 

crude oil. If the unit costs of output of such plants follow 

the pattern of the chemical-process industry, there will be 

a dramatic decline in unit costs with increases in process 

scale, plant scale and industry experience. The cost of 

products from a mature, established industry could be 

competitive with the refined products made from crude oil. 

The viability of gas conversion projects will be dependent on the policies of the host country. Historically, 

nearly all of the LNG construction projects have had equity participation of the host government. The project's economic attractiveness depends on the availability of gas at 

very low unit costs and of few alternative uses for the gas. 

Assuming a 20-year plant life, the liquefaction complex 

will require gas resources of 8 to 12 Tcf (actual consumption will be 6.6 Tcf). Alternatively, 48,000 barrels per day 

gas-to-liquids conversion will require the commitment of 3 

to 5 Tcf (actual consumption will be 2.66 Tcf). 

Large natural-gas accumulations are located in countries that will require foreign capital and imported technology to develop the resource. International firms typically 

view the development options for natural gas as having 

limited profit potential. Where there are local gas markets, 

prices are often regulated and the markets are restricted by 

the amount of gas-using capital that is in place and the 

internal pipeline network. Often gas export via pipelines is 

confined to gas demand in neighboring countries. Gas producers face a tradeoff between technological uncertainty 

for the gas-to-liquid fuels conversion option and the large 

downside-market risk for an LNG project. With either option, the competitiveness of their product will be dependent on the tax treatment by the host country. 

1000 2000 3000 4000 5000 6000 7000 ROOO 9000 10000 11000 1:!000 

Nautical miles 

Figure 5. Estimated LNG (liquefied natural gas) transportation 

costs in dollars per MMBtu (million British thermal units) as a 

function of distance in nautical miles between plant and receiving terminal. 
ALTERNATIVE DEVELOPMENT STRATEGIES FOR NATURAL GAS 701 

The experience of the Australian North West Shelf 

Natural Gas LNG Project suggests that the results of government subsidies, that is, employment and generation of 

foreign exchange, can be mixed. The construction phase of 

the project induced inflation in Australia's capital goods 

industries, which ultimately reduced overall exports. The 

production phase resulted in an export surge, which led to 

deterioration in the competitive position of Australia's 

other export industries. Overall, the production phase led 

to an increase of about 1 percent in the county's gross domestic product (Higgs and Powell, 1992). 

From the host country's perspective there is a tradeoff 

in delaying gas development as opposed to encouraging 

early gas development through tax and subsidy policies. 

The economic value of gas resources appear to be appreciating. Because gas combustion produces only 70 percent of 

the carbon dioxide emissions of oil combustion, environmental concerns are inducing accelerated development of 

gas-using technologies. These technologies will encourage 

growth in the domestic and international gas markets. Furthermore, the gas-to-liquids conversion technologies can 

only improve as the demonstration plants gain operating 

experience. Alternatively, early development of gas resources will require infrastructure investments which, in 

tum, should stimulate additional gas-resource development. 

REFERENCES CITED 

Attanasi, E.D., 1991, Alternative natural gas contracts and pricing structures and incentives for the LNG industry, Natural 

Resources Forum, v. 15, no. 3, p. 190-201. 

Axtell, Oliver, and Robertson J.M., 1986, Economic Evaluation 

in the Chemical Process Industries: John Wiley, 256 p. 

CEDIGAZ, 1991, Natural Gas in the World: 1991 Survey, Centre 

International d'information sur le gaz nature! et tous hydrocarbures gazeux: Paris, 89 p. 

Chapman, Keith, 1991, The International Petrochemical Industry: 

Evolution and Location, Basil Blackwell, 322 p. 

Chern Systems, 1989, Assessment of costs and benefits of flexible and alternative fuel use in the U.S. transportation sector: 

Technical Report 3, Methanol Production and Transportation 

Costs, U.S. Department of Energy DOE/PE-0093, 46 p. 

Chern Systems, 1990, Synthetic Fuel Capital and Production 

Costs: Final Draft Report, Support Data and Analysis Provided to Alternative Fuels Supply Project, U.S. Department 

of Energy, Office of Policy Analysis, 80 p. 

Twentieth Century Petroleum Statistics, 1991, published by DeGolyer MacNaughton, Dallas, Texas, 126 p. 

Energy Information Administration, 1992, Monthly Energy Review, November, 158 p. 

Energy Information Administration, 1992, International Energy 

Annual-1990: U.S. Department of Energy DOE/EIA0219(90) 187 p. 

Energy Information Administration, 1990, U.S. oil and gas reserves by year of field discovery: U.S. Department of Energy DOE/EIA-0534, 137 p. 

Higgs, Peter J., and Powell, Alan A., 1992, Australia's North-West 

Shelf Gas Project: Resources Policy, September, p. 179-190. 

Lieberman, M.B., 1984, The learning curve and pricing in the 

chemical processing industries: Rand Journal of Economics, 

v. 13, no. 2, summer, p. 213-228. 

Masters, C.M., Root, D.H., and Attanasi, E.D., 1991, World resources of crude oil and natural gas: Proceedings, Thirteenth 

World Petroleum Congress, September 1991, Buenos Aries, 

Argentina, Session 25, p. 1-14. 

Pastuhov, Alexis, 1991, The safety and economics of VLLNG 

carriers: The LNG Observer, v. 1, no. 2, summer, p. 9-11. 

Shell Malaysia, 1989, Launch of Shell MDS Project: News Release (August 22), Shell Malaysia Kuala Lumpur, 3 p. 

Vidas, E.H., 1988, Costs for LNG Imports into the United States: 

prepared by Energy and Environmental Analysis Inc. for the 

Gas Research Institute, Washington, 30 p. 

Williams, J.R., and Bekker, G.A., 1990, Large-scale gas utilization: The Shell middle distillate synthesis process, Shell International Gas Ltd. London. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Survey of Natural Helium Occurrences 

By Dennis W. Hinnah1 and John E. Hamak1 

CONTENTS 

Abstract ........... : ............................................................. 703 

Introduction ................................................................... 703 

Historical Background ................................................... 703 

Helium Resources Evaluation ...................................... 705 

Methods of Analyses .................................................... 706 

Occurrences of Helium .... .. ... .. .............. ... ...... ...... .. .... ... 706 

Selected References ... .. .... .... ... .. ..... ..... .............. ... . ..... ... 707 

Appendixes .... .... . .. .... ....... ..... .. ..... .. . .. . ... ... .. ...... ..... .... ..... 708 

ABSTRACT 

This chapter describes the U.S. Bureau of Mines 

(USBM) natural gas survey for helium occurrences. Gas 

samples have been collected since 1917 from oil and gas 

wells and natural gas pipelines in 40 States and 26 foreign 

countries for helium analysis. The gas analyses were made 

by several different methods that have been developed over 

the years. 

INTRODUCTION 

Since 1917, gas samples from oil and gas wells and 

natural gas pipelines throughout the United States and 

other countries worldwide have been collected by the 

USBM in a continuing search for helium occurrences. 

Analyses of 15,583 of the samples, which were collected 

from 40 States and 26 foreign countries (tables 1 and 2), 

are available from the USBM (see appendix A). 

1

U.S. Bureau of Mines, Helium Field Operations, 801 S. Fillmore, 

Ste. 500, Amarillo, TX 79101-3545. 

The USBM is charged with the responsibility of ensuring a continuing supply of helium to meet essential 

Government needs, and this survey of the world's natural 

gas fields is made in connection with this responsibility. 

Most of these analyses have been published in USBM 

publications. The first of this series of publications was 

Bulletin 486 (Anderson and Hinson, 1951) and was followed by two more bulletins (Boone, 1958; Munnerlyn 

and Miller, 1963). These three publications contained data 

on analyses of 5,218 gas samples collected from the beginning of the survey through 1960. Data on gas analyses . 

since 1961 have been published on an annual basis, and 

35 Information Circulars have presented the analyses of 

10,365 gas samples collected through 1991. These analyses are also available on magnetic tape and 3.5-inch diskettes from the National Technical Information Service 

(see appendix B). 

The helium survey program is conducted by soliciting 

natural gas samples throughout the United States and from 

other countries with free market economies. Without the 

assistance of the oil and gas industry, State and National 

agencies, and many individuals engaged in oil and gas exploration and production, the present scope of the helium 

survey would have been impossible. 

HISTORICAL BACKGROUND 

The survey to locate helium occurrences throughout 

the United States has been carried on since the inception 

of the Government's helium program in 1917. A major 

goal of this program has been to conserve helium that 

would otherwise be wasted. Through 1991, more than 

19,200 gas samples have been collected and analyzed as a 

part of this survey. In addition to collecting samples from 

domestic gas fields, the search was expanded in 1965 to 

include foreign gas fields. Although several foreign samples had been analyzed prior to 1965, no active solicitation 

703 
704 THE FUTURE OF ENERGY GASES 

Table 1. Analyses of natural gases from gas and oil 

wells and pipelines in the United States. 

State 

Alabama----------------------

Alaska ------------------------

Arizona-----------------------

Arkansas ---------------------

California --------------------

Colorado ---------------------

Florida------------------------

Georgia-----------------------

Gas and oil 

wells 

91 

77 

88 

376 

212 

678 

5 

Idaho-------------------------- 23 

Illinois------------------------ 22 

Indiana ----------------------- 42 

Iowa -------------------------- 4 

Kansas------------------------ I ,464 

Kentucky --------------------- 1 09 

Pipelines 

17 

2 

2 

33 

107 

35 

0 

3 

0 

0 

0 

312 

Louisiana--------------------- 563 37 

Mary land--------------------- 9 1 

Michigan--------------------- 179 6 

Minnesota ------------------- 2 0 

Mississippi------------------- 135 30 

Missouri---------------------- 1 0 

Montana---------------------- 223 23 

Nebraska--------------------- 28 4 

Nevada ----------------------- 7 0 

New Jersey ------------------ 1 0 

New Mexico----------------- 800 80 

New York -------------------- 121 2 

North Carolina -------------- 2 0 

North Dakota---------------- 62 4 

Ohio -------------------------- 202 18 

Oklahoma-------------------- 2,533 101 

Oregon ----------------------- 10 0 

Pennsylvania ---------------- 215 13 

South Dakota---------------- 4 2 

Tennessee -------------------- 13 5 

Texas-------------------------- 4,033 489 

Utah--------------------------- 361 19 

Virginia----------------------- 21 1 

Washington ------------------ 12 3 

West Virginia---------------- 466 20 

Wyoming--------------------- 722 44 

---------------------- Total----------------------- 13,917 1,415 

of samples had been made. World War I caused a flurry of 

activity and interest in helium production. As a result of 

this interest, the Government's first helium extraction plant 

was constructed in Fort Worth, Tex., by the Department of 

the Navy to process gas from the Petrolia Field in Clay 

County, Tex. Many of the samples collected for the helium 

survey from 1917 through 1919 were analyzed for helium 

content only. 

A second phase of the helium sur-Vey was begun in 1919 

and continued until 1933. Samples collected during this 

period were analyzed by the Orsat combustion method and 

by a special helium apparatus. One result of this phase of 

the survey was the discovery of helium-rich gas at the 

Table 2. Analyses of natural gases from gas and oil 

wells and pipelines in Foreign Countries. 

Country Gas and oil wells 

Argentina -------------------- 12 

Australia --------------------- 22 

Austria -----------------------

Bangladesh ------------------ 0 

Bolivia ----------------------- 17 

Canada ----------------------- 60 

Colombia --------------------

Ethiopia ---------------------- 1 

Indonesia--------------------- 0 

Iran---------------------------- 1 

Iraq---------------------------- 3 

Italy--------------------------- 3 

Mexico----------------------- 21 

Netherlands------------------ 8 

Norway----------------------- 0 

Pakistan ---------------------- 5 

Peru --------------------------- I 

· Poland------------------------ 5 

Qatar-------------------------- 3 

Saudi Arabia----------------- 0 

South Africa----------------- 1 

Spain -------------------------

Taiwan------------------------ 12 

Thailand---------------------- 5 

United Kingdom------------ 3 

Pipelines 

2 

3 

0 

1 

0 

27 

3 

0 

4 

0 

0 

0 

10 

2 

1 

0 

0 

0 

2 

0 

0 

0 

5 

Germany 1 -------------------- 3 0 

-------------------- Total----------------------- 189 62 

I Fonner West Gennany 

Cliffside Field in Potter County, Tex. The Government 

acquired the gas rights in fee in the Cliffside Field and 

subsequently built a second Government-owned helium extraction plant near Amarillo, Tex., to process this gas. This 

plant was built by the USBM in 1928-29, after the supply of 

gas to the plant at Fort Worth was nearly depleted. 

The helium survey was relatively inactive from July 

1933 to April 1941, when World War II began to create an 

increased demand for helium. The survey was intensified 

during the war and resulted in the location of sites for four 

new helium plants in Kansas, New Mexico, and Texas. 

These plants were built in 1943-44. After World War II, 

the production capacity of the five plants was greater than 

postwar demand. Because of the excess capacity and a 

dwindling helium-rich gas supply, the Cunningham, Kan., 

plant was dismantled; and the Otis, Kan., and Shiprock, N. 

Mex., plants were placed on standby. The Amarillo, Tex., 

plant operated intermittently from 1945 through 1951, 

whereas the Exell, Tex., plant operated continuously. 

In 1951, an increasing demand for helium made it necessary to put the Otis, Kans., plant back into production. 

The Shiprock, N. Mex., plant resumed operations in 1953. 

Both of these plants were operated continuously until 1968, 

except for a shutdown of almost a year at Shiprock owing 

to gas supply problems. In 1968, when the USBM sales of 
SURVEY OF NATURAL HELIUM OCCURRENCES 705 

helium decreased markedly, both plants were shut down 

permanently. The Otis plant was sold, and the Shiprock 

plant was deeded to the Bureau of Indian Affairs, which 

turned it over to the Navajo Nation. 

In the 1940's and 1950's, a major helium-rich gas 

source was being developed in the Oklahoma panhandle: 

The Keyes Field was discovered in 1943, and gas samples 

from wells in the field contained an average of about 

2 percent helium. In 1958, the USBM obtained the exclusive helium-processing rights to most of the gas for the life 

of the field. An extraction plant was built near Keyes, Okla. 

to process Keyes Field gas. The plant began operations in 

1959, but ceased gas processing in 1981 because of declining gas supplies and excessive cost of operation. The Amarillo plant ceased gas processing operations in April 1970. 

In September 1971, the Exell plant stopped processing 

West Panhandle Field, Tex., gas, its source of supply since 

it began operation. Exell now supplies all demand for 

USBM helium by purifying helium that was purchased and 

stored by the Government in the Cliffside Field. 

In the early 1960's, demand for helium for Government programs continued the growth that started in 1951, 

while the helipm-rich gas resources declined. Because of 

this decline, Congress passed legislation in 1960 authorizing a helium-conservation program and promoting the 

growth of a private helium industry. The objective of this 

program was to store for future use about 52 Bcf (billion 

cubic feet) of helium that would have otherwise been lost 

as the natural gas was used for fuel. To implement this 

program, four long-term contracts were negotiated with 

private firms for the Government's purchase of helium; 

these contracts obligated the Government to purchase up 

to $47.5 million per year of helium. Five private extraction 

plants were built adjacent to large natural gas transmission 

lines in Texas and Kansas. Most of the gas processed was 

produced from the West Panhandle Field of Texas and the 

Hugoton Field in Texas, Oklahoma, and Kansas. These 

two fields contained the largest known helium reserves in 

the world. Previous helium resources evaluation work by 

the USBM had established that this area was the most 

promising source for the recovery of helium. Minor volumes of gas were produced from smaller fields in the 

same area. The extracted helium was stored in the Government-owned Cliffside Field. This is the helium now being 

purified by the USBM to supply current demand. Through 

November 1973, when acceptance of helium under these 

contracts ceased, 34.2 Bcf of helium had been stored. As 

of January 1, 1992, helium stored in the Cliffside Field 

totaled 33.8 Bcf. Of this volume, 1.7 Bcf is stored by the 

USBM for private companies. In addition to the stored helium, the remaining native natural gas in Cliffside Field 

contains about 3.9 Bcf of helium. Helium is measured at a 

pressure and temperature base of 14.7 psia and 70°F. 

HELIUM RESOURCES EVALUATION 

Even though helium resources are more than adequate 

to supply Government needs at present and for some time 

in the future, the helium resources evaluation program is 

continued so that resources can be located that may be required to supply future demands. Experience shows that it 

takes about 15 years from the time of discovery to the 

time of exploitation of a helium resource. Of particular interest are reserves of helium found in natural gases with 

low heating values. This natural gas is not as likely as 

higher heating-value gases to be produced for fuel; therefore, the helium is effectively "stored" and will be available for extraction when the need arises. These resources 

are classified as "nondepleting helium reserves" and serve 

as a backup to the helium stored in the Cliffside Field. 

Many of these nondepleting helium reserves are located on Federal lands, and under the standard U.S. Government oil and gas lease, helium ownership is reserved to 

the Federal Government. These reserves are, therefore, 

under Federal control, and although a lessee may produce 

the gas with which the helium is associated, the Government has an option to extract, or have extracted, the helium contained in the gas. 

When the helium survey was expanded to include foreign gas fields in 1965, it was believed that with the growing importance and use of helium, it was necessary to 

acquire reasonably detailed and documented knowledge of 

the helium resources outside the United States. Approximately 250 samples from 26 foreign countries have been 

received to date. 

The helium resource evaluation program has been carried on in varying degrees of intensity for over 70 years. 

Gas samples from most natural gas fields in the United 

States and from a few fields in foreign countries have been 

analyzed. Although many of the U.S. gas fields in the area 

of the Gulf of Mexico have not been sampled for the survey, all major transmission lines carrying gas from that 

area have been sampled. The helium resource evaluation 

program has accomplished its purpose in that it has identified the helium reserves and resources from which demand 

continues to be fully supplied. The evaluation is an ongoing USBM program, which. has the objective of locating 

adequate supplies to meet future demands. 

The results of some of the analyses made in connection 

with this program are not included in publications. Some 

reasons for exclusion of analyses are air contamination 

above permissible levels, incomplete analysis, and maintaining the confidentiality of data that were not released by 

the company supplying the gas sample. This confidentiality 

is promised to each company when it is contacted for a gas 

sample; however, most data are subsequently released for 

publication or public presentation by the company. 
706 THE FUTURE OF ENERGY GASES 

Table 3. Examples of gas-well-sample analyses from the United States. 

[--,not available] 

State---------------------------------------- Colorado 

County------------------------------------- Kit Carson 

Field---------------------------------------- Smoky Hill 

Well name--------------------------------- Lowe No. B-1 

Location ----------------------------------- Sec. 6, Til S, R45W 

Owner-------------------------------------- TXO Production 

Completed--------------------------------- 89/--/--

Sampled ----------------------------------- 89/02/24 

Formation ---------------------------------

Age-----------------------------------------

Geologic province code-----------------

Depth (ft)----------------------------------

Wellhead pressure (psig)----------------

Open flow (Mcfd)------------------------

Component (mole percent): 

Methane-----------------------------

Ethane -------------------------------

Propane------------------------------

N-Butane----------------------------

Isobutane ----------------------------

N-Pentane---------------------------

Isopentane---------------------------

Cyclopentane -----------------------

Hexanes+ ---------------------------

Nitrogen-----------------------------

Oxygen------------------------------

Argon--------------------------------

Hydrogen----------~---------------­

Hydrogen sulfide-------------------

Carbon dioxide---------------------

Helium-------------------------------

Heating value (Btu)----------------------

Specific gravity (relative to air)--------

Morrow Formation 

Pennsylvanian 

540 

Not given 

770 

Not given 

16.3 

1.5 

1.0 

0.4 

0.2 

0.1 

0.2 

0.0 

0.1 

74.1 

1.0 

0.3 

0.2 

0.0 

0.5 

4.14 

257 

0.890 

METHODS OF ANALYSES 

Gas mixtures received for helium evaluation are contained either in glass bottles at atmospheric pressure or in 

pressurized steel cylinders. They are analyzed with the 0 

to 10 percent helium/hydrogen gas chromatograph and a 

mass spectrometer. Mass spectrometer results are normalized with respect to the helium and hydrogen values determined on the chromatograph. The specific gravity and 

heating values of the gas are also calculated (see table 3). 

Hydrogen sulfide is significantly soluble in water, and 

most samples are collected by water displacement. This 

reactive gas can also be adsorbed in the walls of the container, tubing, and valves; this results in some unreliability 

in the hydrogen sulfide analyses. Other percent-level components are relatively unaffected by these problems. 

The percent-level components in each analysis are reported to the nearest 0.1 percent, except for helium, which 

Mississippi 

Holmes 

Tchula Lake 

Shad. Dav., Jr., No. 1 

Sec. 8, T15N, R1W 

Triad Oil and Gas Co. 

87/03/07 

87/07115 

Smackover Formation 

Jurassic 

210 

9,832 

2,835 

4,639 

41.6 

5.5 

3.1 

2.0 

1.7 

0.7 

0.6 

Trace 

0.3 

2.1 

0.0 

Trace 

Trace 

0.0 

42.3 

O.QJ 

796 

1.122 

Texas 

Hansford 

Morse SW 

Womble No.3 

Sec. 27, Blk 3 

J.M. Huber 

90/05110 

90110/--

Wichita-Albany 

Permian 

360 

30,178 

342 

2,200 

71.4 

7.5 

4.1 

1.2 

0.2 

0.1 

0.1 

0.0 

0.0 

14.1 

0.0 

0.2 

Trace 

0.0 

0.0 

1.02 

1,020 

0.713 

is reported to the nearest 0.01 percent. The word "trace" is 

used to denote detectable levels of helium less than 0.005 

percent and similar levels of other components less than 

0.05 percent (see table 3). 

OCCURRENCES OF HELIUM 

The data base includes geologic province codes so that 

each sample source can be located within a specific geologic province as defined by the Committee on Statistics of 

Drilling of the American Association of Petroleum Geologists. This information was added in Information Circular 

8749 (Moore, 1977) and is included with all analyses in 

the subsequent publications, tapes, and diskettes. These 

provinces, which are shown in the USBM publications 

with an accompanying list, are delineated by political 

boundaries for convenience and for the accommodation of 
SURVEY OF NATURAL HELIUM OCCURRENCES 707 

data processing equipment. Not all of the provinces shown 

are gas-producing areas, so many of the codes are not used 

in the publications. In offshore areas, only one code is used 

for each State because State or Federal ownership is not 

always known. Only one code, 972, is used for all wells in 

Alaska, both onshore and offshore, because of the lack of 

information on the location of wells in this State. 

Nearly all natural gas contains measurable amounts of 

helium. The average helium content of all samples received by the USBM is about 0.27 percent. This average 

is weighted heavily by the samples from helium-rich 

Hugoton and Panhandle Fields of Kansas, Oklahoma, and 

Texas. In general, reservoirs of Paleozoic age are more 

likely than other reservoirs to contain helium-rich natural 

gas. If the natural gas is helium rich, there will almost 

certainly be a nitrogen concentration of greater than 5 percent, but the presence of nitrogen doesn't necessarily indicate a helium-rich natural gas. Other less distinct 

interrelationships between helium and other elements can 

be found in Report of Investigation 8444 (Tongish, 1980). 

SELECTED REFERENCES 

Anderson, C.C., and Hinson, H.H., 1951, Helium-bearing natural 

gases of the United States; analyses and analytical methods: 

Bureau of Mines Bulletin 486, 141 p. 

Boone, W.J., Jr., 1958, Helium-bearing natural gases of the United States; analyses and analytical methods; supplement to 

Bulletin 486: Bureau of Mines Bulletin 576, 117 p. 

Cardwell, L.E., and Benton, L.F., 1970, Analyses of natural gases, 

1968: Bureau of Mines Information Circular 8443, 169 p. 

---1970, Analyses of natural gases, 1969: Bureau of Mines 

Information Circular 8475, 134 p. 

---1971, Analyses of natural gases, 1970: Bureau of Mines 

Information Circular 8518, 130 p. 

---1972, Analyses of natural gases, 1971: Bureau of Mines 

Information Circular 8554, 163 p. 

---1973, Analyses of natural gases, 1972: Bureau of Mines 

Information Circular 8607, 104 p. 

Hamak, J.E., and Gage, B.D., 1992, Analyses of natural gases, 

1991: Bureau of Mines Information Circular 9318, 97 p. 

Hamak, J.E., and Sigler, S.M., 1989, Analyses of natural gases, 

1988: Bureau of Mines Information Circular 9225, 66 p. 

---1990, Analyses of natural gases, 1989: Bureau of Mines 

Information Circular 9256, 60 p. 

---1991, Analyses of natural gases, 1990: Bureau of Mines 

Information Circular 9290, 56 p. 

---1991, Analyses of natural gases, 1986-90: Bureau of 

Mines Information Circular 9301, 315 p. 

Hertweck, P.R., Jr., and Fox, D.D., 1984, Analyses of natural gases, 1983: Bureau of Mines Information Circular 8993, 127 p. 

Miller, R.D., and Hertweck, P.R., Jr., 1982, Analyses of natural 

gases, 1981: Bureau of Mines Information Circular 8890, 84 p. 

---1983, Analyses of natural gases, 1982: Bureau of Mines 

Information Circular 8942, 100 p. 

Miller, R.D., and Norrell, G.P., 1964, Analyses of natural gases 

of the United States, 1961: Bureau of Mines Information 

Circular 8221, 148 p. 

---1964, Analyses of natural gases of the United States, 

1962: Bureau of Mines Information Circular 8239, 120 p. 

---1965, Analyses of natural gases of the United States, 

1963: Bureau of Mines Information Circular 8241, 102 p. 

Moore, B.J., 1974, Analyses of natural gases, 1973: Bureau of 

Mines Information Circular 8658, 96 p. 

---1975, Analyses of natural gases, 1974: Bureau of Mines 

Information Circular 8684, 122 p. 

---1976, Analyses of natural gases, 1917-1974: Bureau of 

Mines Computer Printout, National Technical Information 

Service Publication 251 202, 889 p. 

---1976, Analyses of natural gases, 1975: Bureau of Mines 

Information Circular 8717, 82 p. 

---1977, Analyses of natural gases, 1976: Bureau of Mines 

Information Circular 8749, 94 p. 

---1978, Analyses of natural gases, 1977: Bureau of Mines 

Information Circular 8780, 95 p. 

---1979, Analyses of natural gases, 1978: Bureau of Mines 

Information Circular 8810, 113 p. 

---1980, Analyses of natural gases, 1979: Bureau of Mines 

Information Circular 8833, I 00 p. 

---1981, Analyses of natural gases, 1980: Bureau·of Mines 

Information Circular 8856, 236 p. 

---1982, Analyses of natural gases, 1917-1980: Bureau of 

Mines Information Circular 8870, 1,055 p. 

Moore, B.J., and Hamak, J.E., 1985, Analyses of natural gases, 

1984: Bureau of Mines Information Circular 9046, 102 p. 

Moore, B.J., Miller, R.D., and Shrewsbury, R.D., 1966, Analyses 

of natural gases of the United States, 1964: Bureau of Mines 

Information Circular 8302, 144 p. 

Moore, B.J., and Shrewsbury, R.D., 1966, Analyses of natural 

gases of the United States, 1965: Bureau of Mines Information Circular 8316, 181 p. 

---1967, Analyses of natural gases of the United States, 

1966: Bureau of Mines Information Circular 8356, 130 p. 

---1968, Analyses of natural gases, 1967: Bureau of Mines 

Information Circular 8395, 187 p. 

Moore, B.J., and Sigler, S.M., 1986, Analyses of natural gases, 

1985: Bureau of Mines Information Circular 9096, 182 p. 

---1987, Analyses of natural gases, 1917-1985: Bureau of 

Mines Information Circular 9129, 1,197 p. 

---1988, Analyses of natural gases, 1986: Bureau of Mines 

Information Circular 9167, 101 p. 

---1988, Analyses of natural gases, 1987: Bureau of Mines 

Information Circular 9188, 74 p. 

Munnerlyn, R.D., and Miller, R.D., 1963, Helium-bearing natural 

gases of the United States; analyses; second supplement to 

Bulletin 486: Bureau of Mines Bulletin 617,93 p. 

Tongish, C.A., 1980, Helium-tts relationship to geologic systems and its occurrence with the natural gases, nitrogen, carbon dioxide, and argon: Bureau of Mines Rl 8444, 176 p. 
708 THE FUTURE OF ENERGY GASES 

APPENDIX A. PUBLICATIONS AVAILABLE FROM THE BUREAU OF MINES RELATED 

TO NATURAL GAS ANALYSES AND HELIUM RESOURCES 

Unless otherwise noted, all publications are information circulars (IC). 

Natural Gas Analyses 

IC 9129, Analyses of natural gases, 1917-85 

IC 9167, Analyses of natural gases, 1986 

IC 9188, Analyses of natural gases, 1987 

IC 9225, Analyses of natural gases, 1988 

IC 9256, Analyses of natural gases, 1989 

IC 9290, Analyses of natural gases, 1990 

IC 9301, Analyses of natural gases, 1986-90 

IC 9318, Analyses of natural gases, 1991 

Helium Resources 

IC 9130, Helium resources of the United States, 1985 

IC 9189, Helium resources of the United States, 1987 

IC 9267, Helium resources of the United States, 1989 

IC 9342, Helium resources of the United States, 1991 

These publications are available from: 

U.S. Bureau of Mines 

Publication Distribution Section 

626 Cochran's Mill Road 

P.O. Box 18070 

Pittsburgh, PA 15236 

Phone: (412) 892-4338 

OR 

Helium Field Operations 

801 South Fillmore, Suite 500 

Amarillo, TX 79101-3545 

Phone: (806) 376-2652 

APPENDIX B. PUBLICATIONS AVAILABLE FROM THE NATIONAL 

TECHNICAL INFORMATION SERVICE RELATED TO NATURAL GAS ANALYSES 

AND HELIUM RESOURCES 

In addition to the information circulars, all released analyses of natural gases can be obtained on magnetic tape and 

diskettes. The following are available: 

ORDER NO. TITLE PRICE 

PB92-501337 Magnetic tape of Analyses of natural gases, 1917-1991 $240 

PB92-503358 Diskette, Analyses of natural gases, 1917-1991 $360 

PB92-503333 Diskette, Analyses of natural gases, foreign $55 

countries, 1951-1991 

PB92-503358 Diskette, Analyses of natural gases, Alaska, $55 

California, Idaho, Nevada, Oregon, and Washington, 

1951-1991 

PB92-503325 Diskette, Analyses of natural gases, 1917-1950 $55 

PB92-503408 Diskette, Analyses of natural gases, Mid-Continent $55 

Region, 1951-1991 

PB92-503382 Diskette, Analyses of natural gases, Texas, other $55 

than District 10, 1951-1991 

PB92-503390 Diskette, Analyses of natural gases, Oklahoma and $55 

Northwest Arkansas, 1951-1991 

PB92-503374 Diskette, Analyses of natural gases, Texas, $55 

District 10, 1951-1991 

PB92-503366 Diskette, Analyses of natural gases, miscellaneous $55 

States, 1951-1991 

PB92-503341 Diskette, Analyses of natural gases, Rocky Mountain $55 

Region, 1951-1991 

The above are available from the National Technical Information Service, Springfield, VA 22161, telephone No. 1-

800-553-NTIS (in Virginia and outside the United States call 703-437-4650). The tape and diskette containing all analyses 

are updated annually. The other diskettes are updated every 5 years. In addition, a diskette of the previous year's analyses 

will be made available each year. Each diskette contains an ASCII file of the gas analyses, a DBASE IV template, and 

documentation. For more information or to get updated tape numbers, call 806-376-2650. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Methods of Gas Analysis 

By David E. Emerson 1 

CONTENTS 

Abstract ········································································· Introduction .................................................................. . 

Sampling Procedures ................................................... . 

Atmospheric Air .................................................... . 

Pressurized Gases ·················································· Soil Gases ............................................................. . 

709 

709 

709 

709 

710 

710 

Water Containing Dissolved Gases ....................... 710 

Calibration Standards ................................................... 710 

Weighed Standards ................................................ 710 

Certified Standards ................................................. 710 

Mass Spectrometry Methods . ...... ... ... . . ... .. . . ..... ..... .. ..... . 710 

Percent-Range Analysis ......................................... 710 

Trace Impurities in Helium Analysis .................... 711 

Analysis of Helium from 0 to 10 Percent ............. 711 

Isotopic Analysis .................................................... 711 

Chromatography Methods . .... ...... .... .. . .... .. ...... ............ .. 711 

Analysis of Helium and Hydrogen from 

0 to 10 Percent ....................................................... 711 

Percent-Range Analysis ......................................... 711 

Hydrocarbon Analysis ............................................ 712 

Moisture Analysis .................................................. 712 

Hydrogen Sulfide Analysis .................................... 712 

Analysis in the Low Parts-Per-Million Range ...... 712 

Special Analyzers ......................................................... 712 

Analysis of Helium from 1 to 100 Percent .... ....... 712 

Fourier Transform Infrared Analysis . . ... ..... ... .. ... . . . 713 

Summary ....................................................................... 713 

References Cited ....... ..... .................. ............... ...... ... ..... 713 

1

U.S. Department of the Interior, U.S. Bureau of Mines, Helium 

Field Operations, Amarillo, TX 79101. 

ABSTRACT 

Methods for sampling, calibrating, and analyzing for 

helium, impurities in helium, and natural gases are described. These methods were developed by the U.S. Bureau of Mines to assist in the processing of natural gas for 

helium recovery. 

INTRODUCTION 

By developing methods such as those described 

below, the U.S. Bureau of Mines provides technical assistance in processing natural gas for helium recovery. These 

methods were developed in compliance with approved 

safety regulations. Anyone using these methods shall comply with current regulations and recommended guidelines 

of the National Research Council's "Prudent Practices for 

Disposal of Chemicals from Laboratories" (National Research Council, 1981 a) and "Prudent Practices for Handling Hazardous Chemicals in Laboratories" (National 

Research Council, 1981 b), 

SAMPLING PROCEDURES 

ATMOSPHERIC AIR 

Special care must be taken to prevent contamination of 

samples of atmospheric air. A sampling apparatus consisting 

of a portable, non-lubricated air compressor and a !-liter 

stainless steel cylinder equipped with stainless steel regulating valves is used for sampling gases at low pressure. Prior 

to use, each cylinder is degassed of adsorbed (and (or) absorbed) gases with a special purging technique using highpurity nitrogen, and checked for possible contamination 

709 
710 THE FUTURE OF ENERGY GASES 

(Holland and Emerson, 1987). All conditions that could affect the samples at the time of sampling are recorded. Some 

gases, such as natural gas, require a gas-tight compressor 

such as a metal bellows pump. 

PRESSURIZED GASES 

In the sampling procedure for pressurized gases, a cylinder is purged with the gas to be sampled three times to 

the pressure of the source, then filled to this pressure. For 

safety, the sampling container, valves, and connecting tubing should be rated to accept a pressure higher than that of 

the gas to be sampled. 

SOIL GASES 

For soil-gas samples, hollow stainless steel probes 

(6.4-mm outer diameter (OD), 2.4-mm inner diameter 

(ID)) and 20-cm3 hypodermic syringes are used. The tips 

of the probes are sealed, sharpened, and then drilled with 

side holes 1.6 mm in diameter. The top of the probe is 

equipped with a 6.35-mm tube connector containing a rubber septum. The sample is collected by hammering the 

probe into the soil to a depth of 60 em. The probe is 

purged of air by inserting the syringe needle into the rubber septum and then extracting and discarding a 5-cm3 

volume of gas. A 20-cm3 sample is then taken for analysis 

and marked with the appropriate identifying information. 

The contents are compressed by pushing in the syringe 

plunger. This compression reduces the possibility of air 

contamination due to barometric pressure and temperature 

changes from time of sampling to time of analysis (Holland and Emerson, 1979). 

WATER CONTAINING DISSOLVED GASES 

Water samples are collected in 500-cm3 metal cylinders with a funnel extending to the bottom of the sample 

cylinder. The cylinder is filled with the sample water and 

is allowed to approach the temperature of the sample 

water. The container is then emptied, resubmerged in the 

sample water and filled to overflowing. Air-water contact 

and turbulence must be minimized. The sample is stored at 

room temperature and analyzed within 48 hours of collection (Holland, 1981, 1989; Holland and Emerson, 1979). 

CALIBRATION STANDARDS 

WEIGHED STANDARDS 

Weighed or gravimetric standards are used to provide 

the most accurate analyses and to certify standards prepared by partial pressure. To prepare a weighed standard, 

the evacuated cylinder is weighed. Then the cylinder is 

reweighed after each gas addition, and the mass of each 

gas is calculated by difference. A particular sequence of 

dilutions is selected to minimize the error of the final mixture. Typical relative errors of ::t0.02 percent are achieved 

(Bibawy, 1989; Bibawy and Emerson, 1990; Loya, 1985; 

Loya, Seitz and Emerson, 1982; Miller, Carroll and Emerson, 1965). 

CERTIFIED STANDARDS 

Certified standards are prepared by a partial pressure 

method to meet the blending specifications within ::t I 0 percent. Pure gases and pre-mixed gas from the percent to 

parts-per-million range for two or more components are 

used. Composition of these standards is determined by 

comparison to weighed standards. Certified standards are 

then used for the everyday operation of the laboratory. 

Pure gases are used for calibration of instruments 

whose analytical responses are linear from 0 to 100 percent. If increased accuracy is required, weighed or certified standard mixtures of the components are used in the 

area of interest. 

Helium content above the 10-percent level is certified 

with a special helium analyzer (Emerson, 1972; Emerson 

. and Kaplan, 1970). Otherwise, mixtures are certified by 

comparison with gravimetrically prepared standard mixtures using chromatographs (Seitz, 1985) and (or) mass 

spectrometers (Emerson, Hoffman, and Weems, 1970; Holland, 1991 ). Moisture content is determined using an electrolytic analyzer (Rhodes, 1981) with the flowmeter 

corrected for viscosity of the gas mixture (Davidson, 1993). 

MASS SPECTROMETRY METHODS 

The mass spectrometer is an apparatus that produces a 

beam of ions from a gaseous sample, sorts the resulting 

mixture of ions by the ratio of their mass to their charge, 

and produces electrical signals that are measures of the relative abundance of each component in the sample. 

PERCENT-RANGE ANALYSIS 

The mass spectrometer provides qualitative and quantitative analyses of gas samples. For natural gases the 

analysis includes hydrogen, helium, nitrogen, oxygen, hydrogen sulfide, argon, carbon dioxide, individual hydrocarbons through pentane, and a composite value for hexanes 

and heavier hydrocarbons. The specific gravity and heating 

value of the gas mixture are also calculated. Results are 

typically reported with a ::t3-percent relative accuracy 
METHODS OF GAS ANALYSIS 711 

(Boone, 1958). Examples of published analytical data provided by this method are available (Moore and Sigler, 

1987). 

Hydrogen sulfide (H2S) is significantly soluble in 

water, and most gas samples containing H2S are collected 

by water displacement. This procedure results in some unreliability of hydrogen sulfide analyses. This reactive gas 

can also be absorbed on the walls of the container, tubing, 

and valves. The water should be saturated with the gas to 

be sampled before starting the procedure (Rhodes, 1981 ). 

Other percent-level components are relatively unaffected 

by these problems. 

TRACE IMPURITIES IN HELIUM ANALYSIS 

Impurities in helium samples are concentrated using 

liquid helium ( -269°C), then the impurities are gasified 

and the partial pressures of the components are determined 

with a mass spectrometer. Samples are reported in the 

range of 0.010 to 600 ppm total impurities with an accuracy of ±15 percent and ±0.05 ppm in the 1.0-ppm range. 

(Emerson, Weems, and Hoffman, 1972; Emerson, Hoffman, and Weems, 1970; Suttle, Emerson, and Burfield, 

1966; Weems and Emerson, 1966). 

ANALYSIS OF HELIUM FROM 0 TO 10 PERCENT 

A mass-spectrometer method for determining helium 

content in the range from 5 ppm to I 0 percent with an 

accuracy of ± 1 percent (Holland, 1991) is similar to methods for determining helium content in the 0.5 to 20,000 

parts-per-billion (ppb) range (Holland, I 984; Seitz and 

Holland, 1986). 

The sample is passed through 0.5 g of 40---60 mesh 

activated coconut charcoal at liquid nitrogen temperature. 

The trap retains all the components except helium. The 

helium pressure is then measured using a mass spectrometer. Preconcentration results in increased sensitivity and a 

minimum detectable limit of 5 ppm for helium. 

ISOTOPIC ANALYSIS 

Analytical methods were developed to analyze for the 

two stable isotopes of helium. Generally, helium-4 is the 

predominant isotopic form. In samples composed mainly 

of helium-3, the helium-4 content can be determined at the 

ppm level to an accuracy of ±5 percent. Gravimetric 

standards of ppm-level helium-4 in hydrogen are used to 

provide accurate sensitivities. The method is accurate in 

the 2 to 100 ppm range. A minimum detectable limit of 

2 ppm helium-4 is attained (Burton and Cornelius, 1989). 

The abundances of isotopes of helium, neon, argon, 

and nitrogen in several natural gases have been determined 

(Davidson and Emerson, 1990a; Emerson, 1970; Emerson, 

Stroud, and Meyer, 1966; Emerson, Suttle, and Hoffman, 

1968; Stroud, Meyer, and Emerson, 1967). 

A mass spectrometer is used for analysis of helium-3 

and helium-4 in air (Holland, 1984; Holland and Emerson, 

1990) and he1ium-3 in helium-4 samples (Davidson and 

Emerson, 1990b; Emerson, Suttle, and Hoffman, 1968). 

Helium-3 in air or natural gas can be measured in the low 

parts-per-trillion (ppt) range with an accuracy of ±1 ppt by 

using a charcoal trap at -269°C that removes all components except hydrogen and helium, and a titanium trap that 

removes hydrogen (Davidson and Emerson, 1990a, b). HeIium-4 in air can be determined in the low parts-per-billion 

(ppb) range with an accuracy of ±0.2 ppb (Holland, 1984; 

Seitz and Holland,' 1986). 

CHROMATOGRAPHY METHODS 

ANALYSIS OF HELIUM AND HYDROGEN 

FROM 0 TO 10 PERCENT 

Gas samples are received in glass bottles at atmospheric pressure or in pressurized steel cylinders. The samples 

are analyzed with a gas chromatograph and a mass spectrometer. Samples received in glass bottles are transferred 

with a water-displacement system. A sample is transferred 

to a 50-cm3 metal cylinder at atmospheric pressure for the 

mass spectrometer while the chromatographic -sample loop 

is being purged for the helium and hydrogen analyses. 

A 2-cm3 sample is injected into the argon carrier gas 

that is flowing at 20 cm3/min. Two 0.32-cm-ID stainless 

steel columns maintained at 40°C are used for the separation. The first column, consisting of 60 em of Porapak R 

(80--100 mesh) and 180-cm activated charcoal (30--60 

mesh), removes carbon dioxide, heavy hydrocarbons, water, 

oxygen, and nitrogen. The second column, consisting of 

4.5 m of activated charcoal (30-60 mesh) and 60 em of 

molesieve, is connected to a thermistor detector operated at 

10 milliamperes (rnA). The limit of detection of this arrangement is about 20 ppm for both helium and hydrogen. 

The accuracy for a !-percent helium sample is 0.004 relative, and for a 5-percent sample is about 0.0015 relative. 

PERCENT-RANGE ANALYSIS 

Chromatography is used for process control and laboratory analysis. Variations of chromatographic procedures for 

the analysis of argon, nitrogen, and hydrogen are used depending on the concentration of the components to be determined. Various chromatographic procedures are used to 

analyze for one or more of the following components: helium, hydrogen, neon, oxygen, argon, nitrogen, methane, carbon monoxide, carbon dioxide, and hydrocarbons. These 
712 THE FUTURE OF ENERGY GASES 

procedures use various detector systems, such as helium 

ionization detectors (HID), thermal conductivity detectors 

(TC), flame ionization detectors (FID), ultrasonic detectors, 

and others. Various columns are used, such as molesieve, 

charcoal, carbosphere, carbosieve, chabazite, Porapak, 

Haysep, Porasil, and combinations of these columns. 

HYDROCARBON ANALYSIS 

The light alkanes and alkenes (C1 through C6) are determined using capillary gas chromatography/flame ionization detection (FID). The analyses are performed using a 

dual flame ionization detector gas chromatograph equipped 

with a 30-m by 0.53-mm-ID, GS-Alumina Megabore capillary column. For sample introduction, the capillary column 

is connected to the instrument's gas sampling valve using a 

0.16-cm to 0.53-mm, zero-volume reducing union. The 

sample loop for the valve is fabricated from a 7.6-cm 

length of 0.16-cm-OD, (0.107-cm-ID) stainless steel tubiQg. The volume of the loop is calculated to be 0.07 cm3. 

The sample container is connected to the gas sampling 

valve using a 1-m length of 0.16-cm-OD stainless steel 

tubing and tube fittings. The output end of the capillary is 

extended through a 0.16-cm tee installed on the detector 

inlet (where make-up gas is added) and terminated inside 

the burner jet approximately 1 em from the burner tip. 

Connections of the capillary to the zero-volume union located at the gas sampling valve and to the make-up gas tee 

at the detector inlet are made using graphite ferrules. 

The procedure for separating the various hydrocarbon 

components uses temperature programming of the column 

oven. The oven temperature is held at 40°C for a period of 

2 min, and then raised steadily at a rate of 5°C/min to 

achieve a plateau temperature of 195°C. 

Helium is used as the carrier gas and is supplied to the 

instrument's flow controllers at a nominal pressure of 446 

kilopascals (kPa). The flow controller for the column is 

adjusted to achieve a flow rate of 6-cm3

/min. Make-up helium is supplied to the detector inlet through a 30-cm length 

of 0.16-cm-OD stainless steel tubing. A make-up helium 

flow of 20 to 30 cm3 /min is required to maintain the recommended gas-flow rate through the detector, thereby sweeping sample components out of the detector immediately 

after their detection and eliminating the possibility of peak 

broadening. To support combustion, air and hydrogen are 

supplied to the detector burner at the manufacturer-recommended flow rates of 400 and 30 cm3/min, respectively. 

The components determined using this procedure include methane, ethane, ethene, propane, propene, isobutane, 

n-butane, ]-butene, cis- and trans-2-butene, isopentane, 

n-pentane, cyclopentane, a composite of pentenes, and a 

composite of hexanes plus. Sensitivity determinations for the 

alkanes are performed using certified standards containing 

0.2 to 3 percent of these components in helium or nitrogen. 

The alkene sensitivities are determined using certified 

standards containing I 0- to 1 00-ppm concentrations of 

these components in nitrogen. All standards are certified to 

be accurate within :!:2 percent. 

When calibrating with standards in the proper range, 

the chromatographic results are usually more accurate than 

those obtained from a general mass spectrometer analysis. 

On the basis of the 2-percent accuracy of the standards 

employed for calibration and the precision experienced for 

the gas chromatograph, the accuracy is estimated to be :!:5 

percent. 

MOISTURE ANALYSIS 

To quantitatively determine water-vapor content in helium in the range of 0.1 to 15 ppm by volume, the chemical reaction of CaH2 with water is used to produce 

hydrogen. The hydrogen analysis has a precision of 0.05 

ppm in the less-than-5-ppm range. This method is used to 

calibrate commercial moisture analyzers (Rhodes, 1981 ). 

HYDROGEN SULFIDE ANALYSIS 

A chromatograph with a flame photometric detector is 

used to analyze samples with H2S concentrations from 

0.01 to 5,000 ppm. Analysis of samples containing 0.1 

percent H2S was repeatable to within ±0.02 percent relative. It is important to use dry stainless steel or epoxycoated cylinders when collecting or analyzing the samples 

(Rhodes, 1979). 

ANALYSIS IN THE LOW 

PARTS-PER-MILLION RANGE 

A helium ionization chromatograph provides determination of components in routine, non-routine, and research 

samples in the low parts-per-million range. Accuracy is 

usually limited by the accuracy of the calibration standards. 

Routine applications consist of determining the neon and 

hydrogen contents of well-gas and helium-production-process samples. Non-routine applications have involved investigations for unusual components and solution of problems 

requiring analyses in the ppm range (Seitz, 1985). 

Cryogenic temperatures can be used to determine lowppm helium-3, neon, and hydrogen in helium-4 (Weems 

and Emerson, 1966). 

SPECIAL ANALYZERS 

ANALYSIS OF HELIUM FROM 1 TO 100 PERCENT 

An instrument has been developed that provides an automated determination for helium. Helium is determined to 
METHODS OF GAS ANALYSIS 713 

an accuracy of ::t:O.OI percent in samples that contain from 

I to I 00 percent helium. A liquid-nitrogen-cooled charcoal 

trap retains all components except helium, and the resulting partial pressure of helium in the sample is compared to 

the pressure caused by 100 percent helium (Emerson, 

1972; Emerson and Kaplan, 1970). 

FOURIER TRANSFORM INFRARED ANALYSIS 

Absorbance peaks obtained by Fourier transform infrared (FT-IR) spectrometry through a gas cell are wave-number specific for each functional group in a gas mixture. 

Individual components of a gas mixture are quantified by 

the partial pressure of each component and the transmission characteristics of each gas (Cornelius, 1993). 

FT-IR complements other analytical methods in that it 

can distinguish functional groups that would interfere with 

each other in mass spectrometry or gas chromatography. 

Solids, liquids, or gases can be analyzed by changing the 

type of cell used. 

SUMMARY 

Methods have been developed to determine the composition of natural gases required to produce high-quality 

helium. These methods outline the procedures used to separate and determine the component of interest in samples 

from air, soil gases, water, solvents, oils, stack gases, and 

process streams associated with helium plants and gas 

fields. Accuracies of each method vary depending on the. 

need. Impurities in helium can be determined to ::t:5 ppb in 

the ppb range, and the general mass spectrometer results 

are normally ::t:3 percent. 

REFERENCES CITED 

Bibawy, N.A., 1989, A method for the calibration of class 2 and 

class 4 standards of mass: U.S. Bureau of Mines Information Circular 9230, 14 p. 

Bibawy, N.A., and Emerson, D.E., 1990, An improved method 

for preparing gravimetric standard gas mixtures of helium-4 

in nitrogen: U.S. Bureau of Mines Report of Investigations 

9312, 7 p. 

Boone, W.J., Jr., 1958, Helium-bearing natural gases of the United States-Analyses and analytical methods: U.S. Bureau of 

Mines Bulletin 576, 117 p. 

Burton, S.R.M., and Cornelius, D.E., 1989, Improved method for 

determination of helium-4 in helium-3 by mass spectrometry: 

U.S. Bureau of Mines, Report of Investigations 9232, 7 p. 

Cornelius, D.E., 1993, Presented at the Pittsburgh Conference, 

Atlanta, Georgia, paper 1104, 9 p. Available upon request 

from 801 S. Fillmore, Amarillo, TX 79101. 

Davidson, T.A., 1993, A simple and accurate method for calculating viscosity of gaseous mixtures: U.S. Bureau of Mines 

Report of Investigations 9456, II p. 

Davidson, T.A., and Emerson, D.E., 1990a, Method and apparatus 

for direct determination of helium-3 in natural gas and helium: 

U.S. Bureau of Mines Report of Investigations 9302, 13 p. 

---1990b, Direct determination of helium-3 content of atmospheric air by mass spectrometry: Journal of Geophysical 

Research, v. 95, no. 04, p. 3565-3569. 

Emerson, D.E., 1970, U.S. Patent 3 517 521. 

--1972, U.S. Patent 3 691 818. 

Emerson, D.E., Hoffman, C.A., and Weems, G.W., 1970, An improved method and apparatus for the analysis of impurities 

in helium: U.S. Bureau of Mines Report of Investigations 

7444, 10 p. 

Emerson, D.E., and Kaplan, R.L., 1970, Method and apparatus 

for determining helium content of gas mixtures: Analytical 

Chemistry, v. 42, p. 1746-1748. 

Emerson, D.E., Stroud, L., and Meyer, T.O., 1966, The isotopic 

abundance of neon from helium-bearing natural gases: 

Geochimica Et Cosmochimica Acta, v. 30, no. 9, p. 847-854. 

Emerson, D.E., Suttle, E.T., and Hoffman, C.A., 1968, The separation of neon from high-helium-content natural gases and 

the atmosphere for isotopic analyses: Journal of Mass Spectrometry and Ion Physics, 1, p. I 05-110. 

Emerson, D.E., Weems, G.W., and Hoffman, C.A., 1972, U.S. 

Patent 3 662 588. 

Holland, P.W., 1981, A method for determining helium in water: 

U.S. Bureau of Mines Report of Investigations 8578, 17 p. 

---1984, An analyzer for determining helium-4 in the p~_rtsper-billion range: U.S. Bureau of Mines Report of Investigations 8853, 9 p. 

---1989, An improved method for determining helium in 

water: U.S. Bureau of Mines Report of Investigations 9249, 

9 p. 

---1991, A mass spectrometer method for determining helium in the parts-per-million to 10-percent range: U.S. Bureau 

of Mines Report of Investigations 9359, 8 p. 

Holland, P.W., and Emerson, D.E., 1979, Helium in ground water 

and soil gas in the vicinity of Bush Dome Reservoir, Cliffside Field, Potter County, Tex.: U.S. Bureau of Mines Information Circular 8807, 22 p. 

---1987, A determination of the helium-4 content of nearsurface atmospheric air within the continental United States: 

Journal of Geophysical Research, v. 92, no. B 12, p. 12,557-

12,566. 

---1990, Geochemistry of gaseous elements and compounds-The global helium-4 content of near-surface atmospheric air: Athens, Greece, Theophrastus Publications, 

p. 97-109. 

Loya, E.W., 1985, Computer program for calculating gravimetric 

primary standard gas mixtures: U.S. Bureau of Mines Information Circular 903 I, 35 p. 

Loya, E.W., Seitz, C.A., and Emerson, D.E., 1982, Gravimetric 

preparation of primary standard gas mixtures in the parts per 

trillion range: U.S. Bureau of Mines Report of Investigations 

8643,4 p. 

Miller, J.E., Carroll, A.J., and Emerson, D.E., 1965, Preparation 

of primary standard gas mixtures for analytical instruments: 

U.S. Bureau of Mines Report of Investigations 6674, I 0 p. 

Moore, B.J., and Sigler, S., I987, Analysis of natural gases 

1917-1985: U.S. Bureau of Mines Information Circular 

9I29, 1197 p. 
714 THE FUTURE OF ENERGY GASES 

National Research Council, 1981 a, Committee on hazardous substances in the laboratory-Prudent practices for disposal of 

chemicals from the laboratory: Washington, D.C., National 

Academy Press, 282 p. 

---1981 b, Committee on hazardous substances in the laboratory-Prudent practices for handling hazardous chemicals in 

laboratories: Washington, D.C., National Academy Press, 

291 p. 

Rhodes, H.L., 1979, Determination of hydrogen sulfide content in natural gas, evaluation of containers for preparation of calibration standards, and sample collection 

procedure: U.S. Bureau of Mines Report of Investigations 

8391, 12 p. 

---1981, An apparatus and procedure for calibrating a water 

vapor analyzer in the 0.1- to 15-ppm range: U.S. Bureau of 

Mines Report of Investigations 8548, 8 p. 

Seitz, C.A., 1985, Analysis for impurities in helium using the 

helium ionization detector: U.S. Bureau of Mines Report of 

Investigations 8941, 30 p. 

Seitz, C.A., and Holland P.W., 1986, An improved analyzer for 

determining helium-4 in parts-per-billion range: U.S. Bureau 

of Mines Report of Investigations 9010, 7 p. 

Stroud, L., Meyer, T.O., and Emerson, D.E., 1967, Isotopic abundance of neon, argon and nitrogen in natural gases-Relationship to helium genesis: U.S. Bureau of Mines Report of 

Investigations 6936, 27 p 

Suttle, E.T., Emerson, D.E., and Burfield, D.W., 1966, High pressure mass spectrometry for analysis of trace impurities in 

helium: Analytical Chemistry, v. 38, no. I, p. 51-53. 

Weems, G.W., and Emerson, D.E., 1966, Method of analysis of 

impurities in helium in the parts-per-billion range: U.S. Bureau of Mines Report of Investigations 6779, 5 p. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Hydrogen: Its Comparison with Fossil Fuels and 

Its Potential as a Universal Fuel 

By T. Nejat Veziroglu 1 and Frano Barbir2 

CONTENTS 

Abstract ......................................................................... 715 

Introduction ................................................................... 715 

Technological and Economic Analysis of Fuels .......... 716 

Fossil-Fuel Prices ................................................... 717 

Production Costs of Synthetic Fuels ..................... 717 

External Costs of Fossil Fuels ............................... 718 

External Costs of Synthetic Fuels ......................... 718 

End-Use Efficiency ................................................ 719 

Thermal Energy Generation .. ... .... .... .. .... ... .... .. 719 

Electrical Power Generation .. .......... ... .. .. ...... .. 719 

Transportation ...................... ........................... 720 

Effective Costs ....................................................... 720 

Comparison of Scenarios for the Future Energy 

System ........................................................................... 721 

Fossil-Fuel System ................................................. 721 

Coal and Synthetic Fossil-Fuel System ................. 722 

Solar Hydrogen Energy System ............................ 722 

Conclusions ............ ............................ ........................... 723 

References Cited ........................................................... 724 

ABSTRACT 

The fuels most often considered for the post-petroleum and natural-gas era are hydrogen (both gas and liquid 

forms), coal, and coal-derived synthetic fossil fuels. These 

fuels can be compared in terms of production cost, exter1

Ciean Energy Research Institute, University of Miami, Coral Gables, FL 33124. 2Energy Partners, Inc., West Palm Beach, FL 33407. 

nal cost, and end-use efficiency. The results show that hydrogen is a much more cost effective energy carrier than 

coal or synthetic fossil fuels, as well as being the most 

environmentally compatible fuel. 

INTRODUCTION 

The economic growth of modern industrialized society 

has been based on utilization of energy from fossil fuels. At 

the present time, about 80 percent of the world energy demand is met by fossil fuels-coal, petroleum, and natural 

gas (Davis, 1990). They are readily av~ilable worldwide in 

one form or another, although they are concentrated in certain regions of the world. Humankind has learned to exploit 

them efficiently to produce the energy services it needs. 

They are storable and portable, which makes them excellent fuels for transportation. 

A simplified version of today's energy system is 

shown in figure I. Fossil fuels are used for transportation; 

for heat generation in residential. commercial, and industrial sectors; and for electric power generation. For transportation, mostly petroleum products are used (gasoline, diesel 

fuel, jet fuel, and others). All three forms of fossil fuel are 

used for heat generation, which includes space heating, domestic water heating, cooking, steam generation and direct 

heating, and (or) drying in various industrial processes. In 

electric power generation, coal is used mainly for the baseload generation, and natural gas and heating oil are used 

for peak load. Part of the electric power is produced by 

hydro and nuclear sources. 

However, consumption of fossil fuels has become an 

environmentally damaging force. Locally, the damage results from emissions, spills and leaks, and strip mining. 

Regionally, the damage results from pollutant dispersion 

715 
716 THE FUTURE OF ENERGY GASES 

over large areas. Globally, carbon-dioxide accumulation 

results in threatening consequences-global warming, climate changes, and sea-level rise. 

If environmental stress does not force a shift to other 

energy sources and other fuels, the finite supply of fossil 

fuels will eventually mandate such a change. Reserves of 

fossil fuels are finite. Known reserves of oil and natural gas 

are about 8,000 EJ (1 EJ = 1018 J or joules), which would be 

enough for the next 40 years at the current consumption rate 

(Fulkerson and others, 1990). If the exponential population 

growth and the demand growth are taken into account these 

reserves will only last about 25 years. If estimated additional undiscovered resources are added, that would satisfy energy needs for fluid fuels for an additional 20 years or so. 

Coal reserves are much larger; the known reserves of coal 

are about 20,000 EJ, and ultimately recoverable resources 

are estimated to be 150,000 EJ (Fulkerson and others, 

1990). These large amounts of coal can eventually be used 

to produce synthetic liquid fuels; the synthetic fuels would 

allow society to continue employing the present energy system. However, this scenario would continue to cause 

detrimental environmental effects, which will ultimately 

lead to a calamity with unforeseeable consequences. 

An alternative is to use renewable energy sources, 

mainly solar energy in its direct and indirect forms. At 

present, these sources are not as convenient as fossil fuelsthey are only intermittently available, they are not storable 

or transportable by themselves, and they cannot be used as 

a fuel for transportation. The shortcomings of renewable 

energy sources point to the need for an energy carrier or an 

intermediary energy system to form a link between the new 

primary energy sources and the energy-consuming sectors. 

Hydrogen, with its vast and ready availability from water, 

its nearly universal utility, and its inherently benign environmental characteristics, has all the properties that might 

be required for such an energy system. 

NATURAL GAS 

ELECTRIC POWER 

Figure 1. Simplified fossil-fuel energy system. 

Hydrogen is the most plentiful element in the universe, 

making up about three quarters of all matter. All the stars 

and many of the planets essentially consist of hydrogen. 

However, on Earth free hydrogen is scarce; the atmosphere 

contains trace amm,mts of it (0.07 percent), and it is usually 

found in small amounts mixed with natural gas in crustal 

reservoirs. A few wells, however, have been found to contain large amounts of hydrogen, such as some wells in Kansas that contain 40 percent hydrogen, 60 percent nitrogen, 

and trace amounts of hydrocarbon (Goebel and others, 

1984). The Earth's surface layers contain about 0.14 percent 

hydrogen (lOth most abundant element), most of which resides in chemical combination with oxygen as water. Accordingly, oceans, lakes, and rivers are our hydrogen mines. 

In the hydrogen energy system, it is envisaged that hydrogen will be produced from water using any and all primary energy sources, and it will be used in every 

application for which fossil fuels are used today (Bockris 

and Veziroglu, 1985). In this system, hydrogen is not a 

primary source of energy. Rather, it is an intermediary, or 

secondary, form of energy or an energy carrier. Hydrogen 

particularly complements the renewable energy sources, 

and it presents them to the consumer in a convenient form 

at the desired location and time. It is inexpensive to produce, it can be converted to other forms of energy more 

efficiently than other fuels, and it is the cleanest fuel because its combustion product is simply water vapor. The 

hydrogen energy system is a permanent energy system because it is independent of the primary energy sources. Hydrogen is inexhaustible, recyclable, and versatile. Even if 

the primary energy sources and the consumption patterns 

of society change owing to technological developments, 

changes in lifestyle, and (or) unforeseeable causes, the hydrogen energy system as an intermediary link would remain basically intact. 

TECHNOLOGICAL AND ECONOMIC 

ANALYSIS OF FUELS 

Hydrogen energy is already technically feasible, but 

economics are a major obstacle for its widespread use. 

Comparing strictly the consumer prices of fuels, hydrogen 

produced using clean and renewable energy sources is more 

expensive than existing (fossil) gaseous and liquid fuels. 

The comparison between competing fuels, however, 

should be based on the effective costs of the services these 

fuels provide. The effective costs include the end-use efficiency, the consumer cost of fuel, and the external costs. 

External costs should include the costs of the physical 

damage done to humans and to the environment owing to 

harmful emissions, oil spills and leaks, coal strip mining, 

as well as governments' expenditures for pollution abatement, expenditures for military protection of oil supplies, 

costs of international conflicts, and other economic effects 
HYDROGEN: ITS COMPARISON WITH FOSSIL FUELS AND ITS POTENTIAL AS A UNIVERSAL FUEL 717 

Table 1. Present and projected prices of fossil fuels. 

[Price in 1990 U.S. dollars per gigajoule] 

Nat ural gas------------

Fuel oil----------------

Natural gas------------

Petroleum fuels ------

Coal--------------------

Natural gas------------

Petroleum fuels ------

Coal--------------------

Gasoline---------------

Jet fuel-----------------

Year 

1990 

Residential sector 

5.61 

6.65 

Industrial sector 

3.26 

4.45 

1.81 

Electric utilities 

2.63 

3.11 

1.47 

Transportation 

8.93 

5.93 

2000 

7.04 

9.14 

4.32 

7.38 

2.20 

3.83 

5.66 

1.86 

11.23 

7.42 

(such as employment, balance of trade, and depletion of 

nonrenewable resources). 

For economic analysis, it is also important to consider 

the future costs of hydrogen, which will presumably be 

considerably lower than they are today because of assumed market and technological developments, with respect to the future costs, both internal and external, of 

fossil fuels, which will unavoidably be higher than today's 

prices owing to depletion, international conflicts, and environmental impacts. 

FOSSIL-FUEL PRICES 

Table 1 shows prices of fossil fuels today and projected prices for the year 2000 in the United States (Energy 

Information Administration, 1990). Prices are given for 

different fuels and for different end-use sectors. It should 

be mentioned that the prices given in table 1 are the enduse prices, which means that they include the production 

cost, as well as the costs of transportation and distribution. 

As expected, the projected prices of the fossil fuels for the 

year 2000 are much higher than they are today, particularly for petroleum products. 

PRODUCTION COSTS OF SYNTHETIC FUELS 

Hydrogen can be produced by several methods from 

various primary energy sources. Today, hydrogen is mainly produced by methane steam reforming and coal gasifiTable 2. Large-scale production cost estimates of synthetic fuels 

for the year 2000. 

[Cost expressed in 1990 U.S. dollars per gigajoule] 

Production 

cost 

Gaseous fuels 

Coal-derived hydrogen ----------- 8.58 

Hydropower hydrogen------------ 11.51 

Solar-derived hydrogen----------- 15.44 

Synthetic natural gas-------------- 8.85 

Liquid fuels 

Coal-derived hydrogen ----------- 10.73 

Hydropower hydrogen------------ 14.39 

Solar-derived· hydrogen----------- 19.30 

Synthetic gasoline----------------- 17.25 

Synthetic jet fuel ------------------ 13.05 

Storage and 

distribution 

3.50 

3.50 

3.50 

2.60 

3.50 

3.50 

3.50 

2.60 

2.60 

End-use cost 

12.08 

15.01 

18.94 

11.45 

14.23 

17.89 

22.80 

19.85 

15.65 

cation. After depletion of fluid fossil fuels, coal could be 

used to produce hydrogen as well as other synthetic fuels, 

such as synthetic natural gas, synthetic gasolin·e, and synthetic jet fuel. Processes for converting coal into liquid 

and gaseous fuels already exist, but they are not widely 

used because synthetic fuels would be more expensive 

than oil and natural gas which are both available and relatively inexpensive. 

Hydrogen can also be produced by splitting water-a 

process that uses both direct and indirect solar energy. The 

most widely used method of water splitting is electrolysis·, 

which is a very efficient technology. The cost of electrolytically produced hydrogen is directly proportional to the 

cost of electricity. Therefore, cheap electricity is required 

to produce hydrogen at competitive prices. One of the possible sources of cheap electricity is hydropower. Electricity 

generated by solar energy, at the present time, is not competitive with coal, hydropower or nuclear electricity. Windgenerated electricity, however, is already competitive at 

some locations. Expected development, particularly of the 

thin-film photovoltaics, could in the near future provide 

electricity at $0.020 to $0.035/kWh (kilowatthour), which 

will make it possible to generate hydrogen on a large scale 

and at competitive prices (Ogden and Williams, 1989). 

Table 2 presents the averages of large-scale production 

costs of synthetic fuels taken from recent literature (Ogden 

and Williams, 1989; Moore and Dahmias, 1991; Williams 

1985; Steinberg and Cheng, 1988, Bockris and Was, 

1988). In the case of hydrogen, the costs are classified by 

the primary energy source used in the production, namely 

coal, hydropower, and solar energy. All costs are expressed in 1990 U.S. dollars and adjusted for inflation. 

Although gaseous hydrogen can be used in most of 

the applications where gaseous or liquid fossil fuels are 

currently being used, there are some applications where 
718 THE FUTURE OF ENERGY GASES 

liquid hydrogen must be used. For example, liquid hydrogen must be used in rocket engines for space travel and in 

jet engines for air transportation. The productton cost of 

liquid hydrogen has been assumed to be 25 percent higher 

than production cost of gaseous hydrogen. Current commercial hydrogen liquefaction processes are costly and 

consume about 35 percent of the hydrogen's heating value. 

Preliminary studies show that the magnetic liquefaction 

process, which is currently being developed, will be much 

more efficient and will need less capital investment and 

less maintenance than conventional liquefaction systems 

(Barklay and Corless, 1992; Sherif and others, 1991 ). 

Because table 1 presents end-use prices, the production costs of synthetic fuels in table 2 have been increased 

for the cost of transportation, storage, and distribution of 

these fuels. For synthetic fossil fuels the assumed costs are 

$2.60/GJ (gigajoule), and for hydrogen fuels the assumed 

costs are $3.50/GJ (Ogden and Williams, 1989). Comparing the costs in tables 1 and 2, it is clear that synthetic 

fuels will be more expensive than fossil fuels. Among the 

synthetic fuels, hydrogen from renewable sources (water 

and solar) is the most expensive. 

EXTERNAL COSTS OF FOSSIL FUELS 

The entire process of fossil-fuel consumption (extraction, transportation, processing, and particularly combustion) creates harmful environment impacts, which have 

direct and indirect negative effects on the economy. 

Excavation of coal devastates the land, which then 

must be reclaimed, and during these processes the land is 

out of use. During the extraction, transportation, and storage of oil and gas, spills and leakages occur, which cause 

water and air pollution. Refining processes also have negative environmental impacts. 

Most of the fossil fuel environmental impacts result 

from end use. The end use for all fuels is combustion, regardless of the intended purpose (that is, heating, electricity production, or power for transportation). The main 

constituents of fossil fuels are carbon, hydrogen, and trace 

amounts of other ingredients, such as sulfur. Combustion 

of fossil fuels produces various gases (COx, SOx, NOx), 

unburned hydrocarbons, soot and ash, droplets of tar, and 

other organic compounds, which are all released into the 

atmosphere and constitute air pollution. Air pollution causes damage to humans, animals, crops, and structures, and 

it reduces visibility. 

Once in the atmosphere, the primary pollutants may 

undergo chemical reactions triggered by sunlight or by 

mixing with water and other atmospheric compounds. As a 

result of these reactions, the pollutants change their form 

to become secondary pollutants such as ozone, aerosols, 

peroxyacyl nitrates, and various acids. Precipitation of sulfur and nitrogen oxides, which dissolve in clouds and in 

Table 3. Environmental damages, including cost estimates, resulting from use of three fossil fuels. 

[Estimates in I 990 U.S. dollars per gigajoule. N/A, not applicable] 

Coal Petroleum Natural gas 

Effect on humans------------------ 3.48 2.83 2.09 

Effect on animals------------------ 0.51 0.42 0.30 

Effect on plants and forests------ 1.35 1.09 0.81 

Effect on aquatic ecosystems---- 0.18 1.05 0.11 

Effect on man-made structures-- 1.12 0.90 0.67 

Other air pollution costs---------- 0.98 0.79 0.59 

Effect of strip mining------------- 0.49 NIA NIA 

Effect of climatic changes ------- 1.39 1.13 0.84 

Effect of sea-level rise------------ 0.32 0.26 0.19 

Total cost of damages ------ 9.82 8.47 5.60 

rain droplets to form sulfuric and nitric acids is called acid 

rain, but acid dew, acid fog, and acid snow have also been 

recorded. Acid deposition (wet or dry) causes soil and 

water acidification and results in damages to the aquatic 

and terrestrial ecosystems; these damages affect humans, 

animals, vegetation, and structures. 

The other products of combustion in the atmosphere, 

mainly carbon dioxide, together with other so-called 

greenhouse gases (methane, nitrogen oxides, and chlorofluorocarbons), result in thermal changes by absorbing the 

infrared energy the Earth radiates back into the atmosphere and partially reradiating it back to the Earth to cause 

global temperature increases. The effects of the temperature increases are melting of the ice caps, sea-level rise 

and climate changes, which include heat waves, droughts, 

floods, stronger storms, and more and bigger wildfires. 

Barbir and Veziroglu (1991) c.ompiled various reported 

environmental damages and asspciated them with consumption of fossil fuels. The results of this study are 

shown in table 3. Cost estimates for environmental damage 

resulting from coal use are highest at $9.82/GJ, those res~Iting from petroleum use are second highest at $8.47/GJ, 

and those resulting from natural gas use are the lowest at 

$5.60/GJ. 

The cost of these negative environmental effects is not 

included in the market price of a fossil fuel, and it must be 

considered an external cost. These environmental costs are 

or will be paid by society in the long term because any 

disturbed ecosystem will affect human society, its environment, and its economy. 

EXTERNAL COSTS OF SYNTHETIC FUELS 

When synthetic fuels are produced from coal, more 

than I GJ of coal is used for each GJ of a synthetic fuel 

manufactured and consumed. Consequently, the environmental damage caused by 1 GJ of a synthetic fuel produced 
HYDROGEN: ITS COMPARISON WITH FOSSIL FUELS AND ITS POTENTIAL AS A UNIVERSAL FUEL 719 

Table 4. C02 emissions and pollution factors for synthetic fuels. 

[C02 emissions expressed in kilograms per gigajoule] 

Fuel C02 emissions Pollution factor 

Coal -------------------------------------- 85.5 I 

Coal-derived gaseous hydrogen------ 116.3 1.36 

Hydropower gaseous hydrogen------ 0 0 

Solar-derived gaseous hydrogen----- 0 0 

Synthetic natural gas ------------------ 116.3 1.36 

Coal-derived liquid hydrogen-------- 145.4 1.70 

Hydropower liquid hydrogen--------- 0 0 

Solar-derived liquid hydrogen-------- 0 0 

Synthetic gasoline---------------------- 131.6 1.54 

Synthetic jet fuel ----------------------- 131.6 1.54 

from coal is greater than the estimated damage caused by 

coal consumption. This can be expressed as follows: 

(1) 

where Esyn is the environmental damage due to use of 1 

GJ of a synthetic fuel (including hydrogen) produced from 

coal, Ecoal is the environmental ·damage from coal consumption, and P s is the synthetic fuel pollution factor. Because of the dearth of data, total C02 generated per unit 

energy is used as a measure of the pollution. Pollution factor, as shown in table 4, is therefore a ratio of total carbon 

dioxide emissions (including emissions during production 

and combustion of particular synthetic fuel) to carbon dioxide emissions from coal combustion. 

END-USE EFFICIENCY 

In comparing fuels, it is important to consider end-use 

efficiency. Fuels are converted to various energy forms, 

such as mechanical, electrical, and thermal, for end use. 

Studies show that for almost every use, hydrogen can be 

converted to the desired energy form more efficiently than 

the fossil fuels or other synthetic fuels (Chen and others, 

1982). In other words, conversion to hydrogen would result in energy conservation. Hydrogen end-use efficiencies 

are summarized in table 5. 

THERMAL ENERGY GENERATION 

For many industrial, commercial, and residential applications, fuels are converted to thermal energy (space heating, water heating, cooking, steam generation, and direct 

heat in industrial processes). Hydrogen combustion in industrial applications is state-of-the-art. Hydrogen is burned 

in large amounts in the chemical industry to produce heat, 

especially when it is not economical to purify it (Peschka, 

Table 5. End-use efficiency advantage of hydrogen. 

[Cost in 1990 U.S. dollars per gigajoule. TIF is average end-use conversion efficiency of fossil fuels and 'lH is end-use conversion efficiency of hydrogen] 

Application End-use efficiency TIF'TIH 

Thermal energy 

Flame combustion----------------------------------- 1.00 

Catalytic combustion ------------------------------- 0.80 

Steam generation------------------------------------ 0.80 

Electric power 

Fuel cells --------------------------------------------- 0.54 

Surface transportation 

Internal combustion engines-----------------------

Fuel cells/electric motor----------------------------

Air transportation 

0.82 

0.40 

Subsonic jet------------------------------------------ 0.84 

Supersonic jet---------------------------------------- 0.72 

1988). However, some design changes in the existing burners are required to match hydrogen burning properties, 

which are somewhat different than those of methane and 

other gaseous fuels, but the efficiency is about the same as 

for fossil-fuel combustion. 

Catalytic combustion of hydrogen is its unique property to combine with oxygen in the presence of a catalyst, 

such as platinum or palladium, in an exothermic reaction 

without a flame. This process is usually more efficient 

than flame combustion. In some applications, such as 

space heating, catalytic combustion can be as much as 99 

percent efficient because all the heat of the catalytic reaction remains inside the heated space; there are no exhaust 

gases (Haruta and others, 1982). Catalytic burners can also 

be used in kitchen ranges (Ledjeff, 1990). 

Hydrogen burns with oxygen to produce pure steam at 

very high temperatures. An appropriate amount of water 

can then be added to bring the steam temperature down to 

the required temperature. Such a device, called the H2/02 

steam generator, has been developed and tested at the German Aerospace Research Establishment (DLR) (Sternfeld 

and Heinrich, 1989). This steam generator is simple, compact, and extremely efficient (as much as 99 percent). 

Conventional steam generators are usually about 75 to 80 

percent efficient. 

ELECTRICAL POWER GENERATION 

Hydrogen can be converted back to electricity in fuel 

cells with much greater efficiency than is possible in thermal 

powerplants using fossil fuels. Whereas conversion efficiencies for the latter range from 35 to 38 percent, practical 
720 THE FUTURE OF ENERGY GASES 

efficiencies in hydrogen fuel cells range from 50 to 70 percent (Kordesch and Oliveira, 1988). In advanced hydrogen 

fuel cells, which are now being developed, even higher 

efficiencies (as high as 80 percent) can be expected. Primary 

electricity, that is, electricity from primary energy sources 

such as solar, wind, and hydropower could be used directly 

whenever possible without conversion to hydrogen. However, these sources are intermittently available, and conversion 

to hydrogen provides a constant energy source. 

TRANSPORTATION 

Hydrogen-powered vehicles with internal combustion 

engines have proven more efficient than gasoline vehicles. 

Hydrogen is more thermally efficient than gasoline, primarily because it bums better in excess air and permits the 

use of a higher compression ratio. Data from engine tests 

indicate that hydrogen combustion is 15 to 50 percent 

more thermally efficient (DeLuchi, 1989). The overall fuel 

efficiency of a hydrogen vehicle, which takes into account 

the thermal efficiency as well as the weight of the vehicle, 

is better than a gasoline vehicle (on the average, hydrogen 

vehicles are 22 percent more efficient (DeLuchi, 1989)). 

Because hydrogen can bum in lean fuel/air mixtures as 

well as in rich fuel/air mixtures, it can result in cars with 

better fuel efficiency for stop-start-type city driving. 

The hydrogen fuel cell-electric motor combination is 

another option for transportation; it can be used for cars, 

trucks, buses, and trains. It is almost twice as efficient as 

internal-combustion engines. 

For a given number of passengers and a given payload, 

a subsonic passenger jet would use 19 percent less energy, 

if it were to use liquid hydrogen instead of conventional jet 

fuel (Brewer, 1991 ). A supersonic jet using hydrogen instead of jet fuel would use 38 percent less energy. 

EFFECTIVE COSTS 

As mentioned, the comparison of competing fuels 

should be based on the effective costs of the services these 

fuels provide. The effective costs include the end-use efficiency as well as both the internal and external costs of 

fuel. Internal costs are those included in the end-user price 

of fuel (production, storage, transportation, and distribution costs). External costs are those associated with fuel 

consumption but which up to now have not been included 

in the price (for example, environmental damage). 

Effective cost of energy services can be expressed as 

dollars/GJth for heat generation, dollars/kWhel for electric 

power generation and dollars/passenger-km or dollars/freightkm for transportation. To bring these costs to a common 

basis and to be able to add them together, they are expressed as dollars/GJ of fossil fuel equivalent, or in other 

words dollars/GJ of fossil fuel required to provide the 

same service. 

Table 6. Effective cost of thermal energy generation. 

[Cost in 1990 U.S. dollars per gigajoule] 

Fuel Effective cost 

Flame combustion 

Natural gas ------------------------------------------- 11.82 

Petroleum fuels-------------------------------------- 18.66 

Coal---------------------------------------------------- 12.02 

Synthetic natural gas--------------------------------

Synthetic fuel oil ------------------------------------

24.81 

30.77 

Coal-derived gaseous hydrogen------------------- 25.44 

Hydropower gaseous hydrogen------------------- 15.01 

Solar-derived gaseous hydrogen ------------------ 18.94 

Catalytic combustion 

Coal-derived gaseous hydrogen------------------- 20.35 

Hydropower gaseous hydrogen ------------------- 12.00 

Solar-derived gaseous hydrogen ------------------ 15.15 

Effective cost of fossil fuels (Ceff) by definition is: 

(2) 

where Cin is internal cost (from table 1) and Cex is external cost (from table 3). 

Effective cost of synthetic fuels, including hydrogen, 

must take into account the end-use efficiency of fossil fuels, 

and is calculated as follows: 

(3) 

Internal costs (Cin) for synthetic fuels are given in table 

2, and external costs (Cex = Esyn) can be calculated by 

using equation I. For coal-derived synthetic fossil fuels, the 

end-use efficiency factor (rJF) is assumed to be rJF/rJs=l. In 

other words, the end-use efficiency of synthetic fossil fuels 

is equal to the end-use efficiency of fossil fuels. For hydrogen, the end-use factor is actually rJF/rJs and is given in 

table 5. 

Using the above equations, tables 6 through 9 give effective costs for various applications for thermal energy 

generation, electric power generation, and transportation, 

respectively. Table 6 shows that the catalytic combustion 

of gaseous hydrogen from hydropower would produce 

thermal energy at a cost comparable to that of using natural gas or coal. Heat produced from synthetic fossil fuels 

would be the most expensive. For electric power generation (table 7), hydrogen-powered fuel cells would be the 

most cost effective method because of their high conversion efficiency. The fuel cells also appear to be the most 

cost effective option for surface transportation (table 8). 

Air transportation requires the most expensive fuels. Liquid hydrogen from renewable sources (hydrologic and 

solar) would be much cheaper than synthetic jet fuel when 
HYDROGEN: ITS COMPARISON WITH FOSSIL FUELS AND ITS POTENTIAL AS A UNIVERSAL FUEL 721 

Table 7. Effective cost of electric power generation. 

[Cost in 1990 U.S. dollars per gigajoulel 

Fuel 

Thermal plant 

Natural gas--------------------------------------------

Petroleum fuels---------------------------------------

Coal ----------------------------------------------------

Synthetic natural gas --------------------------------

Synthetic fuel oil-------------------------------------

Effective cost 

9.43 

15.83 

11.68 

24.81 

30.77 

Thermal plant with Hz-02 steam generator 

Coal-derived gaseous hydrogen--------------------

Hydropower gaseous hydrogen----~--------------­

Solar-derived gaseous hydrogen-------------------

Fuel cells 

20.35 

12.00 

15.15 

Coal-derived gaseous hydrogen-------------------- 13.74 

Hydropower gaseous hydrogen-------------------- 8.10 

Solar-derived gaseous hydrogen------------------- 10.23 

Table 8. Effective cost of surface transportation. 

[Cost in 1990 U.S. dollars per gigajoule] 

Fuel Effective cost 

Internal combustion engines 

Gasoline ----------------------------------------------- 21.40 

Synthetic natural gas -------------------------------- 24.81 

Synthetic gasoline------------------------------------ 34.97 

Coal-derived gaseous hydrogen-------------------- 20.86 

Hydropower gaseous hydrogen-------------------- 12.31 

Solar-derived gaseous hydrogen------------------- 15.53 

Coal-derived liquid hydrogen---------------------- 25.36 

Hydropower liquid hydrogen-,---------------------- 14.67 

Solar-derived liquid hydrogen---------------------- 18.70 

Fuel cells 

Coal-derived gaseous hydrogen-------------------- I 0.17 

Hydropower gaseous hydrogen-------------------- 6.00 

Solar-derived gaseous hydrogen------------------- 7.58 

effective cost is considered (table 9). Hydrogen from coal 

has the lowest production cost among hydrogen fuels, but 

its effective cost would be the highest. This high effective 

cost is attributed to environmental damage. 

COMPARISON OF SCENARIOS FOR THE 

FUTURE ENERGY SYSTEM 

There are three possible scenarios for the future energy system. These are a fossil-fuel energy system as it is 

Table 9. Effective cost of air transportation. 

[Cost in 1990 U.S. dollars per gigajoulel 

Fuel 

Subsonic jets 

Jet fuel ------------------------------------------------

Synthetic jet fuel ------------------------------------

Coal-derived liquid hydrogen ---------------------

Hydropower liquid hydrogen----------------------

Solar-derived liquid hydrogen---------------------

Supersonic jets 

Jet fuel ------------------------------------------------

Synthetic jet fuel ------------------------------------

Coal-derived liquid hydrogen ---------------------

Hydropower liquid hydrogen----------------------

Solar-derived liquid hydrogen---------------------

Effective cost 

17.59 

30.77 

25.98 

15.03 

19.15 

17.59 

30.77 

22.27 

12.88 

16.42 

today, a coal and coal-based synthetic fuel energy system, 

and a hydrogen-fuel energy system based on renewable 

energy sources. 

FOSSIL-FUEL SYSTEM 

In this scenario, it is assumed that the present fossilfuel system will be continued in the future. Therefore, 40 

percent of primary energy (in fossil-fuel equivalent units) 

will be used for thermal energy generation, 30 percent will 

be used for electric power generation, and 30 percent will 

be used for transportation (two-thirds for surface transportation and one-third for air transportation). Energy supplied by hydropower and nuclear powerplants (mostly in 

the form of electric power) and by other non-fossil fuel 

sources is not considered part of this scenario because it is 

assumed to provide the same amount of energy in all three 

considered systems. Actually, it is reasonable to expect 

that in the future even more energy will be supplied by 

these sources, but no estimates were made of the amount 

of energy from these sources. 

In the fossil-fuel system (see fig. I), it is assumed that 

one half of the thermal energy will be supplied by natural 

gas, and the rest by petroleum fuels (fuel oil and residual 

oil) and coal. Coal is assumed to be the main energy 

source for electricity generation, gasoline is the main 

source for surface transportation, and jet fuel is the main 

source for air transportation. This scenario greatly simplifies the fossil-fuel energy system, but it nonetheless represents present patterns of energy consumption, and it can 

be used as the basis for further analyses and comparisons. 

The prices of fossil fuels are expected to rise (see table 1). 

The projected costs for the year 2000 are used in calculations of the effective costs, which are shown in table I 0. 
722 THE FUTURE OF ENERGY GASES 

Table 10. Effective cost of the fossil-fuel system. 

[Cost in 1990 U.S. dollars per gigajoule] 

Fuel 

N at~,~ral gas ----------------

Petroleum fuels-----------

Coal ------------------------

Coal ------------------------

Gasoline -------------------

Jet fuel---------------------

Total -----------------

Energy consumption fraction Effective cost 

Thermal energy 

0.20 11.82* 

0.10 18.66* 

0.10 12.02 

Electric power 

0.30 11.68 

Surface transportation 

0.20 21.40 

Air transportation 

0.10 17.59 

1.00 

• Average for residential and industrial sector. 

Overall effective 

cost (fraction x 

eff. cost) 

2.36 

1.87 

1.20 

3.50 

4.28 

1.76 

14.97 

COAL AND SYNTHETIC FOSSIL-FUEL SYSTEM 

For this system, it is assumed that the present fossilfuel system will be continued by substituting synthetic 

fuels derived from coal whenever convenient and (or) necessary. Patterns of energy consumption are also assumed 

to remain unchanged. Coal will be used extensively for 

thermal power generation and for electric power generation, because it is much cheaper than synthetic fuels. 

However, some end uses require fluid fuels; therefore it 

has been assumed that synthetic natural gas (SNG) will be 

used for thermal energy generation (primarily in the residential sector) and also as a fuel for surface transportation, 

where it will share the market with synthetic gasoline. 

ELECTRIC POWER 

Figure 2. Coal and synthetic fuels energy system. SYN, synthetic; SNG, synthetic natural gas. 

Table 11. Effective cost of the coal and synthetic fuel energy 

system. 

[Cost in 1990 U.S. dollars per gigajoule) 

Fuel 

Coal-------------------------

Synthetic natural gas -----

Coal-------------------------

Synthetic natural gas-----

Synthetic gasoline--------

Synthetic jet fuel ---------

Total------------------

Energy 

consumption 

fraction 

Effective cost 

Thermal energy 

0.30 12.02 

0.10 24.81 

Electric power 

0.30 11.68 

Surface transportation 

0.10 24.81 

0.10 34.97 

Air transportation 

0.10 17.59 

1.00 

Overall effective 

cost (fraction x 

eff. cost) 

3.61 

2.48 

3.50 

2.48 

3.50 

1.76 

17.33 

Synthetic jet fuel will be used in air transportation. The 

energy system based on coal and synthetic fossil fuels is 

shown in figure 2, and the effective costs of this system 

are shown in table 11. 

SOLAR HYDROGEN ENERGY SYSTEM 

In this system, it is assumed that the conversion to 

hydrogen energy will take place, and one-third of the hydrogen needed will be produced from hydropower and 

two-thirds by direct and indirect (other than hydropower) 

solar-energy forms. The same percentage of energydemand sectors as the above scenarios is assumed. It will 

further be assumed that one-half of the thermal energy will 

be achieved by flame combustion, one quarter by steam 

generation with hydrogen/oxygen steam generators and the 

last quarter by catalytic combustion. Electric power will be 

generated by fuel cells. One-half of the energy for surface 

transportation will be provided by gaseous hydrogen burning in internal combustion engines, and the other half will 

be provided by fuel cells. In air transportation, both subsonic and supersonic, liquid hydrogen will be used for fuel. 

A proposed solar-hydrogen energy system is shown in figure 3, and the effective costs of the system are given in 

table 12. 

As shown by the data in tables lO through 12, the hydrogen energy system has a lower effective cost than today's fossil-fuel system if the costs are projected for the 

year 2000 and beyond for both systems. An energy system 

based on coal and coal-derived synthetic fuels would be 

the most costly alternative (fig. 4). 
HYDROGEN: ITS COMPARISON WITH FOSSIL FUELS AND ITS POTENTIAL AS A UNIVERSAL FUEL 723 

Of course, conversion to a new energy system is not 

possible in a short time period-it will probably take more 

than 50 years. These calculations are intended to show that 

the hydrogen energy system could become cost competitive at the beginning of the next century. However, the 

transition should start as soon as possible because only 

with adequate technology and market developments can 

the projected costs of hydrogen be achieved. 

Because of its low external costs, natural gas is presently the most cost effective fuel for many end uses. 

Widespread application of natural gas, particularly in 

transportation and electricity generation, and corresponding infrastructure development could be a bridge toward 

the hydrogen energy system. During the transition period, 

natural gas can be used to generate hydrogen for applications where hydrogen offers better and (or) cleaner performance, such as in fuel cells or in aircraft propulsion. 

Renewably produced hydrogen could be added in the natural gas pipelines to increase the heating value and reduce 

combustion emissions. As the reserves of natural gas diminish, and technologies for production of hydrogen from 

renewable sources mature, hydrogen could gradually take 

over without dramatic and costly infrastructure changes. 

CONCLUSIONS 

1. The solar-hydrogen energy system is environmentally more sound than the fossil-fuel system; it is actually the 

only solution for reducing and reversing the carbon dioxideinduced greenhouse effect and its threatening consequences. 

2. Hydrogen is a synthetic fuel. To take full advantage 

of its environmental benefits, hydrogen would have to be 

produced from clean resources. Water and renewable energy sources are the best choice, although in a transition period hydrogen could be produced from coal and (or) 

natural gas. 

Figure 3. Solar-hydrogen energy system. I. C., internal combustion. 

Table 12. Effective cost of the solar hydrogen energy system. 

[Cost in 1990 U.S. dollars per gigajoule. It has been a'"umed that one-third of the 

hydrogen in this system will be produced from hydropower and two-thirds from 

solar power] 

Flame 

combustion. 

Steam 

combustion. 

Catalytic 

combustion. 

Fuel cells -----------

Internal combustion 

engines. 

Fuel cells -----------

Energy 

consumption 

fraction 

Fuel 

Thermal energy1 

0.20 Gaseous hydrogen 

0.10 Gaseous hydrogen 

0.10 Gaseous hydrogen 

Electric powe~ 

0.30 Gaseous hydrogen 

Surface transportation3 

0.10 Gaseous hydrogen 

0.10 Gaseous hydrogen 

Air transportation4 

Overall 

Effective effective cost 

cost (fraction x 

eff. cost) 

17.63 3.53 

14.10 1.41 

14.10 1.41 

9.52 2.86 

14.46 1.45 

7.05 0.71 

Subsonic ------------

Supersonic----------

Total -----------------

0.05 

0.05 

1.00 

Liquid hydrogen 17.78 

Liquid hydrogen 15.24 

0.89 

0.76 

13.02 

1 Energy consumption fraction is 0.40 2Energy consumption fraction is 0.30 3Energy consumption fraction is 0.20 4

Energy consumption fraction is 0.10 

Fossil-Fuel Coal and Synthetic Solar-Hydrogen 

System Fuels System Energy System 

Figure 4. Effective costs of the analyzed energy systems. Costs 

given in 1990 U.S. dollars per gigajoule and adjusted for inflation. Total cost for the three sectors of each energy system shown 

at top of each column. 
724 THE FUTURE OF ENERGY GASES 

3. The end-use efficiencies of hydrogen are greater 

than those of fossil and synthetic fossil fuels; therefore, in 

the solar-hydrogen energy system, less end-use energy will 

be required to perform the same services. 

4. The solar-hydrogen energy system could be the 

most cost effective system if effective costs (the costs society pays for the energy services) are taken into account. 

It wot:ld not only be more cost effective than the synthetic 

fossil-fuel system-it would be even more cost effective 

than the present fossil-fuel system. 

REFERENCES CITED 

Barbir, Frano, and Veziroglu, T.N., 1991, Environmental damage 

caused by fossil fuel consumption: International Journal of 

Energy, Environment, and Economics, v. I, no. 4. p. 297-310. 

Barklay, J.A., and Corless, A.J., 1992, Cost analysis of a magnetic liquefier in a fleet-size cryofuel refueling system, in 

Worek, W.M., and Pesaran, A.A., eds., Solar Energy Technology 1992, ASME Solar Energy Division publication, v. 13, 

p. 43-50. 

Bockris, J.O'M., and Veziroglu, T.N., 1985, A solar-hydrogen energy system for environmental compatibility: Environmental 

Conservation, v. 12, no. 2, p. I 05-118. 

Bockris, J.O'M., and Was, J.C., 1988, About the real economics 

of massive hydrogen production at 2010 A.D., in Veziroglu, 

T.N., and Protsenko, A.N., eds., Hydrogen Energy Progress 

VII, v. 2: Oxford, Pergamon Press, p. 101-151. 

Brewer, G.D., 1991, Hydrogen Aircraft Technology, Boca Raton, 

CRC Press. 

Chen, D.Z., Gurkan, 1., Veziroglu, T.N., and Sheffield, J.W., 

1982, Effective cost of fuels: comparison of hydrogen with 

fossil fuels, in Veziroglu, T.N., Van Vorst, W.D., and Kelley, 

J.H, eds., Hydrogen Energy Progress IV, v. 4: Oxford, Pergamon Press, p. 1523-1537. 

Davis, G .R., 1990, Energy for planet Earth: Scientific American, 

v. 263, no. 3, p. 55-62. 

DeLuchi, M., 1989, Hydrogen vehicles: an evaluation of fuel 

storage, performance, safety, environmental impacts, and 

cost: International Journal of Hydrogen Energy, v. 14, no. 2, 

p. 81-130. 

Energy Information Administration,1990, Annual Energy Outlook 1990, Long Term Projections: Washington, D.C.. U.S. 

Department of Energy, Energy Information Administration. 

Fulkerson, W.. Judkins, R.J., and Sanghvi, M.K., 1990, Energy 

from fossil fuels: Scientific American, v. 263, no. 3, p. 129-

135. 

Goebel, E., Coveney, Jr., R.M., Angina, E.E., Zeller, E.J., and 

Dreschhoff, G.A.M., 1984, Geology, composition, isotopes of 

naturally occurring H2/N2 rich gas from wells near Junction 

City, Kansas: Oil and Gas Journal, May 1984, p. 217-222. 

Haruta, M., Souma, Y., and Sano, H., 1982, Catalytic combustion 

of hydrogen: International Journal of Hydrogen Energy, v. 7, 

no. 9, p. 729-740. 

Kordesch, K., and Oliveira, J .C.T., 1988, Fuel cells: The present 

state of the technology and future applications, with special 

consideration of the alkaline hydrogen/oxygen (air) systems: 

International Journal of Hydrogen Energy, v. 13, no. 7, p. 

703-716. 

Ledjeff, K., 1990, New hydrogen appliances, in Veziroglu, T.N., 

and Takahashi, P. K., eds., Hydrogen Energy Progress VIII, 

v. 3: Oxford, Pergamon Press, p. 1429-1444. 

Moore, R.B., and Dahmias, D., 1991, Gaseous hydrogen markets 

and technologies, in Proceedings: Transition Strategies to 

Hydrogen as an Energy Carrier-First Annual Meeting of 

the U.S. National Hydrogen Association: Washington, D.C., 

Technology Transition Corporation, p. 11.1-11.17. 

Ogden, J.M., and Williams, R.H., 1989, Solar Hydrogen: Moving 

Beyond Fossil Fuels: Washington, D.C., World Resources 

Institute. 

Peschka, W., 1988, Technologies for the energetic use of hydrogen, in Winter, C.J., and Nitsch, J., eds., Hydrogen as an 

Energy Carrier: Berlin, Springer-Verlag, p. 30-55. 

Sherif, S.A., and others, 1991, Analysis and optimization of hydrogen liquefaction and storage systems, Proceedings DOE/ 

SERI Hydrogen Program Review Meeting, Washington, D.C. 

Steinberg, M., and Cheng, H.C., 1988, Modern and prospective 

technologies for hydrogen production from fossil fuels, in 

Veziroglu, T.N ., and Takahashi, P.K., eds., Hydrogen Energy 

Progress VIII, v. 3: Oxford, Pergamon Press, p. 699-739. 

Sternfeld, H.J., and Heinrich, P., 1989, A demonstration plant for 

the hydrogen/ oxygen spinning reserve: International Journal 

of Hydrogen Energy, v. 14, no. 10, p. 703-716. 

Williams, R.H., 1985, Potential roles for bioenergy in an energy 

efficient world: Ambio, v. 14, no. 405, p. 201-209. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Hydrogen Storage Systems 

By James A. Schwarz1 and K.A.G. Amankwah 1 

CONTENTS 

Abstract . .... .. .. ... ... . .. . ... . . ... . . .. .. .. . ....... .. .. . . .. . ...... .. . ... .. ....... 725 

Introduction ................................................................... 725 

Storage Technologies .................................................... 726 

Experimental ................................................................. 727 

Gravimetric ............................................................ 727 

Volumetric .............................................................. 728 

Modified Volumetric .............................................. 729 

Results . ...... .. ..... .... .. .. .... .. .. ... . ... ... .. . . .. ... .. ... ... ... .. .... .. . ... . . . 729 

Determination of Optimum Conditions for 

Carbon Storage-Gravimetric and Volumetric 

Experiments ........................................................... 730 

Modified Volumetric .............................................. 731 

Discussion ..................................................................... 732 

Comparison of Hydrogen Storage Alternatives .... 732 

Performance Evaluation ......................................... 732 

Cost Evaluations .................................................... 733 

Utility Cost ...................................................... 734 

Storage Unit .................................................... 734 

Cost for Energy Consumption ........................ 734 

Conclusions ................................................................... 735 

Acknowledgments ........................................................ 735 

References Cited ........................................................... 735 

ABSTRACT 

In order to use hydrogen as an energy carrier in modem energy-use systems, it is necessary to find compact, 

efficient means for storing hydrogen for mobile and (or) 

1

Department of Chemical Engineering and Materials Science, Laboratory for Advanced Storage Systems for Hydrogen, Syracuse University 

320 Hinds Hall, Syracuse, NY 13244-1190: 

stationary applications. Performance evaluations coupled 

with cost analyses for four major alternatives for hydrogen 

storage show that storage on activated carbon compares 

quite favorably with the other three options: storage in 

pressurized cylinder, storage on metal hydride, and storage 

as liquid. Gravimetric, volumetric, and modified volumetric laboratory experiments can be used to assess the storage properties of various activated carbons and ultimately 

identify which carbons and which pressure and temperature windows meet desired storage requirements. 

INTRODUCTION 

Energy systems in the 19th and 20th centuries have 

shown a systematic pr?gression of fuel sources from wood 

to coal to oil and now toward natural gas. Major advances 

in the quality of life in civilized nations have resulted as 

the primary energy infrastructure has moved closer to oil 

and natural gas, away from wood. Significant increases in 

energy content per fuel source have led to unprecedented 

energy-related advances in the transportation, buildings, 

and industrial sectors. 

Despite such benefits, it is becoming clear that the use 

of nature's fossil fuels is a transient privilege. Vital natural 

resources are finite, although demand for energy continues 

to grow. Eventually, a sustainable-energy economy must be 

developed that is not dependent on limited reserves of fossil resources. This type of economy requires nondepletable 

resources. Two categories of energy sources meeting this 

requirement are nuclear-based systems and renewable energy systems. Practically, however, energy use requires a 

form of energy that is convenient, flexible, adaptable, and 

controllable. Energy from the source should be deliverable 

virtually everywhere. Of the available options-such as 

wind, geothermal, and solar-hydrogen emerges as a prime 

candidate to become a significant energy carrier. 

725 
726 THE FUTURE OF ENERGY GASES 

The main benefits derived from using hydrogen are 

associated with its versatility after it has been produced 

and delivered to a user. The benefits include clean combustion in numerous devices and (or) efficient conversion 

to electricity in fuel cells. The major challenges to its use 

are finding efficient, cost-effective means for converting 

primary energy sources to hydrogen while still maintaining an environmentally benign impact, and finding efficient means of storing hydrogen for mobile and (or) 

stationary applications. 

STORAGE TECHNOLOGIES 

Development of efficient hydrogen storage capabilities 

is an important factor in the use of hydrogen as an alternative energy carrier. Hydrogen can be stored in three forms: 

gas, liquid, and solid. Research to date on hydrogen storage shows that pressurized tanks (gaseous Hz), liquid hydrogen, metal hydride (solid hydrogen), and adsorption on 

activated carbon (condensed phase of Hz) are all feasible 

storage systems (Noh and others, I987; Amankwah and 

others, I989; Carpetis, I980; Carpetis and Peschka, I980; 

Carpetis, 1982). The major advantages and disadvantages 

of these systems are presented in table I. 

Efforts have been directed to improve each system with 

respect to storage capacity, safety, and economic impact. 

But the intrinsic problems associated with the disadvantages of each system cannot be solved without a detailed understanding of the interplay between the safety, cost, size, 

and weight of the storage system. Among the four alternatives, particular attention has been focused on metal hydride systems, because they can store hydrogen in compact 

vessels at ambient temperature and at ordinary pressure. 

However, difficulties do exist because storage under these 

conditions requires the use of elevated temperature, and 

charging times are strictly controlled by diffusional effects 

(Williams, I980). Assuming these practical limitations can 

be overcome, this method would seemingly lead to a simple 

storage vessel manufactured in much the same way as 

today's gasoline tank. Unfortunately, the simplicity is an 

illusion, and factors such as heating and cooling requirements and excessive weight will make application of hydride storage impractical (Williams, I980). 

Storage on activated carbons has probably received, 

until recently, the least research, and thus its advantages 

have not been fully appreciated. The scientific basis for 

carbon storage is the principle that physical adsorption capacity is dramatically increased as temperature is lowered. 

Carpetis and Peschka ( 1980) have shown that activated carbons demonstrate the best storage performance when compared to other possible adsorbents. The high adsorption 

capacity of hydrogen on activated carbon is due largely to 

the high surface area of the carbon, which is one of its 

important characteristics. Different carbons with the same 

surface area, however, show different adsorption capacities 

for hydrogen. For example, Cabot-BP2000 and Darco-KB 

(industrial names of different carbons) have comparable 

surface areas of I ,500 mzlg, and their hydrogen uptake at 

25 atmospheres and 77 K is 32 g Hzlkg C and 24 g H2/kg 

C, respectively. It is clear that factors other than simply 

physical properties such as surface area influence the ability 

of activated carbon to adsorb hydrogen. This fact has led to 

studies to modify the surface chemical properties and microstructure of selected activated carbons (Agarwal and 

others, I987; Jagiello and others, I992a, b). 

The objective of this discussion is twofold. We first 

describe the laboratory procedures that allow us to identify 

activated carbons that meet desired storage requirements. 

From these laboratory results, we provide a performance 

and cost evaluation that is based on mid-1992 data. We 

then compare these results to those for the other storage 

options listed in table 1. 

In evaluating the options for a hydrogen storage system, it is not feasible to provide a clearcut evaluation matrix that can be applied to all circumstances. The choice of 

an optimum system should depend on the storage requirements. For example, the weight factor is more crucial than 

size for onboard vehicle storage (Eklund and von Krusenstierna, I983). For qualitative comparison, however, evaluation of performance and cost is presented because these 

are the most important factors in the selection of the optimum system. The estimated costs and performance data 

for systems other than activated carbon are values that 

Table 1. Advantages and disadvantages of various hydrogen storage systems. 

Storage system Advantages Disadvantages 

GH2 (compressed gaseous hydrogen)------------- Economical, simple------------------------- Hazardous, bulky. 

LH2 (liquid hydrogen)------------------------------- High density --------------------------------- Cryogenic problem, requires insulation (ZO K). 

MH2 (solid hydrogen in FeTi alloy)--------------- Compact size; relatively safe-------------- Heavy and expensive; chemically 

unstable, susceptible to poisoning. 

C-S (hydrogen on activated carbon) -------------- Moderate size and weight; moderate Requires insulation for cold 

cost. temperature. 
HYDROGEN STORAGE SYSTEMS 727 

have been reported in the literature (Carpetis, I980, I982; 

Carpetis and Peschka, 1980; Eklund and von Krusenstierna, I983; Wallace and Ward, I983; Stannard, 1984; 

Davidson and others, I984). For activated-carbon systems, 

performance data are based on our laboratory experiments. 

EXPERIMENTAL 

Our data base for assessing the storage properties of 

activated carbons is determined by three tiers of experiments: gravimetric, volumetric, and a modified volumetric 

method. Each is described below. 

GRAVIMETRIC 

A Cahn I 000 microbalance is used for adsorption 

measurements. The balance housing is made of stainless 

steel. A schematic representation of the adsorption apparatus is shown in figure 1. The balance can be operated between pressures of 1 o-6 atmospheres and I 02 atmospheres. 

The pressures are measured by transducers. Pressures up 

to 1.3 atmospheres are measured by an MKS capacitance 

manometer model 222B. Pressures higher than 1.3 atmospheres are measured by Data Instruments Transducer 

model EA. 

All the temperature measurements are made by a 

chromel-alumel thermocouple placed internal to the balance on the sample side. Care is taken to ensure that the 

thermocouple does not touch the pyrex tube holding the 

control 

valve 

SAMPLE SIDE 

sample or the wire on which this tube is suspended. The 

thermocouple is connected to a compensating reference 

junction. Use of this junction ensures that changes in room 

temperature do not affect the temperature reading. The 

thermocouple is calibrated at the ice point against a standard thermometer. 

A 30-mm-high Pyrex tube with 4-mm outside diameter is used to hold the sample. A 200-mesh stainless steel 

screen is placed at the bottom of the Pyrex tube to support 

the sample. The balance is calibrated by placing suitable 

weights on the tare side to counterbalance this Pyrex tube. 

The calibration of the balance is checked from time to 

time. All the weight measurements are carried out in the 

I-mg range on the microbalance. The weight measurements are recorded on a Hewlett Packard model 7220 

strip-chart recorder. The least count of each weight measurement is 4 ~-

For adsorption measurements, about 100 mg of the 

sample is placed in the holder. The sample is heated to 

393 K and evacuated to w-6 atmospheres. The evacuation 

and heating are continued until no further weight loss of 

the sample takes place. This procedure ensures removal of 

preadsorbed gases. The measured weight of the sample at 

this stage is considered to represent its degassed weight. 

After this pretreatment, adsorption experiments are commenced. A coolant dewar flask is raised to surround the 

sample tube. The sample is positioned 350 mm below the 

level of the coolant. Because the upper part of the balance 

is at room temperature, temperature gradients are set up on 

the sample side. Unless the sample is placed well below 

the level of the coolant outside, its temperature may be 

Pump 

TARE SIDE 

Figure 1. Schematic representation of apparatus for measuring adsorption of hydrogen 

on activated carbon. See text for explanation. 
728 THE FUTURE OF ENERGY GASES 

different from that of the coolant. It was found that a 

height of 350 mm is adequate to obtain an inside temperature that is the same as that of the outside coolant. 

After the dewar flask has been filled with the coolant, 

the evacuation is stopped and a small amount of the gas 

is bled into the system to ensure rapid equilibration of the 

outside and inside temperature. The amount of gas varies 

with each experiment and typically corresponds to the 

lowest value of the pressure desired for an experiment. 

The lowest value for any . experiment is about 10-3 

atmospheres. 

After the temperature has been stabilized, adsorption isotherms are measured. Each isotherm is composed of 20 to 30 measurements at different pressures. 

Adsorption equilibrium is considered achieved when no 

further increase in weight takes place for· at least 5 minutes at a uniform pressure. Because the least count of 

the balance output is 4 [.lg, at equilibrium, the rate of 

increase in weight is less than 0.8 [.lg/minute. Typical 

equilibrium times are around 20 minutes. (In a few 

cases, adsorption at a given pressure was measured up 

to 60 minutes. The adsorption values after 20 and 60 

minutes were found to be the same.) pesorption isotherms are also obtained. In all cases, adsorption and 

desorption isotherms are identical. 

In the adsorption experiments, only the sample side is 

temperature controlled; the tare side is always at room 

temperature. This difference results in asymmetry in the 

balance operation. Buoyancy corrections are thus necessary. Buoyancy results from the displacement of gas by 

the sample, sample holder, adsorbed phase, and tare 

.c: 

Q) 

0"1 

0 

-g, 

J: 

Gas tank 

A. Deoxo unit 

B. Molecular sieve unit 

C. Flow controller 

D. Carbon in U-tube 

E. Freon refrigerator 

F. Pressure transducer 

G. Vacuum transducer 

H. Diffusion pump 

B 

weights and pan. The corrections due to the tare weights 

and sample holder are estimated by blank runs. In the 

blank runs, experiments are carried out on an empty sample holder at temperatures and pressures that are similar 

to conditions during an adsorption run. The resulting corrections are plotted as a function of pressure at a given 

temperature. From these plots, correction values are determined and added to the corresponding adsorption values. 

The buoyancy due to the sample results in an apparent 

loss in weight during the adsorption measurement. This 

apparent loss in weight is estimated by the skeletal volume of the sample. The sample buoyancy is calculated as 

a product of skeletal volume and gas density at the given 

temperature and pressure. The gas density is calculated by 

a modified Benedict-Webb-Rubin (BWR) equation as developed by Lee and Kesler (1975). 

VOLUMETRIC 

The experimental set-up for volumetric measurements of adsorption of hydrogen on activated carbon is 

shown schematically in figure 2. A deoxo purifier (model 

D) manufactured by Engelhard Industri~s is vsed to pretreat the hydrogen. A mass flow controller (model 

5850C) and totalizer (model 450) manufactured by 

Brooks Instrument Division of the Emerson Electric Co. 

ar~ used to determine the amount of charged hydrogen 

~as. The equilibrium pressure is· recorded by a pressure 

transducer (model EA) and digital pressure indicator 

(model PL-1), both manufactured by Data Instruments, 

Figure 2. Schematic representation of volumetric apparatus for measuring adsorption of 

hydrogen on activated carbon at high pressures. See text for explanation. 
HYDROGEN STORAGE SYSTEMS 729 

Inc. A vacuum transducer (type 0531) manufactured by 

Varian and a vacuum pump (model No. 1400) manufactured by Sargent Welch Scientific Co. are used to determine_ when the discharging step is completed. The freon 

refrigerator (model No. MC-8-120A-l) is manufactured 

by FTS Systems, Inc. 

Because scaled-up experiments cannot be performed 

on a microbalance, a volumetric approach is used. Experiments are conducted at different temperatures. Weighed 

amounts of carbon, previously dried in an oven, are 

charged as efficiently and quickly as possible into a 

U-tube. A heating tape surrounding the U-tube supplies 

heat to the carbon while under vacuum in order to rid it 

of small amounts of moisture that might be adsorbed during the loading period. A vacuum reading of less than 

6.5x w-5 atmospheres is our criterion that there is no 

moisture left in the system. Desired amounts of hydrogen 

are charged into the U-tube via the mass flow controller 

(item C, fig. 2), which is connected to a calibrated totalizer. This arrangement enables us to determine the 

amount of hydrogen that has been charged into the vessel 

at any time. An average time of 30 minutes is found to 

be necessary for equilibrium to be achieved. The pressure 

reading on the indicator and totalizer readings are then 

recorded. An additional amount of hydrogen is then 

charged into the vessel in order to determine the next 

equilibrium point. These steps are repeated until equilibrium pressures of about 54 atmospheres are reached. 

Isothermal discharging (pressure swing) alone was 

considered in an earlier publication for the recovery of 

hy_drogen (Carpetis and Peschka, 1980). At a low-pressure 

level of about 2 atmospheres, isothermal discharging 

leaves substantial amounts of hydrogen unrecovered. The 

recovery of this residual amount is essential, for example, 

in mobile application. Total recovery can be ·achieved by 

both pressure and temperature swing (P-T swing). The 

temperature swing involves the application of heat by any 

appropriate means depending on the configuration of the 

system. Accordingly, we applied the P-T swing in our 

work. 

After the completion of the adsorption experiment at 

a particular temperature, the stored amount is discharged 

first by a pressure swing down to the 2-atmosphere level. 

Heat is then supplied (nonisothermal discharging) to the 

activated carbon by means of the heating tape surrounding 

the U-tube. This continues until a vacuum of 6.5xi0-5 atmosphere or less is attained. Total. amount stored is determined directly from the totalizer reading. We calculate the 

amount of void space on the basis of the equilibrium 

pressure reading and the bed porosity, which is the fraction of U-tube unoccupied by the activated carbon. By 

difference, we obtain the adsorbed amount, the component 

which represents the actual amount stored on the surface. 

These values can be compared directly with gravimetric 

data on the same carbon. 

MODIFIED VOLUMETRIC 

In order to determine the optimum conditions· for a 

practical hydrogen storage system, a number of experiments have to be ·performed in order to answer the following question: For a chosen carbon sample, how does the 

charging procedure affect the adsorption characteristics of 

the carbon and the storage amount of hydrogen? Charging 

procedures consist of rate of charging, maximum pressure 

reached during charging, and amount of time required for 

charging. Charging characteristics refer to the rate at 

which the system pressure falls off until equilibrium is 

reached. Needless to say, the structural heterogeneity and 

chemical functionality of the chosen carbon will play a 

significant role during the whole process of adsorption. 

The vessel used in this experiment has an internal volume of I liter and is 'made from a composite of carbonfiber/epoxy-filament windings. This vessel is charged with 

323 g of carbon sample. The carbon sample is first conditioned by evacuation, followed by a purge of warm helium 

gas. The system is then evacuated to a vacuum of 1.3xl0·5 

atmospheres. The vessel sits in a dewar flask (item G, 

fig. 3) filled with liquid nitrogen. Two thermocouple 

probes are inserted into the vessel; one measures the temperature of the carbon sample while the other measures 

the temperature of the gas in the void space. These temperatures are expected to be the same at equilibrium. The 

pressure within the vessel is measured by means of a pressure transducer (model EA) and a pressure indicator 

(model PL-1 ), both of which were obtained from Data Instruments in Acton, Mass. A schematic drawing of this apparatus is shown in figure 3. 

Adsorption is carried out by passing hydrogen gas 

through a 50-ft coiled copper tube that sits in a dewar 

flask (item B) filled with liquid nitrogen. The cold gas 

then enters the carbon-containing vessel. Using this experimental procedure, a number of charging variables can be 

studied. 

. A Brooks mass flow controller (item E) has been installed on the downstream side of the system. This controller is connected to a totalizer that measures the amount 

of hydrogen stored in the vessel. Discharged amounts 

from the vessel can be measured when pressure swing is 

applied from ,one pressure to the other. 

In all experiments, hydrogen gas of ultra-high purity 

grade (99.9999 percent), was supplied by Linde Specialty 

Gas Division of Union Carbide. The hydrogen is purified 

by means of a deoxo unit and a molecular sieve-unit immersed in a liquid-nitrogen trap. 

RESULTS 

Selected results using the apparatuses described in the 

previous section are described below. 
730 THE FUTURE OF ENERGY GASES 

A 

A. Deoxo unit 

B. Liquid-nitrogen 

container 

C. Cooling coil 

D. Storage vessel 

E. Flow controller 

F. Vacuum pump 

G. Dewar flask for 8 

storage vessel 

H. Pressure Transducer 

J. Thermocouple 

.---..-To end use 

E 

J 

D F 

L...-.------'G 

Figure 3. Schematic representation of modified-volumetric apparatus for studying how 

charging procedure affects adsorption characteristics of carbon sample and the determination of storage amount of hydrogen. Sec text for explanation. 

DETERMINATION OF OPTIMUM CONDITIONS 

FOR CARBON STORAGE-GRAVIMETRIC AND 

VOLUMETRIC EXPERIMENTS 

Two types of activated carbon, designated as carbon A 

and carbon B, are considered here for discussion purposes. 

Carbon A is granular whereas carbon B is powdery. Stored 

amounts of hydrogen in a vessel are composed of two 

components: the adsorbed component and the void component. The adsorbed component depends on the microstructure and surface chemical functional groups of the 

activated carbon. The void component, for a given condition of temperature and pressure, depends on the bulk density of the carbon, which in tum depends on the degree of 

packing of the carbon in the container. 

To facilitate the discussion, we present in figure 4 volumetric data for hydrogen storage on carbon A at 150 K. 

A study of the plot shows that at approximately 55 atmospheres, the amount of hydrogen in the void becomes 

comparable to the amount of adsorbed component. Consequently, there is no need to increase the pressure any further, because the resulting condition becomes comparable 

to a small-volume compressed-gas storage system. A study 

of the plot shows furthermore that the difference between 

the adsorbed and void components (the difference amount, 

or DA) reaches a maximum at about 20 atmospheres. It 

then starts to decrease until it reaches zero at about 55 

atmospheres. 

The question arises as to when an optimum condition 

is reached. Does one choose an optimum when the DA 

value is zero or when it reaches a maximum? Regardless 

of which DA value is chosen, the ultimate goal of storage 

is to store as much hydrogen as conveniently possible. Examination of figure 4 shows that a DA value of zero corresponds to a total stored amount (TSA) of 93 g H2/kg C 

(9.3 percent) for carbon A. A maximum DA value at about 

20 atmospheres corresponds to a TSA of 45 g H2/kg C 

(4.5 percent). We note, however, that the latter condition is 

more efficient when one considers the rationale for using 

an adsorbent. This rationale is to concentrate as much 

100 

90 

80 

70 

60 

50 

40 

30 

20 

1 0 

0 

0 20 40 60 

PRESSURE, IN ATMOSPHERES 

Figure 4. Hydrogen storage on carbon A at 150 K. Diamonds, 

hydrogen stored in void spaces in carbon sample; open squares, 

hydrogen adsorbed on carbon surfaces; solid squares, total stored 

amount (TSA) of hydrogen. 
HYDROGEN STORAGE SYSTEMS 731 

hydrogen in a given volume or space without much increase in weight of the system. However, for this case we 

chose the stored amount of 93 g H2/kg C, which corresponds to a moderate pressure of 55 atmospheres. 

Let us consider the stored amounts of hydrogen on 

carbons A and B at 78 K. Figure SA for carbon A shows 

that the DA value reaches a plateau at about 11 atmospheres. This corresponds to a TSA of 5.7 percent, which 

is a relatively small amount. Such a case, for which a 

140 

a: Wz 120 c.. a 

zcc We:: 100 

8<( 

a::o 80 

c:E ><( 60 J:C::: 

en" 40 ::o 

~~ 20 

(.!) 

0 

0 20 40 60 

PRESSURE, IN ATMOSPHERES 

A 

120 

100 

80 

60 

~· 

~~--o 0 ,, ,,.-·---+---- ------· -+----+-

40 

20 

0 1 0 20 30 40 

PRESSURE, IN ATMOSPHERES 

B 

Figure 5. Hydrogen storage at 78 K on (A) carbon A, and (B) 

carbon B. Solid diamonds, hydrogen stored in void spaces in carbon sample; open squares, hydrogen adsorbed on carbon surface; 

open diamonds, difference between adsorbed hydrogen and hydrogen in void spaces (difference amount, or DA); solid squares, 

total stored amount (TSA) of hydrogen. 

maximum DA value has been attained but corresponds to 

a low TSA value, is not acceptable. Do we then accept a 

condition that corresponds to a DA value of zero and 

probably a relatively high TSA? Not necessarily. Another 

look at figure 5A shows that at 52.5 atmospheres, a DA 

value corresponding to half the maximum DA value will 

suffice. This case corresponds to a TSA of 12.1 percent. 

Clearly, a DA value equal to zero will result in a greater 

TSA but at the unnecessary expense of increased pressure. 

Figure 5B represents the case of carbon B. It can be seen 

that the intermediate DA value chosen at a lower pressure 

of 39.2 atmospheres is suitable, because it corresponds to 

an acceptable TSA of I 1.9 percent. 

The foregoing discussion leads to the following observations: (I) The TSA is optimized on a the basis of a reasonable choice of pressure and DA value, and (2) this 

optimization is strongly dependent on temperature of storage, adsorption characteristics of the carbon, and bulk density of the adsorbent. 

MODIFIED VOLUMETRIC 

Once a carbon's static adsorption properties have been 

established, we use the modified volumetric approach to 

determine the process variables for optimization of dynamic 

charging. Here, following contact between gas and solid, 

the hydrogen pressure is stepped to a higher value, and the 

relaxation of the system to an equilibrium state is measured. 

It can be noted from figure 6 that, for another carbon 

designated C, the maximum pressure applied in one case 

(70 atmospheres) was lower than that applied in another 

case (74 atmospheres). However, the equilibrium pressure 

(39 atmospheres) attained for the first case was higher than 

en 75 

w 

a: 70 w 

J: 65 c. 

en 

0 60 

~ 55 

;E; 50 

wn 45 a: 

::::> 40 ~ w 35 

a: 

Q. 30 

0 1 0 20 30 40 

TIME, IN MINUTES 

Figu're 6. Charging characteristics of carbon C. Open squares, 

maximum applied pressure of 70 atmospheres; solid squares, 

maximum applied pressure of 74 atmospheres. 
732 - THE FUTURE OF ENERGY GASES 

that for the latter case (34 atmospheres). The equilibrium 

temperature for both cases was 116 K. Equilibrium time 

was about lO minutes for both tests. The inverse relation · 

between maximum pressure and equilibrium pressure in the 

two cases is due to different initial conditions of the carbon 

before charging took place. In the first test, cold hydrogen 

gas was flushed through the system at very low pressures 

for a longer period than for the second test. This longer 

period allowed the gas molecules more time to penetrate 

the micropores of the carbon bed. Consequently, most of 

the higher energy sites for adsorption had been occupied 

before the final charging was started. Therefore, even at a 

lower charging pressure, the equilibrium pressure was higher in the first test than in the second. (This aspect of initial 

conditioning of the bed becomes very important in determining the maximum allowable tf!mperature the carbon 

should reach during the discharge process in, for example, 

an automobile.) The TSA at 39 atmospheres was I 0.16 percent, whereas the TSA at 34 atmospheres was 9.65 percent. 

DISCUSSION 

COMPARISON OF HYDROGEN 

STORAGE ALTERNATIVES 

The various alternatives to be compared are coded as 

follows: 

Compressed gaseous hydrogen, pressurized to 

150 atmospheres (steel vessel) or ~o 200 atmospheres (Kevlar vessel) 

Liquid hydrogen, in a cryogenic tank 

Metal hydride-solid hydrogen in FeTi alloy 

Hydrogen storage on activated carbon at 113 

K, 54 atmospheres 

Table 2. Performances of hydrogen storage systems. 

Storage system Vessel 

In the case of C-S, we note that the material of construction for the vessel is carbon-fiber/epoxy-filament 

winding. It has been recommended for hydrogen vessels 

(Structural Composites Industries, Pomona, Calif., personal commun., 1992). See Noh and others (1987) for explanations for an assumed working pressure of 200 

atmospheres for the GH2 system and the use of FeTi for 

the MH2 system. 

PERFORMANCE EVALUATION 

Evaluation of performance was based on mobile applications and two indexes: (I) the weight efficiency, and (2) 

the volume efficiency. For the C-S system, it was found 

that conditions corresponding to a temperature of 113 K 

and a pressure of 54 atmospheres were satisfactory. These 

conditions were attained on an activated carbon, here designated carbon C, whose surface area is 2,230 m2/g. The 

TSA was 12.1 percent. The performance under these conditions has been compared to those of other alternatives in 

table 2. To provide a complete perspective, data for conventional gasoline fuel systems are included. 

In order to have a practical basis for comparison of 

these alternative forms of storage, we cite specific examples of vehicles from DeLuchi's paper (1989) in table 3. We 

have included in this table our own laboratory data. The 

choice of 0.87 million Btu's (MMBtu) is comparable to 

values cited by Deluchi. This amount of hydrogen is sufficient for a range of approximately 310 miles. We reconstructed table 2 based on the results of table 3 and present 

the findings in table 4. It is important to note that these data 

are representative of actual systems. We find that carbon 

storage is very competitive with the other alternatives when 

comparing values for weight or volume efficiency. 

Weight efficiency, in 

(g H2/kg C)x I 00 

(percent) 

Volume efficiency. in 

kg H2/total volume of system 

(kg/m3) 

GH2 (compressed gaseous Steel (150 atmospheres)---------- !.50 ·12.10 

hydrogen). Kevlar (200 atmospheres)-------- 3.10 11.20 

LH2 (liquid hydrogen)---------- Steel --------------------------------- 13.00 46.90 

Aluminum -------------------------- 23.70 46.90 

MH2 (solid hydrogen in FeTi FeTiH2------------------------------- 1.40 36.50 

alloy). 

C-S (hydrogen on activated Carbon-fiber/fpoxy-filament 7.22 39.00 

carbon). winding (113 K, 54 atmospheres). 

Gasoline--------------------------- Steel --------------------------------- 31.00 260.00 
HYDROGEN STORAGE SYSTEMS 733 

Table 3. Comparison of different methods of hydrogen storage. 

[Musashi, Japanese-manufactured vehicle; MB, Mercedes Benz; MMBtu, million British thermal units] 

Amount of Hz Energy density 

Storage system 

Total weight of 

system (kg) 

Total volume of 

system (L) Weight Energy (Btu/kg) (Btu/L) 

GH2 (204 atmospheres)------------------

LH2 Musashi ------------------------------

MH2 (TiVMn) MB 310 van------------

C-S (113 K, 54 atmospheres)-----------

97.72 

45.76 

574.00 

92.00 

Table 4. A reconstruction of table 2 based on table 3. 

[Musashi, Japanese-manufactured vehicle; MB, Mercedes Benz] 

574.0 

198.1 

170.0 

170.0 

Storage system 

Weight efficiency 

in (g H2/kg C)xiOO 

(percent) 

Volume efficiency in 

kg H2/total volume 

of system (kg/m3) 

GH2 (204 atmospheres) ------------

LH2 Musashi -------------------------

MH2 (TiVMn) MB 310 van-------

C-S (ll3 K, 54 atmospheres) -----

6.87 

11.13 

1.045 

7.22 

COST EVALUATIONS 

11.70 

29.07 

35.29 

39.00 

The comparison of costs for each alternative is based 

on data for medium to large stationary power systems. For 

the cost analysis, the guidelines in previous publications 

(Carpetis, 1980, 1982; Carpetis and Peschka, 1980) have 

been followed in a consistent manner. These guidelines are 

in accordance with the use of standardized module factors 

(Guthrie, 1969). 

The baselines for the comparative .cost evaluation 

are for medium-large-scale storage systems. These are as 

follows: 

(1) Maximum storable energy amount (19,200 

million British thermal units (MMBtu)) 

(2) Rated charging power of storage device (200 

megawatts (MW)) 

(3) 50 percent usage of storage capacity 

(4) · 360 charge-discharge cycles per year 

(5) 14 hours per day of charging storage device 

(6) Capital recovery factor of 15 percent 

(7) Personnel and maintenance cost of 2.5 percent 

(8) Electricity cost of $0.09 per kilowatthour (kWh) 

(9) Activated carbon cost of $12.00/kg 

All cost values are estimates and are in mid-1992 dollars. We used cost indexes (Economic Indicators, 1988, 

1992) to update cost estimates reported previously (Eklund 

(kg) (MMBtu) 

6.72 0.90 9,209 1,568 

5.76 0.76 16,608 3,836 

6.00 0.804 1,401 4,729 

6.63 . 0.87 9,456 5,II7 

Table 5. Cost for utility units. 

[See text for explanation of storage systems. Costs are in mid-1992 dollars. Values 

in column ··cost/million Btu., do not include C<?sts for energy consumption. which 

are shown in table 7. atm. atmosphere; Btu, British thermal unit] 

Storage 

system 

GH2 -----

LH2 -----

MH2-----

C-S ------

Utility unit 

Compressor (up to 200 atm) ------

Refrigerator--------------------------

Compressor --------------------------

Compressor (up to 100 atm) 

plus vacuum pump. 

Refrigerator --------------------------

Table 6. Cost for storage units. 

Unit cost 

(million dollars) 

8.98 

12.92 

6.73 

8.98 

12.92 

Cost/million 

Btu (dollars) 

. 0.46 

0.66 

0.34 

0.46 

0.66 

[See text for explanation of storage systems. Costs are in mid-1992 dollars. 

Btu, British thermal unit] 

Storage system Storage unit' Cost/million Btu 

(dollars) 

G H2 ----------- Vessel---------------------------------- 3. 77 

LH2 ----------- Vessel with insulation--------------- 1.09 

MH2----------- Metal (FeTi alloy) vessel with 3.63 

heat exchanger. 

C-S ------------ Vessel with insulation--------------- 2.97 

and von Krusenstierna, 1983; Wallace and Ward, 1983; 

Davidson and others, 1984; Stannard, 1984; Amankwah 

and others, 1987). The six-tenths power factor rule (Peters 

and Timmerhaus, 1980) was applied to account for changes in vessel volume. The cost comparisons for the powerassociated term, capacity-associated term, and energy 

consumption are all on a per-MMBtu basis in tables 5, 6, 

and 7, respectively. The total costs for each alternative are 

listed in table 8. Brief examples of the cost calculations 

for selected storage alternatives are presented below. 
734 THE FUTURE OF ENERGY GASES 

Table 7. Cost for energy consumption. 

[See text for explanation of storage systems. Costs are in mid-1992 

dollars. atm, atmosphere; Btu, British thermal unit; K, degrees 

Kelvin; kWh, kilowatthour] 

Electricity 

Function of utility consumption Cost/million Btu 

Storage system unit (kWh per (dollars) 

million Btu) 

GH2 ---------- Compression 7.35 0.66 

(200 atm). 

LH2 ---------- Liquefaction 90.12 8.11 

at 20 K. 

MH2 --------- Compression 15.07 1.36 

heating. 

C-S ----------- Compression 28.09 2.53 

cooling, and 

heating. 

UTILITY COST 

The unit costs for the various alternatives shown in 

table 5 are updated versions of cost values presented by 

Carpetis and Peschka (1980). The dollar amount per 

MMBtu is calculated on the basis of the assumed baselines. As an example, let us consider the compressor for 

the compressed-gas alternative. 

Unit or capital cost 

Storage capacity 

Capital cost per MMBtu 

= $8.98xl06 

= 19,200 MMBtu 

$8.98xl06 

19,200 MMBtu 

$467.7/MMBtu 

Sum of capital recovery factor and personnel and maintenance cost is 

(15+2.5) percent = 17.5 percent. 

Taking these into account, the cost of utility per year is 

17.5 percent of $467.7/MMBtu = $81.85/MMBtu. 

360 cycles per year will make the cost per cycle 

become equal to 

$81.85/MMBtu = $0.23/MMBtu. 

360 

Utilization of storage capacity is 50 percent, hence the 

final cost is 

($0.23/MMBtu)x2 = $0.46/MMBtu. 

STORAGE UNIT 

A similar approach was taken for calculation of costs 

for the storage units. The overall total cost can be found in 

Table 8. Total cost for storage systems. 

[See text for explanation of storage systems. Costs are in mid-1992 dollars. Btu, 

British thermal unit] 

Cost of utility Cost of storage 

Storage system unit (dollars unit (dollars 

per million Btu) per million Btu) 

Cost of energy Total cost 

consumption (dollars 

(dollars per per million 

million Btu) Btu) 

GH2 --------- 0.46 3.77 0.66 4.89 

LH2 --------- 0.66 1.09 8.11 9.86 

MH2 -------- 0.34 3.63 1.36 5.33 

C-S ---------- 1.12 . 2.97 2.53 6.62 

the paper by Carpetis and Peshka ( 1980), with the exception of that for the C-S system. 

The storage-unit cost of the C-S system is composed of 

the cost of carbon and that of the empty vessel. For a 

19,200-MMB tu storage device, the amount of hydrogen required can be calculated on the basis of the heating value 

(0.115 MMBtu/kg H2) of hydrogen. This calculation leads 

to the amount of carbon needed since the weight efficiency 

(12.1 percent) based on the carbon adsorbent alone is 

known. The carbon-fiber/epoxy-filament winding vessel 

weighs 180 kg for every cubic meter of internal volume. An 

estimated future cost of this vessel is $66.00/kg. This could 

be an overestimation, but we prefer to be on the conservative side rather than be overly optimistic. 

COST FOR ENERGY CONSUMPTION 

Data for energy consumption for the GH2, LH2, and 

MH2 systems are based upon values reported by Carpetis 

(1980, 1982) and Carpetis and Peschka (1980). The values 

for the C-S system were obtained using standard thermodynamic equations. A 40-percent efficiency was assumed. 

The total cost for the various storage systems is summarized in table 8. It is very obvious that the energy consumption component for the LH2 system makes this 

option the most expensive. Next in line comes the C-S 

system. For the same reason, the total cost of the C-S system is higher than those for the GH2 and MH2 systems. 

The energy requirement for the C-S system is composed 

of compression and cooling components primarily, with 

the heating component being a small fraction. It is the 

cooling requirement that makes the C-S energy consumption component relatively large. 

From table 8, the GH2 system is the least expensive of 

the storage systems considered. The MH2 system is also 

less expensive than the C-S system; however, the total 

cost shown in table 8 for the MH2 system could be misleading because most metallic alloys that could be used 

for hydrogen storage systems are more expensive and re-
HYDROGEN STORAGE SYSTEMS 735 

quire higher storage temperatures than the Fe-Ti alloy assumed for table 8. Such differences would affect the 

storage unit and energy consumption components of MH2 

systems in general. It is hoped in the case of the C-S system that current research will lead to the manufacture of 

high-capacity storing adsorbents in the refrigeration temperature range, that is 150-200 K. Consequently, the energy-consumpti~n costs for the C-S system are likely to 

decrease considerably in the near future. 

CONCLUSIONS 

Efficient and cost-effective hydrogen storage is important if hydrogen storage systems are to become 

competitive with existing technologies, particularly in 

transportation applications, which require high-energydensity and lightweight storage. For utility and other 

stationary applications, the energy density and weight 

are not of prime consideration, but storage efficiency 

and systems costs are major considerations. 

ACKNOWLEDGMENTS 

The authors thank Dr. J. Wegrzyn of Brookhaven National Laboratories and Mr. A. Mezzina for their encouragement. Financial support has come from the U.S. 

Department of Energy via the National Renewable Energy 

Laboratory under contract XC-2-11081-1. Collaboration 

with Mr. William Hoagland is also acknowledged. 

REFERENCES CITED 

Agarwal, R.K., Noh, J.S., and Schwarz, J.A., 1987, Effects of 

surface acidity of activated carbon on hydrogen storage: 

Carbon, v. 25, p. 219-226. 

Amankwah, K.A.G., Noh, J.S., and Schwarz, J.A., 1989, Hydrogen storage on superactivated carbon at refrigeration temperatures: International Journal of Hydrogen Energy, v. 14, 

p. 437-447. 

Bandosz, T.J., Jagiello, J., and Schwarz, J.A., 1992, Comparison 

of methods to assess surface acidic groups on activated carbons: Anal. Chern., v. 64, no. 8, p. 891-895. 

Carpetis, C., 1980, A system consideration of alternative hydrogen storage facilities for estimation of storage costs: International Journal of Hydrogen Energy, v. 5, p. 423-437. 

---1982, Estimation of storage costs for large hydrogen storage facilities: International Journal of Hydrogen Energy, 

v. 7, p. 191-203. 

Carpetis, C., and Peschka, W., 1980, A study of hydrogen storage 

by use of cryoadsorbents: International Journal of Hydrogen 

Energy, v. 5, p. 539-554. 

Davidson, D., Fairlie, M., and Stuart, A.E., 1984, Development 

of a hydrogen-fueled farm tractor, in Advances in hydrogen 

energy, v. 4: Oxford, Pergamon Press, p. 1623-1630. 

Deluchi, M.A., 1989, Hydrogen vehicles-An evaluation of fuel 

storage, performance, safety, environmental impacts, and 

cost: International Journal of Hydrogen Energy, v. 14, p. 81-

130. 

Economic Indicators, 1988: Chemical Engineering, v. 95, p. 9. 

Economic Indicators, 1992: Chemical Engineering, v. 99, p. 224. 

Eklund, G., and von Krusenstierna, 0., 1983, Storage and transportation of merchant hydrogen: International Journal of Hydrogen Energy, v. 8, p. 463-470. 

Guthrie, K., 1969, Data and techniques for preliminary cost estimating: Chemical Engineering, v. 76, p. 114-142. 

Jagiello, J., Bandosz, T.J., and Schwarz, J.A., 1991, Application 

of inverse gas chromatography at infinite dilution to study 

the effects of oxidation of activated carbons: Carbon, v. 30, 

p. 63-69. 

---1992a, A study of the activity of chemical groups on 

carbonaceous and model surfaces by infinite dilution chromatography: Chromatographia, v. 33, nos. 9, 10, p. 441-

444. 

---1992b, Inverse gas chromatographic study of activated 

carbons-The effect of controlled oxidation on microstructure and surface chemical functionality: Journal of Colloid 

and Interface Science, v. 151, no. 2, p. 433-445. 

Lee, B.I., and Kesler, M.G., 1975, Generalized thermodynamic 

correlation based on three-parameter corresponding states: 

Journal of American Institute for Chemical Engineers, v. 21, 

p. 510-527. 

Noh, J.S., Agarwal, R.K., and Schwarz, J.A., 1987, Hydrogen 

storage systems using activated carbon: International Journal 

of Hydrogen Energy, v. 12, p. 693-700. Also, see J.A. 

Schwarz, U.S. Patent 4,716,736, assigned to Syracuse 

University. 

~ Peters, M.S., and Timmerhaus, K.D., 1980, Plant design and economics for chemical engineers: Tokyo, McGraw-Hill 

Kogakutha Ltd., p. 166-168. 

Stannard, J.H., 1984, Hydrogen fuel cell for high capacity buses, 

in Advances in hydrogen energy, v. 4,: Oxford, Pergamon 

Press, p. 1729-1741. 

Wallace, J.S., and Ward, C.A., 1983, Hydrogen as a fuel: International Journal of Hydrogen Energy, v. 8, p. 255-268. 

Williams, L.O., 1980, Hydrogen power-An introduction to hydrogen energy and its applications: New York, Pergamon 

Press, p. 115. 
Natural gas is produced from a variety of geologic 

settings, and it must be distributed over long distances 

and through a wide network where demand fluctuates 

over long- and short-term periods. These issues govern 

fluctuations and deliverability of energy gases from the 

wellhead to end users. All fuels compete with one 

another in terms of price, availability, and environmental 

concerns. Complex models for predicting natural-gas 

consumption have been developed to incorporate these 

factors. The reports in this section describe the role of 

economics in determining the amount of gas that is 

available, and the decisions end users and producers 

must make when choosing energy resources from 

among the various fuel options. 

ECONOMICS 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

History of Natural-Gas Consumption in the United States 

By Michael Fanelli 1 

CONTENTS 

Abstract ................................................. '........................ 737 

Introduction ................................................................... 737 

Early Years .................................................................... 738 

A Period of High Growth for the Industry .................. 738 

The Beginning of Instability for the Gas Industry ...... 740 

Continued Attempts at Regulation ............................... 742 

The Natural Gas Policy Act of 1978 ............................ 744 

What Goes Up Might Come Down ............................. 744 

The Future of the Natural-Gas Industry ....................... 746 

References Cited ........................................................... 747 

ABSTRACT 

The history of the natural-gas industry illustrates a 

complex interplay of technological advancement, economic activity, federal regulation, and competition among 

fuels. These factors have all influenced the industry's 

growth and stability. Historical statistics document how, 

over recent decades, gas exploration and development activities have varied greatly from high levels to low levels. 

Perceptions and estimates of the Nation's natural-gas resource base have influenced natural-gas availability and 

demand. The use of gas in various end-use sectors illustrates the effects of equipment efficiency and attitudes 

about conservation in the residential and commercial markets. Additionally, shorter term issues of availability and 

price affect use in the industrial and electricity generation 

sectors. 

1

U.S. Geological Survey, MS 999, 345 Middlefield Rd., Menlo 

Park, CA 94025. 

INTRODUCTION 

Nearly two centuries have passed since methane was 

first demonstrated as a potential contributor to the U.S. energy mix. During that time, the U.S. gas industry has 

evolved from its beginning as a local supplier of coal-derived gas, which first competed with tallow candles and 

whale-oil lamps for lighting streets and homes. The industry has since grown rapidly as the development of production, distribution, and consumption technologies has greatly 

expanded gas availability, transmission capacity, and applications for natural gas. Today, natural gas is delivered to 

nearly 55 million homes and businesses throughout the Nation as a fuel to condition living and working environments, 

to serve as a chemical feedstock and provide heat for many 

industrial processes, and to drive electricity generation. 

The industry's entire history has been shaped by a 

complex interplay of market forces, technology advancement, and regulatory control. Notions of an inexpensive 

fuel with versatile applications and efficient performance 

created robust market demand in many economic sectors 

and geographic regions. Significant technological improvements and large capital investments made it possible to 

discover, produce, and transport gas supplies long distances to end users. Government oversight and regulation ensured that the entire process took place within established, 

but frequently changing, guidelines to protect the public's 

safety and interest. 

Like other natural resource extraction industries (coal, 

oil, and metals), the U.S. natural-gas industry has experienced periods of growth as well as decline. During national 

economic expansion, the gas industry prospered as the Nation's energy requirements grew. Other periods, marked by 

unforeseen business developments, regulatory influences, 

and changing attitudes towards energy consumption, have 

caused large and rapid fluctuations in gas consumption. 

Readjustment and stabilization are the principal objectives 

of today's gas industry. 

737 
738 THE FUTURE OF ENERGY GASES 

The complex history of U.S. gas consumption can possibly illuminate future opportunities and possible limitations for increased use of natural gas in the United States. 

EARLY YEARS 

In the early 1800's, methane was burned in the United 

States to provide heat for industrial processes and for illumination of homes and town streets (National Petroleum 

Council, 1992; Watson, 1992; Energy Modeling Forum, 

1989a, b). It was less expensive and brighter burning than 

the whale oil burned in lamps or the tallow candles used at 

the time. In most regions of the country where methane 

was used, particularly in the northeastern region, it was 

manufactured, as "town gas," initially from coal and wood, 

and later from oil as well. Readily available, inexpensive 

supplies of coal, wood, and oil justified their conversion, 

albeit inefficient, to gas, a more versatile fuel than others. 

Because gas could be delivered in small, continuous volumes through installed piping, it was operationally and economically favorable in some applications, especially 

highly distributed, low-consumption applications such as 

street lamps. 

During the late 1800's in the Appalachian states of 

Pennsylvania, New York, O.hio, West Virginia, and Kentucky, natural gas was collected from wells drilled into 

shallow oil and gas accumulations and transported through 

pipes to nearby consumers. Often, these scarce natural-gas 

supplies were blended with the low-methane-content manufactured gas to improve its heating value. Regardless of 

whether the methane was manufactured or naturally occurring, however, gas delivery was restricted largely to local 

use because of the technical challenges of long-distance 

transportation and (or) storage of large volumes of gaseous 

materials. 

By the early 20th century, with Edison's invention of 

the light bulb, electricity began to replace gas as the preferred energy for illumination. The gas industry responded 

by developing and promoting other gas-consuming applications and equipment for household, commercial, and industrial uses. Gas was increasingly being used in stoves 

for cooking as well as for heating of homes and water. 

The gas markets of the 19th century and early 20th 

century were initially regulated at the state and local level. 

The earliest pipeline systems were often poorly constructed; the poor construction resulted in leaky, inefficient, and 

unreliable service. Fierce competition for a rapidly expanding base of gas-consuming customers, primarily local 

industrial and residential users, resulted in excessive and 

disruptive pipeline construction. Streets were frequently 

tom up as competing suppliers installed new, and often 

redundant, distribution systems. Situations like this led to 

regulations intended to assuage concerns about safety and 

reliability. Market monopolies were given to local gas-distribution companies in exchange for regulatory controls. 

Price constraints and service standards were established to 

protect consumers from market abuses. 

The natural-gas industry grew rapidly as abundant domestic supplies of natural gas became apparent early in 

the 20th century. In the 1920's, large accumulations of gas 

were discovered as a consequence of intensive oil-exploration efforts motivated by increasing petroleum supply requirements for use in the military, by industry, and by 

America's burgeoning population of personal automobiles. 

The largest gas reserves were located in the oil-producing 

regions of Oklahoma, Texas, and Louisiana. Without technology for long-distance gas transportation and distribution, however, access to new gas-consuming markets in 

other parts of the country was greatly limited. This meant 

that large quantities of produced gas, if not reinjected into 

wells for reservoir pressure maintenance, were vented or 

flared as the gas was separated from the highly valued oil 

at production wellheads. Pilots flying over Texas at night 

could easily navigate through the darkness by the bright 

light of natural gas being flared from Texas oil fields 

below. The excess supply situation assured very low gas 

prices for those consumers who were fortunate enough to 

receive it. 

Compared to alternative fuels on a price-per-unit-ofenergy basis, gas was often the low-cost option. The allure 

of inexpensive energy and excess regional supplies resulted in advances in gas transportation and consumption 

technology. During the 1920's, technologies that had been 

developed for wartime applications became available for 

peacetime use. New technologies for gas compression and 

the development of seamless pipe made it possible to 

transport large quantities of gas long distances through 

pipelines. In 1931, the first truly long distance gas pipeline 

was completed, a 1 ,000-mile pipeline built by the Natural 

Gas Pipeline Company to transport gas from the fields in 

Texas and Oklahoma to Chicago. 

A PERIOD OF HIGH GROWTH 

FOR THE INDUSTRY 

During the 1940's, 50's, and 60's, the Nation's overall 

energy consumption expanded greatly to keep pace with the 

Nation's industrial and household growth. Total energy consumption in the United States nearly doubled from 34 to 67 

quads (1 quad= 1 quadrillion Btu's or British thermal units) 

between 1950 and 1970 (fig. 1). Economic growth occurred 

at a similar rate. The increase in energy consumption during 

that period was the primary means of improving the standard of living for many Americans. Clean, safe, and efficient 

natural-gas combustion technologies opened new markets 

throughout the country for space- and water-heating applications in residential and commercial buildings. Gas pipe-
3 

ai 

"' 0 

:::. 

(/) 

c 

c( 

:::> 

0 

HISTORY OF NATURAL-GAS CONSUMPTION IN THE UNITED STATES 

125 

115 

105 

---D-- U S. PAIIIMRY ENERGY 

CONSUMPTlON 

95 

85 

75 

65 

55 

45 

35 

25 +-----+-----r-----~---4-----+-----+-----+-----l----~-----+ 

"' "' 0> "' "' 0> 

0 

.... 

0> 

0 

<0 

0> "' <0 0> 

g 

0> "' 0> 

0> 

4.5 

1/) 

a: 

3.5 ~ 

8 

~ 

z 

Q 

2.5 :::l 

~ 

1.5 

Figure 1. U.S. primary energy consumption (open squares, left scale), 1947-1991, in 

quads, and U.S. gross domestic product (solid squares, right scale), 1959-1991, in trillion 

1987 dollars. Data from Energy Information Administration, 1992; American Petroleum 

Institute, 1992. 

30 

~ 25 [I] 

"' 0 

!:.. 20 (/) 

c 

c( 

:::> 0 15 

10 

0 

.... 

0> 

"' .... 

0> "' <0 

0> 

0 

0> 

0> "' 0> 0> 

Figure 2. U.S. primary energy consumption by energy source, in quads, 1947-1991. 

Data from Energy Information Administration, 1992. 

739 

line capacity expanded rapidly to provide gas service to 

large population and industrial centers around the country, 

particularly in the north-central region. Natural-gas deliveries 

to end users increased nearly four-fold, from approximately 

6 quads in 1950 to approximately 22 quads in 1970 (fig. 2). 

The contribution of natural gas to the Nation's total consumption of primary energy sources (oil, coal, natural gas, 

hydropower, and nuclear) grew from 18 percent in 1950 to 

almost 33 percent in 1970. The low cost, ready availability, 

and clean-burning characteristics of gas made it the fuel of 

choice for many applications. Each energy-consuming economic sector, with the exception of transportation, experienced large increases in gas consumption during this same 

period (fig. 3). (The transportation sector continues to be 
740 THE FUTURE OF ENERGY GASES 

!/) 

c 

<t 

::l 

a a 

- RESIDENTIAL SECTC:fl 

---o-- COMI.£ACIAL SECTOR 

"' .., 

"' 

-•-INOOSTRIALSECTOR 

----<>- ELEC GEN SECTOR 

0 

... 

"' 

0 

·~ "' "' "' 

g 

"' 

"' <D 

"' 

0 

,._ 

"' 

0 

"' "' 

"' "' "' 

0 

"' "' 

Figure 3. U.S. natural-gas consumption by economic sector, 1930-1990. ELEC., electrical; GEN., generation. Data from Energy Information Administration, 1992; 199lb, c; 

American Gas Association, 1991. 

nearly exclusively reliant on refined oil products: gasoline, 

diesel, and aviation fuels.) · 

THE BEGINNING OF INSTABILITY FOR 

THE GAS INDUSTRY 

A significant portion of the increased natural-gas demand during the 1940's, 50's, and 60's was stimulated by 

the ready availability of gas and its low price; people were 

anxious to use an inexpensive, clean, safe, and domestically available fuel in their homes and businesses. If this 

rapid growth in consumption had been the result of freemarket forces of supply-demand balancing and competitive pricing, the industry would have had a very bright and 

stable future. The prevailing gas prices, however, were 

controlled by government regulation. These external constraints would later have considerable impact on market 

dynamics, and their effects continue to this day. 

The initial federal regulating agency, the Federal 

Power Commission, was established by the Natural Gas 

Act of 1938. This agency, replaced in 1978 by the Fed~ral 

Energy Regulatory Commission (FERC) was given jurisdiction over interstate gas commerce. The Federal Power 

Commission felt, at the time, that public interest was best 

served by imposing government controls on the increasing 

quantities of gas that was traded across state borders. The 

rapidly growing gas industry sought government oversight 

and intervention to assure an orderly and sensible program 

of pipeline construction. Without any real competition between interstate gas suppliers, price constraints in the form 

of wellhead price controls seemed necessary to ensure stable prices for consumers. As a result, beginning in 1954, 

the commission also imposed controls over producer prices for gas destined for interstate transportation and sales. 

However, the Federal Power Commission did not have 

jurisdiction over intrastate gas commerce; therefore, wellhead prices for gas produced and consumed within the 

same state were exempt from federal regulation. Texas, 

Louisiana, and Oklahoma, which produced most of the gas 

for interstate markets, were also home to large energy-intensive manufacturing and petrochemical industries, which 

were large customers for intrastate gas supplies (National 

Petroleum Council, 1992). This local, industrial demand 

for gas grew fast enough to foster strong competition for 

intrastate supplies and caused intrastate prices to exceed 

interstate prices. This situation essentially established two 

natural-gas markets, which competed for the available gas 

supplies-an interstate market with federally regulated 

prices and an intrastate market without regulated prices. 

Gas producers, given a choice of markets for their products, opted to drill for gas and commit (contract to sell) 

the production to the higher priced intrastate market.' In 

remote producing areas, which had fewer intrastate customers and were therefore dependent upon interstate markets for their gas, the producers received lower prices for 

their supplies. Accordingly, gas exploration and production 

activities in these areas declined. The gas industry was set 

on a collision course with a supply crunch. 

Until 1967, exploration and development drilling for 

gas had been very successful in identifying new U.S. gas 

reserves. As additional wells, known as development wells, 

are drilled within gas fields to optimize the extraction of 
HISTORY OF NATURAL-GAS CONSUMPTION IN THE UNITED STATES 741 

300 ~ 30 

I 

250 + 25 

I 

tu 200 20 l:ii UJ UJ u. u. 

12 12 m m => => () 150 15 () 

z z 0 0 :::; :::; :! :! cr cr 1- 100 10 1-

-•- PRO\IEDRESERVES 

Figure 4. U.S. proved natural-gas reserves, production, and reserve replacements, 1947-1991. Reserve data include 

the addition of 26 trillion cubic feet in 

1970, accounting for the natural gas in the 

Alaskan Prudhoe Bay field, which was discovered in 1968. In 1988, 24.6 trillion cubic 

feet of Alaskan natural gas reserves were 

removed owing to economic and market 

conditions. Natural-gas production data is 

total U.S. dry gas production, including 

Alaskan production, reflecting gross gas 

withdrawals less gas used for repressuring, 

removal of non-hydrocarbon gases, gas that 

is vented and flared, and the extraction Joss, 

which is a volume reduction resulting from 

the removal of natural gas plant liquids. 

Revisions, extensions, and discoveries are 

averaged using a three-year moving average. Data from American Gas Association, 

1992; Energy Information Administration, 

50 -a--- PROOU::TlON 

--;-0---- REVISIONS, EXTENSIONS, 

09XNERIES 

~ e. 6 

:::l 

UJ 

~ 

!z 5 UJ 

:Iii 

a.. 

g 

~ 4 

c 

cr 

UJ 

a.. 

~ 

g 

8 2 < 

UJ 

~ UJ 

131 

cr 

"' ~ ;:. 0> ~ 

"' 0 "' R "' 0 

"' "' "' ,._ ., 0> 0> 0> "' 0> 0> ~ 

-,------,-----,-----,-----

gas, the producers learn increasingly more about the actual, 

ultimate size and shape of the gas accumulation. With this 

information, they are able to update and revise their estimates of the gas remaining to be extracted. This process 

results in annual revisions to the gas-reserve estimates for 

previously discovered fields. In addition, field growth results when producers drill wells, known as extension wells, . 

around or below currently producing area ol' fields. Often 

these wells result in new production from deeper and shallower zones or surrounding accumulations that previously 

had not produced. This process results in annual field extensions and the development of new producing intervals 

in existing fields. A third category of wells, known as new 

"' ., 

0> 

g "' 0> 0> 

~ 

.,. 

0> 

0> 

1992; American Petroleum Institute, 1992. 

Figure 5. Natural-gas reserve replacements 

per development well drilled, 1947-1990. 

Data from American Petroleum Institute, 

1992; Energy Information Administration, 

1992. Bcf, Billion cubic feet. 

field wildcats, are drilled in locations distant from existing 

fields in hopes of discovering new fields. The newly discovered fields represent new-field ~dditions to U.S. gas reserves. Accordingly, total annual U.S. gas-reserve additions 

include the revisions to field-reserve estimates, reserves 

identified by field extension and in-field exploratory activity, and new field discoveries. Despite steadily increasing 

gas consumption, annual gas-reserve additions continued 

to exceed the total national annual gas production rates 

until 1967 (fig. 4). This phenomenon resulted in growing 

estimates of the Nation's total proved gas reserves, During 

this period, total reserve additions averaged 5 Bcf (billion 

cubic feet) per development well completed (fig. 5). 
742 THE FUTURE OF ENERGY GASES 

45000 

40000 

c 35000 

.... 

~ 0. 30000 

::E 

8 

Ul 25000 .... 

.... 

~ 

!r: 20000 

LIJ 

::E 

0. 

g 15000 -- LIJ 

~ 10000 

5000 

--------

f 

/ 

~J-

., 

., 

0> 

0 

"' 0> 

., 

"' 0> 

0 

,.._ 

0> 

., 

,.._ 

0> 

., 

<0 

0> 

g 

"' 

., 

0> 

"' 

Figure 6. Oil and gas development wells completed, 1947-1991. Data from Energy 

Information Administration, 1992. 

Gas consumers were very encouraged by continued low 

gas prices and optimistic reports of rapidly growing reserve 

estimates. It appeared as though vast and easily found gas 

supplies would ensure long-term, inexpensive natural-gas 

supplies well into the future. This optimistic outlook encouraged increased investment in gas-burning equipment 

for industrial purposes and continued pipeline extension to 

growing cities for use in new residential and commercial 

developments, primarily for space and water heating. 

Low, regulated wellhead prices for gas destined for interstate commerce, however, discouraged some producers 

who had limited intrastate gas markets from undertaking 

gas-field exploration and development activities, particularly field infill and extension drilling. As a result, the Nation's development drilling activity decreased significantly 

from 5,000 gas development well completions in 1962, the 

highest level since before 1950, to approximately 3,000 

completions in 1968 (fig. 6). In addition, new gas-field exploration drilling declined from more than 300 successful 

wildcat wells in 1962 to less than 130 in 1968 (fig. 7). 

Over an extended period beginning in 1968, annual reserve 

replacements fell far short of national production (fig. 4). 

Consequently, gas reserves peaked in 1967 at more than 

290 Tcf (trillion cubic feet), a 17 year supply at 1967 consumption rates. The highly successful and prolific exploration and development trends in the Gulf of Mexico began 

to only grudgingly yield new discoveries and field extensions. As a result, after 1967, annual gas production exceeded reserve additions and the Nation's proved reserves 

began to decline rapidly (fig. 4). 

Despite declining gas-reserve estimates, gas production and consumption actually increased by nearly 30 percent between 1967 and 1973. Each energy-consuming 

sector continued to increase gas consumption through 1972 

(fig. 3). Another 5 million homes with gas-burning appliances were connected to gas-distribution systems (fig. 8). 

Nearly 500,000 additional commercial establishments were 

built or converted to gas service. Electric power generators 

consumed greater amounts of gas to fuel their boilers. 

In 1973, gas production peaked at 22 Tcf, but it began to 

decline rapidly thereafter. Producing wells were unable to 

deliver enough gas to meet demand. Too few new wells, 

exploratory or development, were being drilled to replace 

the decline in gas production. The Nation's gas supply was 

seemingly being rapidly depleted. As wellhead production 

declined, the amount of gas available to pipelines was reduced, and pipelines were unable to meet the gas demands of 

all their customers. Supply shortages were felt primarily by 

industrial and power generation consumers whose gas supplies were curtailed. An eight-step curtailment plan was 

established to prioritize gas customers and determine gas 

deliveries during periods of shortage. Gas production continued falling through the mid-1970's and delivery shortages, at 

their worst, in 1977, caused nearly 4 Tcf of curtailments. 

Loss of gas service forced closings of businesses, industry, 

and government buildings throughout the country. 

CONTINUED ATTEMPTS AT 

REGULATION 

The gas-supply disruptions of the early 1970's led government regulators to reevaluate wellhead price controls 
HISTORY OF NATURAL-GAS CONSUMPTION IN THE UNITED STATES 743 

900 

800 

700 

"' .... 

.... 600 Ul 

~ 

1-

c( 

8 500 

.... 

i 

c 400 .... 

Ul 

u: 

1S 300 

z 

200 

100 

"' 0 "' 0 "' 0 ~ 0 "' 0 "' ~ "' "' "' <0 ,_ "' "' "' "' "' "' ~ "' ~ "' "' "' "' "' 

Figure 7. Successful oil and gas new field wildcat wells, 1947-1991. Data from American Petroleum Institute, 1992. 

60 

55 

.., 

<: 

~ 50 

~ 

"' a. 45 ::> 

~ 

0 

0 

:t: 40 

(§ "' 

.... 

~ 35 1-

z 

Ul 

c 

iii 

t 

w 30 a: 

25 

I 

5.5 

.., 

<: 

~ 

~-

"' 4.5 ~ 

~ 

8 

:t: 

"' (3 

.... 3 5 ~ 

2 5 

a: 

Ul 

:Iii 

:Iii 

0 

u 

20 I ----- 1------- 1------l--- ----1-----+ 

"' 0 <0 ,_ 

"' "' 

"' ,_ 

"' 

0 

"' "' 

0 

"' "' 

Figure 8. Total U.S. residential and commercial gas service hookups, 1967-1991. Data 

from American Gas Association, 1992. 

and the impact that strict industry regulations were having 

on market dynamics. It was easy to draw the conclusion 

that gas supplies were falling because too few development 

wells were being drilled to replace the declining production from existing wells. Furthermore, producers were not 

drilling development wells because the wellhead price controls made it uneconomic for them to do so. 

Wellhead price controls were relaxed considerably in 

the mid-1970's as an incentive to explore for, develop, and 

produce more natural gas. Producers responded with dramatic increases in development drilling; by 1977, development drilling for gas had increased to more than 10,000 gas 

well completions per year from a low of 3,000 in 1968 

(fig. 6). As expected, increased gas exploration and development drilling was successful in identifying new gas reserves during this period. The total annual reserve additions, 

however, continued to be less than annual gas production 

rates, and, consequently, estimates of the Nation's total 
744 THE FUTURE OF ENERGY GASES 

proved gas reserves continued to decline throughout the 

1970's (fig. 4). 

Other trends raised concerns about the reliability of 

long-term gas supplies. While large annual increases in development drilling activity added, as expected, greater 

amounts of new reserves annually, the rate at which new 

reserves were being found had fallen dramatically. During 

the 1970's, new reserves were being added at an average 

rate of only I Bcf per development well; this was one-fifth 

the average additions for development wells drilled prior 

to 1968 (fig. 5). Large numbers of gas development wells 

were being drilled, but each was finding smaller amounts. 

Because less gas was being found, it appeared as 

though the Nation's gas-resource base was dwindling, that 

supplies may indeed be resource limited, that increased 

development drilling may not reverse the decline in reserves, that supplies would continue not to meet demand, 

and that curtailments of gas service would continue. Gas 

consumers, particularly industrial and electric generation 

customers, rapidly began to lose confidence in both nearand long-term gas supplies. Fuel-supply planning for these 

consumers and new industrial developments initiated alternative energy strategies (sourced by coal, oil, and electricity) that would hopef~lly be more reliable. 

THE NATURAL GAS POLICY ACT 

OF 1978 

Congress responded to supply shortages with the Natural Gas Policy Act (NGPA) of 1978, which created the Federal Energy Regulatory Commission (FERC) as well as 

some energy policies. Realizing that sufficient future natural-gas supplies were critically dependent on producer development drilling and new field exploration activities, 

which were in turn dependent on market-value incentives, 

the NGPA began the process of removing wellhead price 

regulations. Wellhead prices for various types of gas were 

scheduled for deregulation over the next several years. Price 

distinctions were made between gas produced from current· 

ly producing wells and newly drilled wells, as well as for 

gas produced from different depths. The NGPA also extended federal pricing regulations to the intrastate markets. This 

eliminated the two-market situation for gas producers. 

Long-term gas purchase contracts between pipelines 

and producers were negotiated to reflect the federally defined gas-price schedules. With the incentive of significantly higher gas prices for producers, exploration and 

development drilling for gas responded quickly; exploration success increased from 550 wells in 1977 to more 

than 700 wells in 1981, and development drilling increased from 13,000 completions in 1978, to 17,000 in 

1981 (figs. 6, 7). 

From 1978 to 1980, despite the large increase in drilling 

activity, development drilling continued to be less productive than in previous decades; reserve additions continued at 

an average of only 1 Bcf per well. However, further increases in the number of development wells drilled in 1980 resulted in sufficient new reserves being added to replace the 

amount of gas produced. As a result, proved reserves estimates in 1980 stopped a 13-year decline. It appeared as 

though a fragile stabilization in the gas industry might have 

been established. 

In addition to deregulation of wellhead prices, tax incentives were established in 1980 that encouraged exploration 

and development of unconventional natural-gas resources. A 

provision of the Federal tax code, known as "section 29," 

provided for substantial tax credits for natural-gas production from shales, coal beds, and "tight" (low permeability) 

formations. It was felt that this tax incentive would stimulate 

production of the Nation's unconventional natural-gas resources; lead to the development and improvement of technologies used in the production of gas from unconventional 

accumulations, and expand the Nation's natural-gas reserves 

by encouraging development of unconventional resources. 

The section 29 tax credit remained in effect until December 

31, 1992; qualifying wells that were completed prior to that 

date will continue to receive the credit for natural gas produced until 2002. During the 12-year period that the tax 

credit for unconventional natural-gas production was available, it is estimated that approximately 45 percent of all 

natural-gas completions were drilled with the benefit of the 

section 29 tax credit (oral commun., 1993, P. Stark, Petroleum Information Corporation). 

WHAT GOES UP MIGHT COME DOWN 

The mid-1970's through the early 1980's was also a 

period of dramatically higher global energy prices, primarily as the result of several sudden increases in crude-oil 

prices (fig. 9). These price increases were the effect of foreign government pricing policies for crude oil that they 

exported. Because a few governments had control of vast 

oil supplies, which were shipped to all comers of the 

globe, they were able to manipulate the international oil 

market by controlling production and setting prices to 

their satisfaction. Despite these largely capricious price 

manipulations by artificial, external, and nonfree market 

forces, the industry's prevailing perspective was that an 

enduring pattern of escalating energy prices had been established. With that view, oil prices were projected by 

most experts to continue rising (see Howell and others, 

this volume). The high oil prices and projections of ever 

higher prices spurred dramatic increases in domestic oil 

exploration and development activity (figs. 6, 7). 

Within a context of rising oil prices, it seemed reasonable to regulators, producers, and gas purchasers that natural-gas prices could, or should, rise as well. The NGPA of 

1978 adopted just that philosophy in their wellhead price 
HISTORY OF NATURAL-GAS CONSUMPTION IN THE UNITED STATES 745 

:a 

.. 

z 

Q 

7 00 

6.00 ... 1~1-.. r T 

·1 ~-= :~TURALGAs .. · ·.. j· . ~ 5 00 

:E 

a: 

w 

.. -•- BITUMINOUSCOAL 

.. .. --<>---·- ANTHRACITIC COAL . .. .. .. . . ... (/) 

a: 4 00 

~ 

(/) 

~ 

~ 3 00 

a: 

.. 

... 

w 

:::> 

~ 2 00 

iii 

~ 

1 00 

0 00 

+ } 

l 

"' "' "' 

~-------,-~ 

0 "' 0 "' :;; ~ <0 "' " " ~ 

"' "' "' ~ "' "' 

Figure 9. Oil, gas, and coal prices in constant 1987 dollars per million British thermal 

units (Btu), 1959-1991. Data from Energy Information Administration, 1992. 

decontrol schedules for natural gas. Gas prices were allowed to rise to provide increased incentive for domestic 

gas exploration and production activities. 

Pipeline companies had just been through an extended 

period of supply shortages during the mid-1970's which 

forced curtailments of gas service to many of their customers. To avoid a repeat of those circumstances, most 

pipelines sought to ensure firm, long-term gas supplies 

from producers. The gas market, therefore, became more 

of a sellers market; gas producers gained more favorable 

terms for their gas. To ensure reliable supplies, gas purchase contracts between producers and pipelines were 

often negotiated as long-term contracts with future prices 

adjusting according to the regulated schedule of maximum 

allowable wellhead prices. Often, these contracts also obligated purchasers (pipeline companies) to pay for contracted amounts of gas, whether or not the purchasers actually 

had a market for the gas. This was commonly known as 

the "take-or-pay" contract clause, and it ensured producers 

of steady income, which they could use to continue their 

development activities. Pipeline companies were willing to 

agree to those terms because they also seemed satisfied 

that rising global crude oil prices would create a U.S. energy market that would favor gas use, even at significantly 

increased prices. Furthermore, because they had just gone 

through a period of too little supply and too many customers, they were very confident of having enough customers 

for the amounts and prices of gas their contracts committed them to buy from producers. 

However, the interstate gas market, which experienced 

severe supply shortages of the late 1970's, quickly and unexpectedly became an oversupplied market in the early 

1980's. Gas demand declined very rapidly in the early 

1980's (fig. 3) for several reasons-attitudes toward energy consumption became more conservative, economic recession in 1981 reduced industrial activity and overall 

energy demand, oil prices declined very rapidly after the 

early 1980's and diminished the gas-price advantage over 

oil, and so dual-fuel customers increasingly used oil instead of gas. 

The curtailments of gas service during the 1970's had 

been so disruptive to many gas customers, especially industrial and electricity generation consumers, that they 

held lingering concerns about long-term reliability of gas 

supplies. Because of rising gas prices, they also saw a diminishing cost-of-energy advantage of gas over alternative 

fuels. Many gas consumers with dual-fuel (oil, coal, and 

(or) gas) burning capability turned to oil and coal to meet 

their energy needs. Gas consumption in the industrial sector fell by more than 33 percent from approximately 9 

quads in 1973 to less than 6 quads in 1983. During the 

same period, gas consumption in the electricity generation 

sector fell by 25 percent from approximately 4 quads to 

nearly 3 quads (fig. 3). 

The higher energy costs also increased public interest in 

energy efficiency and conservation measures. Tax incentives 

to reduce energy consumption were also a factor in energy 

conservation. Among residential and commercial customers, 

the trend toward increasingly energy efficient equipment and 

conservation programs, which were begun in the early 

1970's, continued and caused significant reductions in gas 

consumption by the average individual customer (American 

Gas Association, 1992). Significant improvements in furnace design and construction, for example, have resulted in 
746 THE FUTURE OF ENERGY GASES 

the delivery of much more heat with less fuel. Replacement 

of old, inefficient furnaces as they come to the end of their 

useful lives with new equipment has further reduced the 

demand for energy for space-heating needs. Greater thermal 

insulation in new construction and insulation added to existing construction has also reduced the per-building consumption of energy to heat and cool. While the per-customer 

consumption of gas continued to decline significantly, overall gas consumption by both residential and commercial 

sectors remained stable only because of large numbers of 

new customers. 

The customer groups that account for marginal gas demand are high-volume industrial and electrical generation 

consumers. While the average residential customer consumes approximately 90 MMBtu (million British thermal 

units) per year and the average commercial customer consumes approximately 500 MMBtu per year, the average 

industrial and electricity generation customer consume approximately 10,000 and 1,800,000 MMBtu per year, respectively (American Gas Association, 1992). Whereas there are 

only few marginal consumers compared to the residential 

and commercial market, each one consumes such large 

amounts of energy that the fuel choices they make influence 

the overall demand for specific fuels; fuel switching by 

industrial and (or) electricity generation customers can cause 

significant fluctuations in the supply and demand of individual fuels (Electric Power Research Institute, 1992). Many of 

these consumers use gas in applications for which they have 

alternative fuel-burning capability, such as steam boilers. 

Many can switch on very short notice to the most readily 

available and reliable fuel supply, or the least expensive fuel 

at the time. For industrial consumers, fuel choices often are 

made on the basis of the differences between delivered prices of various grades and types of refined oil products, coal, 

and natural gas. Small adjustments in the price differences 

between fuels will often influence fuel choice, which can 

have a large impact on overall fuel demand. 

In comparison, residential and commercial consumers 

are much more firm gas customers. These customers generally have limited, if any, ability to switch energy supplies to meet their needs. Most of their fuel use is for 

space heating and cooling, and the equipment installed for 

these purposes is usually single-fuel burning equipment. 

At the time of initial building design and construction, a 

fuel-choice decision is made and equipment is installed to 

bum that particular fuel. In most residences, space-heat requirements are met by furnaces burning distillate oil or 

natural gas, or by electrical heating systems. 

By 1986, the Nation's overall natural-gas consumption 

had fallen by more than 25 percent from its 1972 peak of 

23 Tcf to less than 17 Tcf (fig. 2), primarily as a result of 

sharply reduced demand in the industrial and electricity 

generation sectors. Many industrial consumers and electricity generators used alternative fuels more frequently. 

Refined oil products became increasingly price competitive with natural gas as the price of crude oil fell dramatically during the mid-1980's (fig. 9). Many pipelines, 

however, which had firm, long-term contracts with producers for gas supplies, accrued large financial liabilities 

under the take or pay commitments they had made during 

times of much higher projections of gas consumption and 

higher energy prices. The excess deliverability capacity 

became known as the "gas bubble." 

THE FUTURE OF THE 

NATURAL-GAS INDUSTRY 

Since 1983, the gas industry has been undergoing a 

complex and prolonged process of regulatory revision (National Petroleum Council, 1992). The goal is to transform 

the industry from one that is heavily dependent on regulation to a more market-driven business (see Nesbitt, this 

volume). During this process, the traditional functions of 

natural-gas producers, transporters, distributors, consumers, and regulators have changed. Wellhead gas prices, as 

of January 1, 1993, have been entirely deregulated. Pipelines are moving away from their role as gas merchants 

and are now largely providing gas-transmission and underground storage services for gas producers, distribution 

companies, and industrial consumers. Many large-volume 

gas consumers, particularly the industrial and electricity 

generation customers, who previously had bought gas supplies from pipelines, are now contracting for gas supplies 

directly with producers, and are buying customized transportation services from pipelines. Natural-gas prices have 

declined significantly from their highs in 1983 and 1984, 

and demand for gas has increased strongly since 1986. 

As gas exploration and development activities proceed 

without price regulations, the market should more closely 

approach a natural equilibrium between supply and demand. Gas markets will respond more easily and quickly 

to changes in energy demand. Consumers will enjoy greater control over their fuel-supply planning. 

Concerns, however, linger over the long-term U.S. gas 

supply outlook (Butler and Stark, 1993; Crow and Koen, 

1993; Koen, 1992; Riva, 1993). In particular, there is reason to believe that the recent low levels of exploration and 

development activities will soon lead to shortages of natural-gas supply. Many large-volume consumers, particularly 

the electricity generation sector, are unconvinced of the 

gas industry's ability to maintain, much less increase, 

natural-gas delivery at prices that are competitive with alternative fuels. These consumers are often faced with fuelchoice decisions during planning, design, and construction 

of long-term, capital-intensive projects involving fuelburning equipment. Availability, reliability, price, performance, and environmental impact are just a few of the parameters of fuel choice. These consumers also have unique 
HISTORY OF NATURAL-GAS CONSUMPTION IN THE UNITED STATES 747 

requirements for gas service that may be difficult for pipelines to meet. 

Using natural gas to provide more of the Nation's energy mitigates several environmental and economic issues, 

which relate to energy consumption. Its use will augment 

a recovery from the prolonged period of depressed activity 

in the domestic industries that explore for, develop, and 

transport natural-energy resources to end-users. Its use will 

also help to mitigate the environmental impacts of fossilfuel combustion by reducing the emissions of greenhouse 

gases and atmospheric pollutants, which result primarily 

from coal and oil combustion. Furthermore, its use presents an opportunity to reduce a fragile dependence on 

foreign sources of energy, particularly oil, and the unfortunate consequences of that dependence. The reduction of 

dependence on foreign oil may very likely result in reduced military expenditures, fewer deadly conflicts, more 

political and price stability, and less threat of tanker spills 

that spoil coastlines and marine environments. 

If historical experiences and trends can be used to develop a perspective of future possibilities, the U.S. naturalgas industry is likely to continue a process of regulatory 

and technological evolution. When the unavoidably high 

levels of uncertainty that pervade the technically challenging and economically sensitive process of natural resource 

exploration and exploitation are combined with a dynamic 

market for natural gas and other forms of energy, the industry's future is indeed difficult to predict with any reasonable 

degree of certainty (see Howell and others, this volume). 

REFERENCES CITED 

American Gas Association, 1992, Gas facts-1991 data, 204 p. 

[Available from the American Gas Association, 1515 Wilson 

Boulevard, Arlington, VA 22009]. 

American Gas Association, 1991, Gas consumption in the United 

States-1990 data and forecasts, v. 18, 69 p. [Available from 

the American Gas Association, 1515 Wilson Boulevard, Arlington, VA 22009]. 

American Petroleum Institute, 1992, Basic petroleum data bookPetroleum industry statistics, v. 12, no. 2. 

Butler, J.R., and Stark, P.H., 1993, U.S. gas outlook-Wjlere will 

we get it?: World Oil, February 1993, p. 39. 

Crow, P., and Koen, A.D., 1993, Supply/demand conc~ms top 

U.S. gas industry agenda in '93: Oil and Gas Journal, April 

26, 1993, p. 21. . . 

Electric Power Research Institute, 1992, Natural gas for electric 

generation-The challenge of gas and electric industry coordination [Available from the EPRI Distribution C~ilter, 207 

Coggins Drive, P.O. Box 23205, Pleasant Hill, CA 94523]. 

Energy Information Administration, 199la, Natural gas productive capacity for the lower 48 states, 1980 through 1991, 

DOE/EIA-0542, 77 p. [Available from the National Energy 

Information Center, EI-231, Energy Infoimation Administration, Room lF-048, Forrestal Building, Washington, D.C.]. 

--199lb, Natural gas annual 1990, DOE/EIA-0131/1, v. 1, 

253 p. [Available from the National Energy Information 

Center, EI-231, Energy Information Administration, Room 

1F-048, Forrestal Building, Washington, D.C.]. 

--199lc, Natural gas annual 1990, DOE/EIA-0131/2, v. 2, 

263 p. [Available from the National Energy Information 

Center, EI-231, Energy Information Administration, Room 

lF-048, Forrestal Building, Washington, D.C.]. 

---1992, Annual energy review 1991, DOE/EIA-0384, 347 

p. [Available from the National Energy Information Center, 

EI-231, Energy Information Administration, Room 1 F-048, 

Forrestal Building, Washington, D.C.]. 

Energy Modeling Forum, 1989a, North American Natural Gas 

Markets, EMF Report 9, v. 2, 142 p. 

---1989b, North American Natural Gas Markets: Selected 

Technical Studies, EMF Report 9, v. 3, 471 p. 

Koen, A.D., 1992, Warning flags hoisted over Gulf of Mexico 

longevity: Oil and Gas Journal, December 21, 1992, p. 19. 

National Petroleum Council, 1992, The potential for natural gas 

in the United States, 6 volumes [Available from the National 

Petroleum Council, 1625 K Street, N.W., Washington, D.C.]. 

Riva, J.P., 1993, Domestic natural gas-Part of the solution or 

part of the problem?: Congressional Research Service, 93-

150 SPR, 18 p. 

Watson, W.D., 19?2, The gas seller's companion-A practical 

guide to gas contracts: Tulsa, Okla., PennWell Publishing 

Company, 197 p. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

An Economic Approach that Links Volumetric Estimates of 

Resources with Cost and Price Information 

By Dale M. Nesbitt1 

CONTENTS 

Introduction ................................................................... 749 

How Should Future Price Trends be Forecast? ........... 751 

Forecasting Based on Market Observations .......... 752 

Surveys of Market Experts .................................... 753 

Expert Judgment Tends to be Biased ............. 753 

Is an Expert's Track Record Meaningful? ...... 755 

Structural Models ................................................... 755 

A Prudent, Workable Strategy for Market 

Forecasting ............................................................. 756 

A Model to Accurately Simulate the Behavior 

of an Informationally Efficient Market ........................ 757 

What Geographic and Temporal Scope can 

be Achieved? ................................................................ 760 

Demand-Side Structure .......................................... 762 

Supply-Side Structure ............................................ 762 

United States ................................................... 762 

Canada ............................................................. 763 

Mexico ............................................................. 764 

Liquefied National Gas (LNG) Import 

Terminals ......................................................... 764 

World Outside North America ........................ 765 

Developing Regional Supply Curves from 

Fundamental Geologic and Cost Information .............. 765 

Step !-Regional Estimates of Proved 

Reserves and Initial Year Production Levels ........ 765 

Step 2-Regional Estimates of Undiscovered 

Resources ............................................................... 765 

1

Decision Focus, Inc., 650 Castro Street, Suite 300, Mountain View, 

CA 94041-2055. 

Developing Regional Supply Curves from 

Fundamental Geologic and Cost Information-Continued 

Step 3-Disaggregate Regional Volumetric 

Estimates into Plays ................................................ 766 

Step 4-Estimate Reservoir Size and Depth 

Distribution ............................................................. 766 

Step 5-Assemble Historical Schedules of 

Discoveries, Reserve Additions, and Production ... 769 

Step 6-Statistical Analysis of Historical 

Schedules ................................................................ 770 

Step ?-Probabilistic Simulation of Future 

Exploration and Production .................................... 771 

Step &-Deterministic Simulation of Future 

Exploration and Development ................................ 774 

Producer Behavior Given Regional Supply 

Curves ..................................................................... 775 

Modeling Demand ......................................................... 775 

Building Regional Gas-Demand Curves 

from Fundamental Information .............................. 775 

What Does Demand Imply about the Crossing 

Point? ...................................................................... 778 

A More Segmented Representation of Gas 

Demand ................................................................... 780 

Modeling Transportation ............................................... 782 

Conclusion ..................................................................... 785 

Selected References ....................................................... 785 

INTRODUCTION 

How can gas prices be reliably forecast? How can 

prudent decisions be made that do not risk shareholder equity or compromise the ability to service corporate debt? I 

749 
750 THE FUTURE OF ENERGY GASES 

present herein a blueprint for anticipating future gas prices 

by coupling observations of market instruments with structural modeling of markets. The structural modeling approach specifically marries volumetric estimates of gas in 

the ground typically made by such organizations as the 

U.S. Geological Survey with cost and price estimates. To 

support such structural modeling requires the development 

of supply curves, which are systematic relations l;>etwee!} 

volumes and prices, to characterize the resource 'endowment; development of demand curves that systematically 

relate price and consumption; and development of pipelin~ 

and other transportation costs. This paper categorically re":; 

jects using expert opinions or surveys of future; market 

prices and demonstrates that they are fundamentally erro~ 

neous. The paper demonstrates how to couple volumetric 

estimates with market information and thereby calculate 

the economic implications of resource assessments by the 

U.S. Geological Survey and other organizations. 

When I entered the energy economics profession in 

1974, then-current estimates of the remaining United 

States natural-gas resource base were approximately 800 

trillion cubic feet (Tcf). During the early 1970's, reserve 

additions were not keeping pace . with consumption; the 

United States was "falling behind." Consumption, buoyed 

by artificially low, regulated wellhead prices, was fast outstripping reserve additions. The United States was running 

out of gas. Crude-oil and natural-gas price controls, windfall profits taxes, and franchised downstream monopolies 

with stringent rate-of-return regulation and complete control and domination of downstream markets were supposedly needed to keep producers from taking advantage of 

consumers. 

Assuming average annual consumption of approximately 20 Tcf since 1974, the United States should have 

by now consumed approximately 380 Tcf of the 800 Tcf 

natural-gas resource base foreseen in 1974, which leaves 

only 420 Tcf. In 1993, it should be a scant 21 years before 

the United States runs out of natural gas. Prices should 

already be skyrocketing in anticipation of "running out." 

The dramatically escalating price predictions of the turbulent days of the energy crisis should now be coming to 

pass. We should be in trouble. Quite the contrary is true, 

however. The price of gas is low in real, inflation-adjusted 

terms, and there is little prospect for sustained increase. 

Why were the 1974 forecasts so wrong? Were there 

signals in place in 1974 that could have told the proper 

story? The answer is a definitive yes! Without question, 

there were definitive signals in place. Without question, 

the primary reason the energy forecasts were wrong was 

that virtually all discussion and debate centered on how 

much gas might be left in the ground. No attention was 

given to several critical questions: (1) How much will it 

cost to produce and transport that gas to market? (2) What 

will be the fair market value, that is, the price, of gas in 

every market it serves? (3) How much more gas might be 

found if prices were to rise? (4) What fuel form will gas 

be competing with in each prospective market it might 

serve? (5) Will producers make any money producing gas? 

(6) To what degree can gas-production costs be reduced by 

fundamental technological change? and (7) Will natural 

gas become an "import economy," just like crude oil and 

its byproducts have become? 

Since 1974, virtually the entire debate has centered on 

the question what is down in the ground without attention 

given to what will happen when the gas is produced and 

~elivered to market. Indeed, most of the other papers in 

$is voljlme focus almost entirely on what is down in the 

ground.: The U.S. Geological Survey, the Potential Gas 

<:;:ommittee (PGC), the Bureau of Economic Geology, the 

Canadian Geological Survey, and many other groups have 

presented pure volumetric estimates based on criteria such 

as current or reasonably anticipated prices and technologies, quantities entrapped in sediments, or gas resource 

potential. The purely volumetric approach has generated 

estimates that differ by orders of magnitude. Yet, throughout the entire debate and the entire range of volumetric 

estimates, price forecasts have not varied perceptibly. 

It is amazing how price forecasts remain constant, unfazed by profound changes in volumetric estimates or accompanying production cost estimates. Even today, the 

Energy Information Administration (EIA) National Energy 

Strategy's high estimate and the U.S. Geological Survey's 

low estimate of gas reserves lead to the same price forecast! Neither estimate is tied to prices or markets. It is 

astonishing that price forecasts have not varied perceptibly 

in spite of the severalfold increase in recoverable gas volumes foreseen during the past 20 years. Prognosticators 

persist in putting forth the same hackneyed forecasts they 

always have-forecasts in which prices remain level for a 

brief period of time and then escalate dramatically. 

In contrast to most of the modeling and analytical 

work of the day, sev-eral colleagues and I designed the 

SRI-Gulf model in 1973 precisely to answer the critical 

economic questions posed previously for natural gas and 

other fuels. See Cazalet ( 1977) for a description of the 

SRI-Gulf model. (The acronym SRI stands for Stanford 

Research Institute, which has since been renamed SRI International.) The SRI-Gulf model and its successors (the 

LEAP and NARG models) did not decouple volumetric 

estimates from price estimates. The long-range energy 

analysis program (LEAP) capability was initiated by the 

Energy Information Administration in 1977-8. The North 

American regional gas (NARG) model was developed by 

the Gas Research Institute (GRI) in 1984. Both models explicitly attached resource volumetric estimates with costs 

and avoided pure volumetric approaches. The underlying 

approach (called "generalized equilibrium modeling") systematically coupled and interrelated prices and volumes by 

postulating and advocating the use of long run marginal 

cost curves (defined and described later in the "Supply" 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 751 

section). One of the purposes of this paper is to show how 

a fundamental coupling between price and quantity can be 

accomplished and to argue that such coupling is absolutely 

essential to a proper understanding of natural gas and 

other fuels in the United States, North America, and the 

rest of the world. 

The success of the generalized equilibrium approach is 

rather lucid. The first application of the generalized equilibrium approach indicated quite clearly that oil and gas 

prices would not escalate at anywhere near the rate or to 

anywhere near the height most pundits of the day were 

predicting and that oil and gas prices would decouple from 

one another. Even at that time, it was clear there were 

plenty of oil and gas resources in the ground to serve the 

demand for the next 20 years. Prices could not possibly 

escalate very high or very rapidly. To complement domestic resources, there were plenty of foreign resources available, which could be imported by the United States. In 

1975, the team from SRI recommended that the government should not participate in the research and development of or subsidize synthetic fuels (Interagency Task 

Force on Synthetic Fuels Commercialization, 1975). The 

basis for our recommendation was that there would be 

plenty of conventional oil and gas available at production 

costs lower than synfuels and that availability of low cost 

oil and gas would retard price increases and keep prices 

well below the cost of synfuels. For the study, costs and 

prices were systematically attached to the volumetric estimates of the day. We concluded that at higher prices, large 

quantities of additional oil and gas could and would be 

produced. SRI also specifically predicted that markets 

would be efficient and prices would clear markets. Prices 

would never rise to levels needed to render synthetic fuels 

commercially viable. Were such conclusions in 1975 visionary? Hardly. The conclusions were derived from a 

straightforward, fundamental analysis of the resource base, 

an analysis that systematically coupled volumetric with 

cost information-an analysis that can be easily duplicated 

today. 

As one might imagine given the conventional wisdom 

of the day following the first oil embargo, the team from 

SRI was criticized by some program advocates within the 

Government for our conclusions that the economic fundamentals pointed toward little, if any, price increases for 

the foreseeable future. SRI's reports to the Council on Environmental Quality (CEQ) and the Interagency Task 

Force on Synthetic Fuels Commercialization dated 1975 

contain our price forecasts from 1975. How, people asked, 

could such heretical, irresponsible conclusions be drawn 

that were so far at odds with conventional wisdom? 

Wasn't the United States entrapped in the clutches of insecure, avaricious, unethical Middle Eastern producers out to 

ruin the West? Wasn't there an urgent need for massive 

Government intervention to prevent frequent recurrence of 

gasoline lines and oil embargoes? Wasn't the cost of subsidized synfuels a meager price to pay to escape the voracious clutches of "foreign oil producers?" The answer then 

as now was that the economic and geologic fundamentals 

point in quite the opposite direction. 

The main purpose of this paper is to focus on the critical 

question of how to attach economic significance to volumetric estimates. Volumetric estimates such as the amount of 

hydrate-entrapped gas worldwide or how much gas remains 

to be discovered and produced in the Gulf Coast Basin are 

meaningful only when they are coupled with viable price 

forecasts and pertinent market information. There are several critical market-related questions to be addressed. How 

much will it cost to produce and transport the gas to market? 

What fuel(s) will the gas be competing with in any prospective market? To what degree can technological advances 

reduce the cost of producing gas? 

Considering only volumetric estimates in contexts 

other than oil and gas is unheard of. What is so different 

about energy that allows us to make only volumetric estimates devoid of cost and price? For example, the fair market value of silicon depends on the cost of converting it to 

a useful commodity, not on the volume of silicon available 

at various locations. Volumetric estimates are what the old 

Chinese metaphor calls "the sound of one hand clapping." 

They tell only half the story. Supply curves showing explicit relations between volume and cost tell the whole 

story. 

HOW SHOULD FUTURE PRICE TRENDS 

BE FORECAST? 

There has been a great deal of attention dedicated to 

forecasting future price trends in the context of the stock 

market and a number of commodity markets. Can stock 

and commodity market concepts be extrapolated to natural 

gas, oil, and other energy commodities? The answer is yes. 

In stock and commodity markets, it is generally accepted 

today that "the market is efficient." This seemingly innocuous statement means that everything that is known or 

knowable is systematically embedded in the price. There is 

nothing that is known or knowable that is not already considered by and embedded in the price. All transactions in 

all markets that affect or are affected by the stock market 

are fully incorporated into the market price. All information-public as well as confidential-is embedded in the 

price because all transactions collectively combine to determine the price. In an efficient market, it is totally without justification to make subjective judgments about price 

or about the market. It is impossible for any individual to 

systematically outsmart the market. In efficient markets, 

subjective estimates of prices are meaningless. The subjective estimate is equally likely to be high or low. 

One of the leading students of the efficient market, 

Fama (1991) argues that most stock market price forecasts 
752 THE FUTURE OF ENERGY GASES 

that attempt to value a company on the basis of "technical" 

criteria in the market (for example, price patterns) or on 

"fundamental" criteria (the· composition of the company's 

portfolio of assets) are "investor pornography." Fama states 

that in an informationally efficient market (which the U.S. 

stock market .assuredly is) that there is no possible way to 

systematically discern true price trends and thereby beat 

the market. The market is not a game of skill that one can 

beat by being astute. It is not a blackjack game, which one 

can beat (statistically speaking) simply by counting cards. 

It is not a baseball game in which an astute manager can 

increase his odds by formulating and executing better strategy. Absolutely the contrary, the market is a game of pure 

chance, not skill. It is a craps game, a slot machine, a roulette wheel, in which the odds are completely specified outside any one individual's purview. There is no viable 

strategy for out-thinking one's adversaries except by carefully and completely accepting the fundamental efficiency 

of the market, recognizing that all relevant information is 

already embedded in the market. The best strategy is to 

throw darts at the stock market page of the Wall Street 

Journal, not to systematically select and reject stocks on 

the basis of technical or fundamental analysis. In the gas 

context, the best strategy is to observe and model the gas 

market and thereafter adopt the most profitable (usually 

least cost) strategy. 

An efficient market is a competitive, free market in 

which many players make many frequent transactions. Assuredly the U.S. and North American gas markets are quite 

efficient. There are thousands of trades, contracts, and traders. There are many players-producers, aggregators, brokers, transporters, distributors, final users, and arbitragers. 

Regulators are striving constantly to foster market efficiency. There is no shortage of information, forecasting, and 

misinformation. There is a futures market, albeit somewhat 

limited in duration. Traders are relatively untrammeled by 

regulation that would restrict the transactions they can 

make. There is an emerging forward market that allows 

increased trading into the future. There are few signs of 

monopoly or monopsony power. The signs of an informationally efficient market abound. Signs of an inefficient 

market (for example, monopoly power by a small number 

of players, franchise monopoly behavior by regulators, astute players systematically duping other players and beating 

the market, bilateral negotiations rather than multilateral 

trading, vertical integration without pricing of intermediate 

commodities) are nonexistent. 

It would be difficult to argue that the North American 

gas market is inefficient to any degree. Given the inherent 

efficiency of the market, it is futile to make subjective estimates of future market prices. If, in an efficient market, one 

cannot make subjective estimates of market prices, there 

are three alternatives (fig. 1). Price expectations may be 

determined by (1) market observations (observing present 

and future prices of key securities traded in the market), (2) 

building confidential and proprietary models and data, and 

(3) surveying outside experts. I will argue for using a combination of approaches (1) and (2). 

Market 

Observations 

Private <----------------" Survey of 

Models and Data Outside Experts 

Figure 1. Three methods of forecasting gas prices. Combining 

market observations with models and data works best for the real 

world. 

FORECASTING BASED ON MARKET 

OBSERVATIONS 

Do observations of today's market presage the future, 

or are they largely irrelevant to what is going to happen in 

the future? Market observations are known to be the most 

reliable source of information, because everything that is 

known or knowable is explicitly embedded in market prices. Even when people make decisions based entirely on 

proprietary or confidential information, they cannot hide 

that information from the market. On the contrary, the investment, operation, and retirement decisions they make 

"signal" the market and induce changes therein. Through 

this signaling mechanism, their information is transmitted 

to the market and explicitly embedded in the prices and 

volumes therein. This is why we say that everything that 

is known or knowable about securities that are actively 

traded in the market is already reflected in the prices of 

those securities. No individual can be systematically 

"smarter" than the market unless he or she has insider information. To assume otherwise is to speculate. Public domain bodies (for example, federal governments, state, and 

provincial governments, GRI, EPRI) should not be speculating with taxpayer and ratepayer money. Quite the contrary, they should be hedging, pooling, mitigating risks, 

and overcoming market imperfections. Corporations 

should not be speculating with shareholder equity, squandering it (in a statistical sense) as they do so. They should 

be hedging, diversifying, making acquisitions, and divesting so as to optimize their risk/return profile and honor 

their fiduciary responsibility. Neither should be relying on 

subjective estimation of market prices. 

While gas markets are quite efficient in the United 

States and North America, they are also "incomplete." A 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 753 

complete market is one in which all possible spot and forward contracts are actively traded and scrupulously honored. Longer term futures contracts simply do not exist in 

gas markets; the absence of longer term futures contracts 

renders them incomplete. Regulators regularly abrogate 

contracts, rendering otherwise complete markets incomplete. In the "Structural Models" section, a method to overcome whatever market incompleteness exists in gas markets 

is described. 

Today's spot prices, futures prices extending outward 

for 18 months, and a few longer term instruments such as 

forward contracts can be observed in the market. How 

might one discern a legitimate, market-consistent forecast 

extending outward 5 years based on a 5-year forward contract observed in the market? Imagine a security that guarantees delivery of I thousand cubic feet (Mcf) of gas per 

year for the next 5 years. (The present example can be 

scaled up to real world quantities of gas delivered as desired.) Suppose the security sells in the market for $7.20. 

Assuming that the price of gas begins at $1.60 per Mcf 

today, escalates forward at a rate of y percent real per year 

(where y is to be determined), and the discount rate is r 

percent (real), the present value of the I Mcf per year of 

gas deliveries is 

1-(~f PV = ($1.60} I+ r 

1- (~) 1 + r 

(1) 

It is known by observation of the Standard and Poors 500 

(S&P 500) index since the year 1920 (reported by Dimensional Fund Advisors) that the annual real return is approximately 6.5 percent, meaning that r in equation 1 

should be approximately 6.5 percent. One can arbitrage 

(establish a collection of trading positions) between the 

S&P 500 and the oil industry without affecting the return 

in the S&P stocks. Substituting r=0.065, PV=$7.20, and 

solving for y, the value of y=0.01 (y equal to I percent 

real) would satisfy the equation. This equation is telling us 

that the market thinks that gas prices will escalate at approximately I percent above inflation for the next 5 years. 

This simple calculation is rather profound. The equation 

implies that the market value of the security ($7.20 per 

annual Mcf) is consistent with a gas price escalation rate 

of approximately I perce!lt above inflation. If the market 

value of the security were higher, the gas price escalation 

rate would be higher. If the market value of the security 

were lower, the gas price escalation rate would be lower. 

To bet against a security of this type is to gamble. To purchase this security is to lock in a price and eliminate all 

future price uncertainty. 

Tying oil and other price escalation rates to market 

observations can be much more difficult than the simple 

calculation herein. Nonetheless, the simple calculation is 

more reliable than expert surveys. The calculation accounts for all attributes of the efficient market. Such calculations are based solely on objective observations and 

demonstrable actions by a plethora of market participants. 

Unfortunately, forward natural-gas markets are rather 

incomplete. The futures market only extends 18 months 

into the future, yet most of the price risks extend much 

further into the future than that. Furthermore, the forward 

markets just now emerging are rather "thin." A thin market is one in which there are not many players and there 

are not many transactions being made that definitively establish the fair market value of the commodities being 

traded. A thin market may also be one in which the sanctity of the property rights embedded in the securities is 

questionable. If a forward contract is not scrupulously and 

completely honored by both contracting parties and by the 

underlying legal system, then that forward contract is not a 

viable market instrument. It is no different from a spot 

market instrument. 

It is necessary to complement observations of thin markets with structural models. A hybrid approach-combining 

observation of incomplete markets with structural modeling-holds promise for predicting how the market will 

evolve in a future world of incomplete markets in which 

contracts may not be scrupulously honored or may not extend sufficiently far into the future to reflect the full range of 

price expectations various market agents may have. 

SURVEYS OF MARKET EXPERTS 

Surveys of independent external market experts regarding future prices in efficient markets are notoriously unreliable. They are hypothetical, and they invariably embody 

the prejudices and self-interests of the experts making the 

forecasts. I have previously stated that in an efficient market, no expert can systematically and consistently beat the 

market because no expert has as much information as the 

market has in aggregate. Forecasting market prices is not a 

game of skill; it is a game of chance. The market is made 

up of people who have "put their money where their mouth 

is," investing in and playing the market and thereby transmitting their information to the market. Individual experts 

are no more than providers of abstraction and academic 

hyperbole. The message to public and corporate decision 

makers is clear: Do not waste time or money with surveys 

of market forecasters. Do not operate anywhere near the 

lower right hand corner of figure 1. Use observations of the 

market complemented by structural modeling. 

EXPERT JUDGMENT TENDS TO BE BIASED 

In expert assessment, it is difficult to identify and eliminate abuse, bias, and self interest. In a study performed for 
754 THE FUTURE OF ENERGY GASES 

the Department of Energy in approximately 1985, Sobodka 

Corporation was asked to assemble future oil price projections made by a number of organizations and examine 

whether those forecasts tended to "cluster" together according to the type of organization that rendered them. The 

four types of organizations considered were banks, Government agencies, consultants, and oil and gas companies. 

Sobodka found that there were four distinct clusters of 

forecasts, and the clusters were strongly correlated with the 

types of organizations that offered them. 

The four clusters include a very low cluster, a low 

cluster, a moderately increasing cluster, and a rapidly escalating cluster. The forecasts made by banks clustered at the 

bottom of the range. Banks had the lowest, most draconian 

forecasts among the entire group. Their motivations would 

seem quite understandable. Banks have somewhat limited 

technical knowledge of the industry, but they are asked to 

bet their money on it. It seemed that banks were discounting future oil price projections as a way to assuage their 

risks. Banks were discounting future oil price escalation as 

a means to discount all projects being offered them in 

hopes that Darwinian natural selection would cull out all 

but the winning projects. Banks were not putting forth oil 

price forecasts they truly believed. They were shading 

their estimates toward the low end of the range to place 

the subjective burden of proof onto prospective borrowers. 

Yet, the projects actually funded by banks were and are 

consistent with a much different forecast of oil price than 

the banks were projecting. Banks were systematically putting forth conservative projections that would most effectively protect their self interests. 

The second lowest cluster corresponded to the oil and 

gas companies, whose equity dollars and ability to service 

debt are at risk in every oil and gas project they pursue. 

Avoidance of such risk motivates them to offer conservative 

forecasts in the same way that banks are motivated. However, within oil and gas companies, there are internal advocates for various ventures, regions, and projects. There are 

people whose careers depend on pursuing particular 

projects in particular regions of the world. There are people 

whose careers depend on using a particular type pf process 

or technology. Such people can be expected to systematically bias the subjective estimates of profitability of those 

projects upward by biasing oil and gas price forecasts upward and project costs downward. Certainly there is momentum within companies to continue in the oil and gas 

business, and such momentum favors higher price forecasts. 

In summary, offsetting the forces of risk aversion (which 

were evident within the banks), there are positive, proactive 

internal forces in oil and gas companies. Forecasts by oil 

and gas companies often reflect the tension between project 

advocacy and risk aversion. The net result of this tension is 

to push up price forecasts slightly above the banking industry. While oil and gas company price forecasts are quite 

conservative, they are not as conservative as bank forecasts. 

Apparently price forecasts offered by the oil and gas 

industry like the banking industry are designed to serve 

their self-interests. Industry forecasts contain a market-appropriate balance between conservatism (a desire to screen 

off the unprofitable ventures) and optimism (which typifies 

project advocacy). It seems that oil and gas industry price 

forecasts do not necessarily reflect what companies truly 

believe. Their price forecasts are intended to work to their 

business benefit rather than to communicate objectively 

what the companies truly believe. 

It is useful to consider the opposite extreme, the high 

price forecasts. Not surprisingly, Government forecasts invariably lie at the extreme high end of the spectrum. Government energy policy agencies are systematically 

motivated to forecast high. The motivation is simple. If oil 

prices were forecast to be low forever, why would we 

need government energy agencies? What economic function would they serve? Their very existence derives in 

great measure from high oil prices and the arguments favoring extra-market action to counter such high prices. 

High oil prices serve Government decisionmakers' self-interests by keeping their profile high. Government policy 

bodies have consistently since 1973 rationalized and justified their existence by citing high and escalating oil prices, 

import security problems, balance of trade problems, unethical or aggressive behavior by "increasingly insecure 

and high priced Middle Eastern sources," and other "sky is 

falling" motivations. Yet, in spite of Government forecasts 

of high and increasing prices put forth continually since 

the first oil embargo in 1973, prices have retreated in real 

(inflation adjusted) terms almost back to where they were 

in the late 1960's. Prices today are not high by historical 

standards. In effect, today is the "good old days" as far as 

real gasoline (and oil) prices are concerned. While the 

United States has undergone profound structural changes 

on the consumption side, the supply side continues to 

show very low real oil prices, which will probably continue indefinitely. 

Included with Government agencies are the utility and 

energy research institutions: the Electric Power Research 

Institute (EPRI), the Gas Research Institute (GRI), and the 

Department of Energy research laboratories. Economists 

generally recognize a very legitimate research and development role for such organizations because it is known 

that the "invisible hand" of the market often leads to systematic underinvestment in technological innovation. (Innovators cannot privately recover the benefits of their 

innovations and are therefore motivated to underinvest.) 

However, given the political and funding realities, research 

and development organizations are often motivated to predict high prices for the same reasons as Government agencies. As an example, would one expect a research and 

development organization such as GRI to put forth a gas 

price forecast that never rose high enough to exceed the 

anticipated cost of new technologies it is attempting to de-
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 755 

velop and commercialize? Instead, would one expect them 

to forecast substantially increasing prices some 5 to 10 

years out, just when various new technologies under development are anticipated to be ready for commercial deployment? Are research and development organizations be 

better off to argue that their new technologies, when delivered to commercial status, will be eagerly absorbed into 

the market? Over the past 18 years of research and development organization forecasts, there seems to be a recurrent theme of rapidly increasing real prices some 5 to 10 

years into the future, with very receptive market eager to 

absorb new technologies they are developing. 

Public bodies are also putting forth forecasts that 

serve their self-interests, not necessarily forecasts they believe. Because public bodies are not viable, proactive market agents investing their own money, their actions do not 

signal the market. Public bodies are bystanders, albeit 

powerful bystanders, who can affect the market only 

through regulation and (or) incentives but not through participation. The Tennessee Valley Authority (TVA) and 

Bonneville Power Administration (BPA) are Governmentowned exceptions to this general statement. They are market participants, and their ability to signal the market is 

similar to other producers. 

As one might anticipate, consultants fall squarely in 

the middle between the low industry forecasts (banks and 

oil and gas producers) and the high Government forecasts. 

Serving banks, oil and gas companies, and the Government, consultants are strongly motivated to fall somewhere 

in the middle. Extreme opinions do not sell consulting 

work. Iconoclastic or controversial prognostications do not 

sell consulting work. Middle of the road, conventional wisdom, :'plain vanilla," nonthreatening forecasts, presented 

with authority and backed by apparent industry consensus, 

sells consulting work. Like the other types of organizations, it is difficult to conceive that consultants as a group 

are putting forth forecasts they truly believe. They too 

seem to be putting forth forecasts that best serve their own 

interests. 

IS AN EXPERT'S TRACK RECORD MEANINGFUL? 

What if a particular expert has an unblemished track 

record? What if that expert actuany "called the tum" in oil 

prices correctly each of the past three times? Should you 

believe an expert on the basis of his or her track record? 

The answer is a resounding no! An example from Burton 

Malkiel in his classic book A Random Walk Down Wall 

Street illustrates. Consider a gymnasium filled initially 

with 1,000 people. At the front of the gym at a podium, 

there is a speaker flipping a coin. At each flip, every person who calls the coin correctly remains in the gym for 

the next flip, and every person who calls it incorrectly 

leaves. What will we see after twelve or so flips? We will 

see a single person remaining in the gym, a veritable genius at calling coin flips, a person with uncanny, paranormal abilities. The last remaining person will have an 

irrefutable record of twelve consecutive correct calls of the 

coin without a single error! 

What if that last person remaining in the gym approached you and offered: "I would be eager to call coins 

for you. For a mere $2500 per day plus travel expenses, I 

will travel to your office and assist you in calling coins. I 

have a system. It is a computer model for calling coins. 

The computer model is highly scientific. You can tum 

your coin forecasting over to me secure in the knowledge 

that I cannot miss. I can make you rich." Would you hire 

the last person in the gym to call coin flips for you? 

Would you believe any forecasts he might make? Is he 

better at calling coins than the average person on the street 

or better than you are? After an, the expert has a demonstrably perfect track record, twelve straight correct cans of 

the coin. The answer of course is No. By sheer happenstance, the expert just happened to be the last person in 

the gym, the last person standing. Clearly if there were an 

additional coin flip, he would be no more likely to can it 

correctly than anyone else. 

So it is with price forecasting. Most people feel more 

comfortable relying on a person with a documentable 

track record of accurate past forecasts. Somehow, a successful track record gives credence to people trying to 

forecast price. The person who called the turn last time is 

likely to make more money as a price forecaster than the 

person who missed the boat. However, based on the simple coin flipping analogy, given the number of people 

prognosticating gas and oil prices these days, the vast majority of people arguing they called the tum correctly just 

happened to be the last person standing in the gym. They 

were just lucky! Businesses and Government should rely 

instead on forecasters who combine market observations 

with structural modeling. 

STRUCTURAL MODELS 

In projecting future prices for use in decisionmaking, 

structural models and data designed to simulate the operation of an informationally efficient but incomplete market 

are the best way to complement direct observations of an 

incomplete market. To wit, anything not observable in the 

market should be structurally modeled using an economic 

theory (for example, supply-demand balancing under rational expectations). Such models should simulate independent, autonomous, economic agents. A model should 

represent an informationally efficient market by explicitly 

accounting for the players, their alternatives. (resources), 

their information (what they know and what they do not), 

their preferences (what they want), and the network interrelations among them. A model should not simply be a 
756 THE FUTURE OF ENERGY GASES 

spreadsheet accounting system. One should not build a 

model that assumes all the players act in lockstep to optimize some overall social objective. DOE's and EIA's linear programming models beginning with the Project 

Independence models of the 1970's and continuing with 

today's National energy modeling system (NEMS) have 

always assumed lockstep pursuit of an overall social objective (cost minimization). Such models do not describe 

the realities of a decentralized market in which individual 

agents simultaneously pursue self-interest. One should not 

appeal to "social engineering" concepts such as systems 

dynamics that view market agents as inflexible, myopic, 

unthinking automatons. 

A PRUDENT, WORKABLE STRATEGY FOR 

MARKET FORECASTING 

In an ideal world, one would operate entirely by market observations (see fig. 1 ). By so doing, one could hedge 

away all price risk. However, in a non-ideal world in 

which markets are not entirely efficient and for which 

complete spot and futures markets may not exist, one 

should operate along the line between market observations 

and structural modeling of market activities (see fig. 1 ). In 

evaluating risks and returns, economic or otherwise, models must be combined with market observations. By so 

doing, you run the least risk of making the wrong assessment, defiling your conclusions, and bearing unnecessary 

risks. Direct subjective estimation of future market prices 

are never accurate. 

Gas and oil markets in North America (and in fact 

worldwide) have become increasingly efficient. This increased efficiency has profound implications for resource 

assessment-observed prices in the market communicate 

what the market believes the resource base to be. Any resource assessment that runs counter to what the market believes is probably wrong. In the past, difficulties have 

plagued resource assessment and subsequent market analysis precisely because market price forecasting models have 

approached resource assessment data as if it were immutable scientific· truth. Supposedly immutable scientific truths 

are loaded into models and the results are given credence 

whether or not they depart from observed market realities. 

The models are argued to be credible simply because they 

are based on data that is scientifically derived. The idea 

that reliable data leads to reliable models is shown in figure 2. The left circle in the figure represents data from 

resource-base assessment. Scientific, technical, and geologic in nature, resource-base assessment is assumed to be 

an intrinsically correct estimate-one that can be determined and justified by scientific inquiry. 

As shown by the arrow proceeding to the right in 

figure 2, the output of resource-base assessment is typically 

fed directly into a market model. The results of the market 

Geology 

and Cost 

Est i mall; s 

Asscssm~.:nt 

Data 

Economic 

Modd 

"Answer" 

Figure 2. How a model using a unidirectional view works. 

Geology 

and Cost 

Estimates 

Assessment 

Data 

"Answer" 

Economic 

Model 

Figure 3. How a model using an iterative process works. 

model are asserted to be accurate and precise because the 

resource assessment is accurate and precise. Whether or not 

the model gives price-quantity answers that are consistent 

with market observations or are inherently reasonable in 

their own right is deemed immaterial. The model's projections supersede market observations if the two deviate. 

This unidirectional view from resource assessment to 

market model to forecast has proven deficient. To overcome the deficiency, it is necessary to complement the traditional procedure shown in figure 2 by linking the market 

model back to the resource-base assessment, as shown in 

figure 3. This link is a judgmental process whereby the 

reasonableness and consistency of the market forecast are 

compared with observations of prices and quantities in the 

market. If the market forecast is judged unreasonable, one 

must modify the resource-base assessment accordingly. 

The resource assessment must be adjusted not only on the 

basis of intrinsic scientific information assembled from geologists but also on market observations and market model 

runs based on that information. In a reliable model, the 

resource-base assessment must produce market projections 

that are reasonable and consistent with market observations and with arbitrage and trading opportunities available 

in the market. One must conduct an iterative procedure 

between the assessment and the model until the data gives 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 757 

model results that are consistent with observed price realities (fig. 3). If the model gives results that are inconsistent 

with observed price realities, the assessment is probably 

wrong and another iteration is required. 

The iterative procedure is essential. It requires that 

one simultaneously use the best available geologic data 

and the best available market modeling data and iterate 

between them until they become lockstep consistent. Only 

then can one assert that the geologic estimates are consistent with observed market phenomena and simultaneously 

that observed market prices and quantities are consistent 

with volumetric estimates of resources. 

There is one interesting corollary of the approach proposed in figure 3. Price forecasts that look like "hockey 

sticks" are not credible. They are inconsistent with rational 

economic behavior and arbitrage by market agents; the 

market will not support them. If people anticipate rapid 

price runups, they quickly arbitrage in futures markets and 

(or) increase inventories and thereby raise prices today and 

reduce the rate of price runup tomorrow. Prices cannot 

possibly run up faster than the returns from market arbitrage. Price forecasts inconsistent with rational temporal 

and regional market arbitrage simply cannot happen and 

will not be forecast by a reliable model no matter what 

independent resource assessment data might imply. 

A MODEL TO ACCURATELY SIMULATE 

THE BEHAVIOR OF AN INFORMATIONALLY EFFICIENT MARKET 

How can a reliable model of natural-gas prices and 

volumes be built? To build a model that simulates the 

present and future operation of the North American and 

world natural-gas market is to realize that fundamental and 

irreversible changes have swept American, Canadian, and 

world natural-gas markets in the past 8 years. Times have 

changed; the old days are gone. 

Deregulation has fundamentally broken the franchise 

monopoly nature of the gas-transportation system, particularly the upstream portion. Open access transportation has 

provided unequivocal price transparency to all producers 

and consumers in the system. Regulatory risks related to 

operation of a franchise monopoly have given way to market risks related to prices and price fluctuations. There is 

far less government intervention today than at any time 

since the advent of natural-gas markets. Free trade among 

relatively well defined trading blocs (United States-Canada-Mexico and the European Community) fosters price 

transparency and smooth and efficient market operation. 

These and other forces result in wellhead and burner 

tip prices throughout the United States, North America, 

and the rest of the world being determined by supply-demand interactions (or equilibrium) in the tightly interconnected, fiercely competitive North American and world 

natural-gas markets. When the two largest markets in the 

world, North America and the European Community, embrace unregulated, price-transparent markets, it is difficult 

to conceive how prospective producers could operate with 

anything other than increasingly competitive and transparent systems. 

The implications of these insights are that economics 

matter! The operative concept underlying natural-gas markets in the industrialized world is shown in figure 4. Conceptually, there are supply curves that characterize the 

volumes and costs of resource available and demand curves 

that characterize consumption. The crossing point of these 

curves is where the market will tend to operate. The market 

clearing price where the two curves cross is the price toward which the market will trend. 

The market clearing price has two critical interpretations: descriptive and prescriptive. The descriptive interpretation is the more obvious of the two. The market clearing 

price in figure 4 is the "best guess" at what the market price 

will actually be. The price describes the market. If you are 

trying to presage how the market will evolve, the market 

clearing price is your best bet. The price arises from a fundamental structural representation of the economy (embodied in the supply-demand curve pair) and is the best 

description of where the market is likely to evolve. 

The second interpretation, more consequential than the 

first, is the prescriptive or normative interpretation. One 

should assume that everyone in the market knows that the 

market will operate at the crossing point. Spot, contract, 

and futures prices will properly signal everyone in the 

market that the market clearing price in figure 4 will in 

fact be the true market price and that everyone will react 

accordingly. No single individual can know the truth while 

others do not. The normative interpretation arises from the 

notion of an informationally efficient market, and everything that is known or knowable is fully embedded in the 

price. It will not take market agents long to figure it out. 

Price 

Market 

Clearing 

Price 

Quantity 

Transacted 

Supply 

Curve 

Demand 

Curve 

Quantity 

Figure 4. Supply-demand equilibrium or market clearing price of 

gas. 
758 THE FUTURE OF ENERGY GASES 

If the equilibrium shown in figure 4 is the best description of gas market prices and volumes, then there is 

"good news" and "bad news." The good news is that one 

need only assemble a complete set of gas-supply curves 

and gas-demand curves, each of which relates quantities 

with prices. Thereafter, the crossing points will tell the 

story. If one had a single aggregate supply curve and a 

single aggregate demand curve, it would be trivial to calculate the market clearing price and the corresponding volume flowing at that price. The crossing point (by visual 

observation), of which there is but one, could be located 

and its implications reported. 

There are hundreds or thousands of existing and prospective supply curves, one for each basin and for each 

consuming region. There are hundreds or thousands of demand curves, one for each segment and each demand region. There are hundreds or thousands of intervening 

pipelines and LNG linkages. In effect, there are hundreds 

or thousands of pairs of supply and demand curves, every 

pair interlinked with every other pair by a complex network. Such interlinkage recognizes that in the market 

every transaction made necessarily implies that a number 

of transactions are not made. Transactions not made as 

well as transactions made explicitly interlink the entire 

system. 

Because of the market complexity, a computer program is needed to analyze the many supply regions, 

proved and undiscovered reserves, and exploration and 

production costs. The supply regions are characterized 

with supply curves; the many transportation linkages of 

supply regions characterize using transportation markups. 

The many demand segments and regions are characterized 

$1 

V-iS' ----- ,~'' \-' I 1 

using demand curves. The prospective transactions are 

represented using a network that interrelates regional supply, transportation, and demand. 

There is no way to make the requisite calculations by 

hand. There is no way to approximate them using intuitive 

methods. Consider the simplest possible example case 

shown in figure 5. In this example, there are two supply 

regions, each with a simple, straight-line, static supply 

curve (points 1 and 2 in fig. 5); two demand regions, each 

with a simple, straight-line, static demand curve (points A 

and B in fig. 5); and a complete set of prospective pipeline 

linkages connecting the two supply regions with the two 

demand regions. A complete set means that there are linkages from 1 to A, from 1 to B, from 2 to A, and from 2 to 

B. Each prospective pipeline linkage has an associated 

cost and an assumed 100 percent efficiency (no losses). 

It is impossible to determine the market clearing price 

in figure 5 by inspection. To do so requires solving 12 

simultaneous linear inequalities (12 simultaneous equations and unknowns). It is useful to examine these properties in the simple context of figure 5 because certainly any 

properties that hold in this simple situation will also hold 

in the general dynamic, nearly unregulated, multiregional 

market of the United States, Canada, and the rest of the 

world. 

Figure 6 shows the solution for the two supply-two 

demand scenario shown in figure 5. Notice in the figure 

the following: 

1. The prices in the two producing regions are different. In general, wellhead prices in various producing regions are different. There is no intrinsic market force that 

serves to equate wellhead prices in any fundamental way. 

Figure 5. A "textbook" example of a simple gas market with two supply regions 

and two demand regions. P, price; A, region A; B, region B; subscript 1, region 

A; subscript 2, region B; q, quantity. 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 759 

It cannot be surprising that wellhead prices in different regions should be different; the market tells us this everyday. 

2. The prices in the two consuming regions are different. Burner tip prices in various demand regions are different. There is no fundamental market force that strives to 

equate burner tip prices in any fundamental way. Burner 

tip prices are different because there is no intrinsic market 

force attempting to equate burner tip prices across regions. 

An important corollary of this observation is that gas 

and oil prices need not necessarily be equal at the burner tip 

on a British thermal unit (Btu) basis. There are no fundamental forces that serve to equate oil and gas prices. The 

price of gas does not necessarily equate with the price of oil. 

Quite the contrary, gas price can be set by competition 

among gas producers, competition from oil, or competition 

from coal. To assume gas-oil price parity is to risk error. 

3. "Netback" calculations (demand region price minus 

transportation cost back to a particular upstream supply region) do not necessarily work. The netback calculation 

from demand region A to supply region I works, and the 

netback calculations from demand region B to supply regions I and 2 work (fig. ~). However, the netback calculation from demand region A to supply region 2 does not 

work (fig. 6). Netback calculations do not work in general. 

They only work along transportation links that are economically competitive. Without an economic model based 

on supply-demand curve pair crossings, it is impossible to 

sort through the myriad competing transportation links and 

determine which ones are economically competitive (and 

therefore contribute to the netback calculations) and which 

ones are not. 

4. It is necessary to disaggregate the supply side and the 

demand side. The solution to the aggregated supply-aggregated demand problem is not the same as the aggregated 

solution to the disaggregated supply-disaggregated demand 

1.86 (q• $314 

1.86 

1.86 

0 

~a / ," 

2.27 (it• $2.14 

problem. To solve an aggregate problem is to get the wrong 

market clearing price, a price that does not necessarily approximate the properly disaggregated, real-world situation. 

To understand why disaggregation is essen.tial, try to 

aggregate the two supply curves and aggregate the two demand curves shown in figure 5 and then find the price. 

Even if a suitable method of aggregation could be found, 

the answer to the aggregated problem will be entirely different from the answer to the disaggregated problem. 

The logical way to represent geologic, cost, and technology information on the supply side is the supply curve 

or long-run marginal cost curve. Indeed, the supply curves 

used to characterize each of the supply basins are the fundamental data for the model. The "Supply" section of this 

paper describes how to build reliable and consistent longrun marginal cost curves from fundamental play analysis 

of the type performed by the U.S. Geological Survey. 

To represent economic growth and sectorial consumption on the demand side, a dynamic demand curve is used. 

The sectorial demand curves used to characterize each of 

the demand regions are also fundamental data for the 

model. The "Demand" section of this paper describes how 

to build reliable and consistent demand curves. 

The logical way to represent pipeline and distribution 

infrastructure is to assemble cost and loss data for the 

pipeline network. As shown in figure 7, the data for the 

model is the collection of all the regional supply curves, 

all the pipeline and distribution costs and losses, and all 

the regional demand curves. The data to our model are 

curves and transportation costs. 

The model is an automated calculator that finds the 

magic crossing points (fig. 7). The inputs to the model are 

the curves, and the outputs from the model are the crossing 

points, the simultaneous crossing points for all the supply 

and demand curves in the model. 

1.73 <it' $4.14 

0.41 1.32 

132 

1.32 {it• $3.64 

Figure 6. Market clearing prices for the two supply and demand regions shown in 

figure 5. Quantity of gas in thousand cubic feet. 
760 THE FUTURE OF ENERGY GASES 

lZ; MODEL 

p* 

lSd p* 

q* 

q* 

Figure 7. Data input to an economic model are supply and demand curves. Data 

output from a model are market clearing price (p*) and quantity of gas (q*). 

Using the simple supply-demand paradigm as a guide, 

there are several critical properties a properly configured 

supply-demand model must embody. First and foremost, if 

one changes any supply, transportation, or demand assumption anywhere, the model solution must change everywhere. 

Every price and every volume are inextricably interconnected. For example, if one increases the volumetric estimate 

for a resource supply basin in a single supply region, the 

model must drive down prices everywhere-every supply 

region and every demand region (fig. 8). More supply coupled with the same demand implies lower price and higher 

volume. If one decreases the cost estimate for a resource 

supply basin anywhere, the model drives down prices everywhere. Lower cost for the same inventory implies lower 

price and higher volume. A number of similar examples can 

be constructed using the simple supply-demand paradigm. 

In view of the supply-demand paradigm shown in figure 8, it is clear that the price of gas at the wellhead must 

vary substantially across the range of volumetric estimates 

that have been put forth over the past several years. Clearly 

the price of gas will be quite different between the 1974-

derived estimate of 800 Tcf and the 1992 NPC estimate of 

approximately 2,000 Tcf (1,200 Tcf in the United States 

and 800 Tcf in Canada). The 2,000 Tcf case could portend 

prices at one-half, one-fourth, or even less than the 1974 

estimate. Explicit supply-demand methods will not be susceptible to the practices of the past 20 years during which 

markedly different resource-base estimates have implied 

zero differences in price projections. 

Prices can never be input to a reliable supply-demand 

model; supply curves and demand curves are inputs to the 

model. Market clearing prices are outputs from the model. 

Curves go in, crossing points come out. 

WHAT GEOGRAPHIC AND TEMPORAL 

SCOPE CAN BE ACHIEVED? 

To accurately represent natural-gas supply, transportation, and demand, one must necessarily disaggregate supply 

Price 

Demand 

A Quantity 

Price 

Demand 

B Quantity 

Figure 8. A supply-demand paradigm showing (A) how increased quantity of gas coupled with no change in demand lowers the price and results in more gas being available and (B) 

how decreased cost for any supply region drives down prices 

everywhere. 

regions, transportation linkages, and demand regions. How 

much disaggregation is necessary? How much disaggregation is possible? The degree of supply and demand side 

disaggregation for North America summarized here consti-
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 761 

tutes the basis of the North American regional gas (NARG) 

supply-demand Model. The much greater degree of supply 

and demand side disaggregation used to represent the world 

summarized here has been implemented within the world 

gas trade model (WGT). The North American and world 

network structures presented herein should be interpreted as 

a simple, straightforward expansion of the two supply region-two demand region case shown in figure 5. 

The network structure required to properly represent 

North American gas markets will be presented in hierarchical form beginning with the interrelation among the United 

States, Canada, and Mexico. The second level of the hierarchy examines the regional supply and demand structures 

resident within each of the three main countries. The third 

level examines the degree of technological and process disaggregation resident within each of the producing and consuming regions within each region within each of the three 

countries. It is convenient as an organizing and expositional 

aid to move hierarchically downward from aggregate reBRITISH 

COLUMBIA 

• 

BRITISH 

COLUMBIA 

.:·• ;; 

WESTERN 

Al88lTA CANADA . .,: .. ,;. . 

SASK 

.. · .. : .. 

FIOCKY 

.. MTNS 

SAN..JUAN 

·=··== 

...... 

• N GREAT 

PLAINS 

WNCi • 

MTN 

Figure 9. North American supply basins and demand regions used for the North American regional gas (NARG) 

model. Basins shown by stipple pattern; open circles denote existing and prospective export points for Canada to 

the United States. Northern California (NOR CAL) demand region further divided to show specific gas utility 

service regions: PGE, Pacific Gas and Electric; EOR, 

.California Enhanced Oil Recovery. Southern California 

gions to successively more disaggregated regions containing multiple supply, transportation, and demand activities. 

North America comprises three main geographic regions-the United States, Canada, and Mexico. The political boundaries of these three regions are shown in figure 9. 

The figure shows Alaska as a part of the United States, but 

because of its remoteness from the principal markets, it 

must be represented as a fourth distinct geographic region. 

Therefore, its existing and prospective future pipeline and 

liquefied natural gas (LNG) connections with the rest of 

the regions must be represented. Within each of the regional subdivisions of North America, subregional detail must 

be distinguished. Whereas it would be possible to consider 

geographic subdivision to the state and (or) province level, 

it is neither pragmatic nor necessary. Indeed, the specific 

regional detail needed depends on where the largest demand centers are located, where the various supply regions 

are situated, and what existing and prospective pipeline infrastructure connects each. The challenge in economic 

.. • EAST 

: .' >·:,·.CANADA 

(SOCAL) demand region further divided to show specific 

gas utility service regions: SCG, Southern California Gas; 

SDGE, San Diego Gas and Electric. SASK, Saskatchewan; NW, North~est; N, Northern; WNC MTN, West 

North Central Mountain; WSC, West South Central; ESC, 

East South Central; ENC, East North Central; E, Eastern; 

NE, New England; MID ATL, Mid-Atlantic; S ATL, 

South Atlantic. See text for discussion. 
762 THE FUTURE OF ENERGY GASES 

modeling is to identify commonalities among states and 

provinces that would justify aggregation. 

DEMAND-SIDE STRUCTURE 

The degree of regional disaggregation on the demand 

side is governed largely by the census regions of the United States. Much of the demand-side data is assembled according to census region, of which there are presently ten. 

The census regions and their assigned names are shown in 

figure 9. There is historical precedent to disaggregating 

demand by census region, and there is much accepted 

data. Furthermore, climatic distinctions among census regions are usually deemed adequate to reflect different 

weather and usage patterns throughout the United States. 

Finally, census region disaggregation strikes an appropriate balance between the desirability of greater demandside disaggregation and the need for a manageable model. 

Because of the large number of pipelines in California, the Pacific census region is substantially disaggregated. California is distinguished from the rest of the Pacific 

census region. The rest of the Pacific region is termed the 

Pacific Northwest region. Within California, northern California and southern California are distinguished. Further 

distinctions among the specific gas utility service regions 

within southern California-Southern California Gas, San 

Diego Gas and Electric, and California Enhanced Oil Recovery-are made. I have found it sufficient to disaggregate the United States into the following 13 demand 

regions (which I believe to be the minimum acceptable 

disaggregation): New England, Mid Atlantic, South Atlantic, East North Central, East South Central, West South 

Central, West North Central mountain, Pacific Northwest, 

northern California (Pacific Gas and Electric), Southern 

California Gas, San Diego Gas and Electric, California 

Enhanced Oil Recovery, and Alaska. 

It is appropriate to aggregate the 12 provinces and territories of Canada into 4 aggregate demand regions. British Columbia lies west of the main supply markets in 

Alberta and the main demand markets in Ontario. Because 

of its large prospective supply and export possibilities, 

British Columbia must be disaggregated. The provinces of 

Alberta, Saskatchewan, and Manitoba can be aggregated 

into a region called Western Canada. Eastern Canada includes all provinces east of the Ontario/Manitoba border 

and is divided into two subregions-Ontario and the rest 

of Eastern Canada (Quebec and the Maritimes). Ontario is 

distinguished because of the high concentration of population and industry in the province and because of the economic and political power Ontario wields in Canada. To 

summarize, Canada is subdivided into four demand regions: British Columbia, Western Canada, Ontario, and 

Eastern Canada excluding Ontario. 

Mexico is represented as a single demand region, although there is growing motivation to distinguish the 

northern regions of Mexico along the border (which are 

growing rapidly) from the southern and central regions of 

Mexico (which are industrialized and populous). 

In modeling world gas, the demand-side structure must 

have at least the level of detail resident within the DFI 

(Decision Focus, Inc.) world gas trade model. In the model, 

eight global regions are represented: North America, Latin 

America, Western Europe, Former Soviet Union and Eastern Europe, Africa, Middle East, Mainland Asia, and Pacific Rim and Australia. Within these eight global regions, the 

demand side has been disaggregated as follows: 

North America is disaggregated into Canada, the United 

States, and a summary representation of Mexico. 

Demand within Latin America is disaggregated into four 

regions. These are Mexico, northern South America (including Central America), Brazil, and southern South 

America. These four regions encompass all of Latin 

America from Mexico southward. 

Demand within Western Europe is disaggregated to specifically enumerate the large consumers and the major 

transit regions. The United Kingdom, Germany, France, 

Spain, Belgium, Netherlands, Italy, Denmark, Portugal, 

and other Western Europe are distinguished in the model. 

The former Soviet Union can probably be treated as a 

single, aggregated bloc. It will be desirable to disaggregate the more rapidly growing former Soviet and Eastern 

European states, particularly if any of those states experiences more rapid than expected development and growth. 

There is not much current demand in Africa, nor is there 

much projected future demand. Therefore, it is sufficient 

to distinguish the northern part (which has greater growth 

prospects) from sub-Saharan Africa and points south. 

It is sufficient to treat the Middle East as a single aggregate demand region. 

Mainland Asia is disaggregated to distinguish the major 

population centers and the major areas with growth potential. These are Pakistan, India, China, and other 

mainland Asia. 

The Pacific Rim and Australia are disaggregated to distinguish the major consuming regions. These are Japan, 

Korea, Taiwan, Western Australia, eastern Australia, New 

Zealand, and the ASEAN countries (all other Pacific Rim). 

SUPPLY-SIDE STRUCTURE 

UNITED STATES 

It is not appropriate to characterize the basic supply 

regions of the United States by political or demographic 

boundaries. Rather, it is appropriate to subdivide the supply regions according to existing and prospective naturalgas producing potential. In other words, the United States 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 763 

should be subdivided on the basis of geologic considerations. Also, making supply region disaggregation, consideration must be given also to the structure of the existing 

and prospective pipeline system. In particular, supply regions must be associated with the upstream ends of existing pipelines and with the upstream ends of anticipated 

new pipelines. 

The supply-side disaggregation proposed here was selected for several reasons. First, when it is necessary to 

distinguish differences among gas-producing basins in 

terms of transportation costs to demand regions that compete for that gas, those· basins have been associated with 

distinct supply regions. 

Second, for those sources that will require new pipeline capacity, regional supply distinctions must be made. If 

a particular gas-producing basin relies on the addition of 

new pipeline capacity to become economically viable, that 

supply region is distinguished from other supply regions. 

Indeed, in such cases, the supply region and the outward 

bound pipeline are inextricably linked, and they must be 

represented as a pair. 

Third, when it is necessary to distinguish resource endowment and cost differences among producing basins, 

those basins are distinguished by region. In general, there 

are substantial differences among gas-producing regions 

with regard to extent, cost, and distribution of the naturalgas resource base. It can be argued that such heterogeneity 

of the resource-base motivates an extremely detailed representation of natural-gas supply. Counter to such an argument is the observation that much supply-side aggregation 

is dictated by the specific structure of the pipeline system. 

In an economic model, the desirability of more supplyside regional and technological detail must be balanced 

against the desirability of realistically representing key 

transportation corridors for delivering gas to market. 

Fourth, many supply or pipeline projects directly affect only localized regions of the United States or Canada, 

yet the indirect effects proliferate broadly throughout all 

supply and demand regions of all countries in the world. 

In effect, prices carry economic signals from the single 

site directly affected to all other regions of the world 

along all competing and complementary parts of the transportation network. The representation of the pipeline network must contain sufficient detail to represent all 

important existing and prospective future paths. 

Fifth, Government policy can be region-specific. Excessive aggregation across regions would obviate the ability of a model to properly represent Government policy. For 

example, there are significant tax, financial, and other differences among regions that necessitate regional distinctions. Border price regulations Canadian agencies might 

impose, alternative royalty and tax structures local and national governments may impose, tax subsidies for certain 

types of resources (for example, coal seams tax credit), and 

other similar phenomena dictate substantial regional detail. 

With regard to the conventional and unconventional 

natural-gas resource base, it has proven useful to adopt the 

Potential Gas Committee (PGC) regions and designations. 

The PGC regions are defined rather conveniently relative to 

the U.S. pipeline system. The North American supply basins in relation to the demand regions are shown in figure 9. 

On the basis of the regional disaggregation developed by 

the PGC, the following supply-basin disaggregation should 

be used for the United States: 

The North Alaska producing region requires significant 

overland transportation across Alaska to reach markets 

(for example, ANGTS, Trans Alaska Gas System). 

The South Alaska producing region requires much less 

overland transportation within Alaska to reach a port or 

a local market. 

The San Juan Basin includes the conventional and coal 

seams producing basins in the Four Comers area of the 

country. 

The Rocky Mountains region is a rather aggregated region that contains the west-central United States except 

for the San Juan and contiguous basins. The primary resource base lies in the northern part of the Rocky 

Mountain region of the country. 

The Northern Great Plains region includes regions east 

of the Rocky Mountains in the plains areas of the United States. 

The Anadarko region includes the Kansas-Oklahoma 

midcontinent area. 

The Arkoma region is becoming increasingly important, 

both as a producing region and as a contributor to gason-gas competition and displacement. 

The Permian region includes west Texas and New Mexico. 

The Gulf Coast region includes the main onshore and 

offshore regions of Texas and Louisiana. These are Louisiana onshore, Texas onshore, eastern Gulf onshore, 

and Gulf offshore. 

The Midwest region includes the north-central producing areas of the United States. 

The Appalachian region includes the entire Northeastern 

part and Eastern Seaboard of the United States. 

The Offshore Atlantic region includes the offshore regions in the Atlantic Ocean. 

The Pacific Northwest region includes all West Coast 

production outside California. 

The Southern California region includes all onshore and 

offshore production in southern California. 

The northern California region. 

CANADA 

For Canada, the primary producing basin is the Western Canadian Sedimentary Basin (and a subregion called 
764 THE FUTURE OF ENERGY GASES 

the Deep Basin). Other important basins in Canada are located in the MacKenzie Delta, the Beaufort Sea, and the 

Arctic Islands, all located north of the Western Canadian 

Sedimentary Basin. Eastern Canada (Hibernia) has some 

resource potential as well. The specific regional disaggregation suggested for Canada is chosen for several reasons. 

First, it is necessary to survey and represent the location 

of the primary gas deposits in Canada, particularly as they 

relate to the major transportation systems (Nova, Westcoast, Northern Border, TransCanada). 

Second, the Canadian resource base and transportation 

system must be distinguished at a level of geographic detail 

necessary to support analysis of six existing and prospective export points to the United States: Sumas/Huntington 

(Westcoast), Kingsgate (PGT), Monchy (Northern Border), 

Emerson (Great Lakes and Viking), Niagara (New York), 

and Iroquois (New York/New England). 

Third, it is necessary to distinguish demand patterns in 

Canada, which in the past have influenced not only delivered gas prices in Canada but also export prices to the 

United States. In particular, much Canadian gas demand 

occurs within Ontario, Canada's most populous and most 

politically influential province. However, Ontario demand 

must be served through long-distance pipelines from Alberta either indirectly through the Great Lakes system or 

directly through TransCanada. Alberta and points intermediate, such as Saskatchewan, must _be distinguished. 

Fourth, it is necessary to distinguish the more northem, Arctic gas resource basins in sufficient detail to discern when, if ever, transportation systems from those 

regions will become competitive. In particular, the supply 

structure representing Canada must be sufficiently robust 

to analyze whether exploring successively up the MacKenzie is more economic than building a complete pipeline to 

the MacKenzie Delta. The geographic detail shown in figure 9 is sufficient to answer such questions. 

Within each of the seven Canadian supply regions and 

subregions (British Columbia, Alberta, Saskatchewan, 

MacKenzie, Beaufort, Arctic Islands, Eastern Canada), the 

volumes and costs of conventional and unconventional gas 

at various depth intervals, resource types, and subregions 

are all represented. Canadian resource and cost data are 

available from the Canadian Geological Survey, the National Energy Board, the Canadian Energy Research Institute, and other organizations within Canada. 

The degree of detail necessary to represent Canada is 

as follows: 

The British Columbia region includes the Deep Basin of 

British Columbia and part of the Western Canadian Sedimentary Basin that is located in the province of British 

Columbia. 

The Alberta region includes most of the Western Canadian 

Sedimentary Basin. It also includes the rather substantial 

tight sands and coal deposits located in Alberta. Supply is 

disaggregated by these three types of resource. 

The Saskatchewan region includes the eastern portion of 

the Western Canadian Sedimentary Basin located in 

Saskatchewan. 

The northern Canada region includes gas in the Northwest and Yukon Territories, the MacKenzie River Valley 

and Delta, the Beaufort Sea onshore and offshore, and 

the Arctic Islands north of the North Slope. 

The Eastern Canada region includes all gas east of Manitoba, primarily offshore gas in Hibernia and contiguous 

developments. 

The disaggregation of the supply side of the model is 

guided largely by the regional distribution of the conventional resource base. Unconventional gas (from tight sand, 

from coal deposits, and from shale) is disaggregated and 

grouped into the key conventional gas-producing regions 

as dictated by physical location. Using the same regional 

distinctions for unconventional as well as conventional gas 

seems appropriate because unconventional gas resource 

must have the same access to the transportation system as 

conventional gas. 

Coal gasification is regionalized according to the location of coal deposits in the United States. The major coalproducing regions have been associated with the various 

PGC supply regions and have been situated within the corresponding gas-supply regions. For example, the North 

Dakota coal region (where minemouth coal gasification 

could someday occur) is placed within the northern Great 

Plains gas-supply region. Small supplemental sources such 

as methane from waste or biomass are positioned within 

the various demand regions; their position reflects the fact 

that they use oniy the distribution system, not the longdistance transportation system. 

MEXICO 

Three import and export points connecting Mexico 

with the United States must be represented. These are the 

Texas border (Reynoso), Arizona border (Yuma bypass), 

and California border (San Diego connection). Gas presently flows from the United States to Mexico. If the Mexican National Pipeline is ever completed, gas could flow 

northward into the United States from Mexico. 

LIQUEFIED NATIONAL GAS (LNG) IMPORT TERMINALS 

There are presently four LNG terminals on the Eastern 

Seaboard of the United States: Everett, Massachusetts; 

Cove Point, Maryland; Elba Island, Georgia; and Lake 

Charles, Louisiana. Additional sites will probably not be 

implemented on the Eastern Seaboard because the four existing sites span the significant markets, and it is probably 

not necessary to include additional import locations. However, it is probably necessary to consider two prospective 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 765 

sites on the West Coast (California and Pacific Northwest) 

and one prospective site in Eastern Canada (Quebec). 

WORLD OUTSIDE NORTH AMERICA 

More interesting than the question of which existing 

and prospective LNG sites should be included for North 

America is the question of what is the price level at which 

LNG can be landed and regasified at these terminals now 

and in the future? To answer this question, it is necessary 

to construct a comprehensive, multiregional world gas 

trade model, which subdivides the world into a large number of supply regions as well as demand regions. Following is the level of supply disaggregation necessary to 

characterize world gas markets and to accurately predict 

the landed price of LNG in North America: 

North America is disaggregated into the United States, 

Canada, and Mexico. 

Latin America's primary gas-producing regions are 

Mexico, Venezuela, Trinidad, Columbia-Ecuador-Peru, 

Brazil, and Bolivia-Chile-Argentina. 

There are several supply regions in Western Europe. 

The major supply regions within Europe that serve or 

prospectively serve Western Europe are the United 

Kingdom, Netherlands, other European Community 

countries in Western Europe, Norway, and non-European Community Western Europe. 

There are vast supplies of natural gas in the former Soviet Union. The following level of disaggregation is the 

minimum level required to understand the supply-demand situation in Western Europe, Eastern Europe, the 

former Soviet Union, and competitive supply regions in 

that part of the world. The disaggregation of the supply 

regions in the former Soviet Union and eastern Europe 

is as follows: Romania, Other Eastern Europe, Pechora/ 

Barents Sea, Volga/Urals and contiguous areas, Western 

Siberia, and Eastern Siberia/Sakhalin Island. 

Supply potential in Northern Africa is prospectively 

very important in Europe. The following level of supply-side disaggregation is necessary for Africa: Algeria 

(Northwest Africa), Libya/Egypt/Sudan (Northeast Africa), Nigeria, and other Africa. 

The enormous supply potential of the Middle East is 

disaggregated as follows: Iraq/Kuwait, Saudi Arabia, 

Qatar, United Arab Emirates, Iran, and other Middle 

East. 

Mainland Asia must be disaggregated to determine its 

competitive ability to serve the primary demand centers 

in India, Japan, Taiwan, Korea, Australia, and New Zealand. Following is the required degree of disaggregation: Afghanistan, Pakistan, India, Burma/Bangladesh, 

Southeast China, North China, and other China. 

The Pacific Rim and Australia supply sources are disaggregated using the same philosophy as Mainland Asia: 

Thailand, Malaysia, Indonesia, Northwest Shelf Australia, Western Australia, Southeastern Australia, and New 

Zealand. 

The degree of supply-side disaggregation around _the 

world used for the DFI world gas trade model is the same as 

that used for demand side. It is probably necessary to include 

more detail when addressing single-country or single-region 

questions. However, more detail would not be necessary 

when predicting wellhead and burner tip prices in the major 

producing and consuming regions around the world. 

DEVELOPING REGIONAL SUPPLY 

CURVES FROM FUNDAMENTAL 

GEOLOGIC AND COST INFORMATION 

STEP I-REGIONAL ESTIMATES OF PROVED 

RESERVES AND INITIAL YEAR 

PRODUCTION LEVELS 

The first step is to assemble regional estimates of 

proved (established) reserves and initial year (1992) production levels. Proved or established reserves include those 

reserves that require little or no additional fixed cost to 

produce. For proved reserves, fixed costs are largely sunk 

and only variable costs are required to bring the gas to 

market. Proved reserves are an important determinant of 

gas prices because of their low prospective costs to market. 

Basin- and country-specific proved reserve data are 

available from Government agencies complemented by 

data from sponsors of DFI's world gas trade program. For 

North America, such estimates are made by the Energy 

Information Administration (EIA) on the basis of corporate and other submissions. For the world, estimates are 

made by the U.S. Geological Survey. DFI has assembled a 

complete set of such estimates for all the producing regions of the world as described in the previous section. 

Because subsequent steps require significant disaggregation of the natural-gas resource base, this step requires 

disaggregation of proved reserves into such categories as 

dry versus associated gas, condensate field gas, deep versus shallow gas, onshore versus offshore gas, and conventional versus tight or unconventional gas. 

STEP 2-REGIONAL ESTIMATES OF 

UNDISCOVERED RESOURCES 

The second step is to make regional estimates of undiscovered resources on a basin-by-basin basis for each 

type of gas resource considered. (Many other papers in this 

volume offer resource estimates for a wide variety of gas 

rel)ources.) The volumetric estimates of undiscovered resources will be essential for subsequent steps in which the 

exploration and development costs are estimated for those 
766 THE FUTURE OF ENERGY GASES 

basins and coupled with the volumetric estimates. To support subsequent analysis of the cost structure of the resource in place, one must distinguish to the maximum 

degree possible the various types or qualities of resource: 

deep versus shallow, onshore versus offshore, conventional 

versus unconventional, associated versus dry, connected 

versus unconnected, and different subregions or countries 

within regions. Such distinctions lie at the heart of the approach used by the U.S. Geological Survey, the Potential 

Gas Committee, the Canadian Geological Survey, and 

other organizations. 

Experience suggests that the volumetric information 

assembled is more complete and comprehensive than information held by individual producer or pipeline organizations. Most producers have detailed information related 

to specific prospects or regions in which they operate (or 

intend to operate). Yet they tend not to have information 

related to regions in which they do not operate. The purpose of step 2 is to provide a uniform level of detail for 

the entire North American and the world resource base to 

better understand the forces that will set gas prices and 

volumes throughout the North American and world natural-gas markets. Lacking uniformity and accuracy, it is impossible to project regional gas prices or volumes and to 

value various gas assets. In particular, if one lacked reliable information for just one region of North America or 

the world, calculations of gas price would be suspect. Accordingly, there must be a premium placed on being complete and comprehensive-breadth of coverage must be 

emphasized over individual detail. 

STEP 3-DISAGGREGATE REGIONAL 

VOLUMETRIC ESTIMATES INTO PLAYS 

To superimpose cost and price information over the 

regional volumetric estimates, subdivide the region or 

country of interest (for purposes of this discussion the 

United States) into geographic areas. Figure 10 shows how 

the United States might be divided into six geographic 

areas. 

For each of the six geographic areas, an assessment pf 

undiscovered gas is made. The gas is subdivided into rather small subregional increments called horizons or plays. 

Rather small means small relative to the size of the geographic region. Each horizon and (or) play is categorized 

as a deep or shallow resource, an onshore or offshore resource, and as a conventional or tight resource. For each 

horizon considered, one must obtain an estimate of the undiscovered resource in place. Adding all horizons in a 

given region yields the aggregate volumetric estimate for 

that region. 

There are several methods used for making subregional volumetric estimates. These methods are summarized as 

follows. 

Figure 10. Six geographic regions of the United States used for 

coupling market information with volumetric estimates of gas. 

(Data from the Potential Gas Committee, 1987.) 

I. Subjective judgment by geologists who are specifically cognizant of a given region. In regions for which 

there is a significant exploration, development, and production history, this is viable and straightforward method. 

For regions in which there has been relatively less exploration, development, and production or which reside in 

"closed" political-economic systems that have precluded 

resource basinal analysis, it may not be. 

2. Another method is statistical extrapolation of historical drilling, finding rate, reserves, production, and (or) 

other information. This method, which is based on classical statistical methods, is inherently fallible. 

3. Another method is to estimate the amount of resources present in an area on the basis of geologic analogy 

with other regions judged to be similar. .· 

In practice, there is a substantial amount of subjective 

judgment in resource-base assessment. However, the approach outlined here does not deJ>end on how volumetric 

resource estimates were developed. 

To summarize, the third basic step is to ensure that the 

aggregate volumetric estimates have been correctly disaggregated to the play or horizon level. This can be accomplished either by making estimates directly at the play 

level or by systematically disaggregating more aggregate 

estimates and e;:xtrapolating them to the play level. This 

disaggregation to the play level is a necessary first step 

toward properly superimposing cost and price information 

over the volumetric estimates. 

STEP 4-ESTIMATE RESERVOIR SIZE AND 

DEPTH DISTRIBUTION 

To infer reservoir size and depth distributions that characterize the resource base in each of the geographic areas 

shown in figure 10, one must ultimately consider the individual horizons or plays within the areas, infer the reservoir 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 767 

size and depth distribution for those plays, and then add up 

the distributions into an aggregate distribution that characterizes the entire geographic region. To do so requires stateof-the-art probabilistic simulation techniques. A somewhat 

detailed explanation of those methods is presented herein 

because of the pivotal importance of the regional gas-supply curves that will ultimately be generated. It is essential 

to understand how volumetric estimates and field and pool 

size distributions combine to form regional gas-supply 

curves. 

There are two ways to develop reservoir size distributions for a given play. One is the subjective extrapolation 

of geologically analogous regions. For some regions of 

North America and the world, there is no production history, and very little is objectively known. The most viable 

(perhaps the only) approach for such regions is extrapolation from known regions believed to have similar reservoir 

size and depth distributions. 

Another method is the statistical extrapolation of historical finding rate information. For some regions of North 

America and the world for which exploration and development activities have occurred over a significant period of 

time (mature regions), there is sufficient historical information to statistically calculate the reservoir size and 

depth distribution of that part of the resource in place that 

remains. For regions for which sufficient historical statistics are available, it is valuable to assemble that historical 

information and perform statistical analysis to complement 

any subjective estimates of reservoir size and depth distributions. Whichever of the two methods is ultimately used, 

the probabilistic methods used to characterize the reservoir 

size distribution are the same. 

Consider a simple homogeneous gas play that contains 

three reservoirs of size B1 Mcf, B2 Mcf, and B3 Mcf. The 

total resourc(! potential, or the total volumetric estimate of 

resource in place, is B 1 +Bz+B3. The critical question is not 

what is the total volume of resource in place but rather in 

what order might one expect to encounter the three reservoirs. The critical observation is that given a set of prospects 

whose elements have a common structural configuration and 

are located in the same geographic region, the bigger reservoirs are most likely to be discovered first. 

To model this effect, suppose that an entrepreneur 

drills a hypothetical three-reservoir play until the first reservoir is;hit. Which reservoir has most likely been hit-1, 

2, or 3? A model of the order in which such discoveries are 

made can be built by postulating a surface area function, 

SA(.), that depicts surface area of each reservoir. That is, 

SA(Bi) =surface area of a reservoir containing Bi barrels (2) 

The: simplest and most frequently used surface area 

function assumes that SA(B)=B. In other words, the surface area of a reservoir is directly proportional to its size. 

(Such an assumption might well be characteristic of advanced seismic technologies, whose ability to discriminate 

a structure should depend on the relative size of the structure.) The typical probabilistic simulation model assumes 

that the reservoir encountered is 

Reservoir 1 with probability 

SA (B1

) 

Reservoir 2 with probability 

SA (B2 ) 

Reservoir 3 with probability 

SA (B3 ) 

(3) 

(4) 

(5) 

This probabilistic assumption can be likened to throwing 

darts at the play, assuming an equal probability of hitting 

each reservoir in the play. The probability of hitting a reservoir in the play is the area of the reservoir divided by 

the total area of the play. (The discussion does not yet 

consider dry holes.) Interpreted differently, the probability 

of encountering the surface area presented by each reservoir in the play is equal. This can be regarded as a statement about the homogeneity of the play. If a play is a 

heterogeneous structure, one might assume that some reservoirs are more likely to be discovered than others. The 

model would have to deal with such heterogeneity by disaggregating plays into homogeneous subplays or by modifying the described reservoir discovery probabilities. 

Assuming that the probability of hitting each reservoir in 

the play is equal, the probability of finding the ith reservoir is simply the surface area of the ith reservoir divided 

by the total surface area presented by all reservoirs in the 

play, or 

SA (B.) • I (6) 

Suppose the first reservoir discovered is reservoir 2. If 

a second reservoir is discovered as a result of additional 

exploration, the model assumes it is 

Reservoir 1 with probability 

SA {B1) 

(7) 
768 THE FUTURE OF ENERGY GASES 

If reservoir 2 already has been discovered, 

Reservoir I with probability 

SA (B3

) 

(8) 

the model assumes that the dart is equally likely to hit 

either reservoir I or 3. The probability that the entire play 

is hit is the ratio of its area to the total areas of the undiscovered reservoirs. 

The order of discovery of the reservoirs and the probability in which that order of discovery occurs is determined 

by sampling probabilities. The exploration component of 

the model is a sampling without replacement model of the 

three reservoirs. The sampling probabilities are functions 

of the reservoir surface areas (which are functions of the 

reservoir sizes). There are 3! possible orders of discovery, 

and each order of discovery has a particular probability 

that is dependent on the size of the reservoirs. 

In general, the surface area function SA(.) is such that 

the probability of discovering the reservoirs in descending 

order of size is much higher than discovering them in any 

other order. The order of discovery is asymmetric, and the 

early discovery of larger reservoirs is strongly favored 

over the discovery of small reservoirs. This is critical because it dictates to a very large degree the nature of the 

supply curve derived from probabilistic simulation. 

Extending the simple three-reservoir model to N reservoirs, if the reservoirs are indexed 1, 2, ... , N, the probability of discovering these reservoirs in the order i 1, i2, ... , iN 

is according to the model: 

SA (B.) SA (B.) SA(B. ) II 12 1

N-I X X ••• X (9) N N N 

~ SA (B; ) ~ SA (B. ) ~ SA(B;) I 

m = 1 m= 2 m 

m = N-1 m 

which can be rewritten 

N-1 

TI SA (B;) 

k = 1 k 

(IO) N-1 N 

TI ~ SA(B;) m 

There are N! reservoir discovery sequences whose probabilities are governed by this equation. 

The discussion thus far has implicitly assumed that the 

size of each of the N reservoirs is known with certainty. 

What if they are not? What if the sizes of the reservoirs 

are governed by a probability distribution over reservoir 

size? How can a probabilistic model of reservoir sizes be 

superimposed over the foregoing model of sampling without replacement? The general approach is to postulate that 

reservoir sizes are governed by a joint probability distribution over the contents of N reservoirs 

(II) 

and to analyze its consequences. The most frequent simplification is to assume that each of the N reservoirs is 

governed by an independent, identically distributed probability distribution. That is, 

(12) 

In other words, each of the B/s assumed to be known with 

certainty in the previous discussion is now assumed to be 

uncertain and to be governed by a probability density 

function f(B). 

The implications of the expanded model can be illustrated by computing the probability of observing the reservoir size sequence S1, S2, ... , SN. Using the probabilistic 

expansion rule, the probability of observing the reservoir 

size sequence S1, S2, •.• , SN can be expanded about the N! 

possible discovery sequences 

~ {Sl' ... , SN' il' ... ,iN} (13) 

il' ... ,iN 

The distribution within the summation {SI•····SN, i1, ... ,iN} 

is the probability distribution that reservoir i 1 is discovered first and is of size S1 (that is, B;1

=S1)., reservoir i

2 is 

discovered second and is of size S2 (that is, B; 2=S2), ... , and 

reservoir iN is discovered Nth and is of size SN (that is, 

B;N=SN)· This corresponds to a single path through the corresponding probability tree; the probability of taking this 

path is 

{Sl' ... ,SN' il' ... ,iN} 

N-1 

TI SA (Bi) 

k = 1 k -----f(A.) ... f(B.) N-1 N 11 1N 

TI ~ SA (B;) 

k=1m=k m 

(I4) 

Per the deterministic reservoir size development, the first 

term is the probability of encountering the reservoirs in 

the sequence i 1, ... , iN given the sizes of the reservoirs and 

the second term is the joint probability of the sizes of the 

reservoirs. Substituting into equation 13 above gives the 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 769 

following expression for the reservoir size sequence 

probability: 

N-1 

n f(B. )SA (B.) 1

k 1k k = 1 }: (15) . . N-1 N 

'p····'N n }: SA(Bi) 

k=1m=k m 

The reservoir size sequence must be independent of the 

particular way in which the reservoirs are indexed. Therefore, the N! different ways of indexing the reservoirs must 

be taken into account and all can be considered equal in 

probability. Therefore, because there are N! possible orderings of the indexes, the summation in the above equation 

can be replaced by a multiplication by N! to obtain the 

expression 

N-1 

TI f(Sk)SA(Sk) 

N! k = 1 

N-1 N 

TI }: SA (Sm) 

k=lm=k 

(16) 

This equation is the fundamental "grist" from which 

stochastic supply curves can be derived. It gives the probability distribution over the sequences of sizes in which 

the reservoirs are likely to be discovered. This reservoir 

size probability distribution can be used in very straightforward fashion by analytical or Monte Carlo methods to 

simulate sequences of reservoir sizes discovered. 

The surface area function SA(.) is asymmetrically larger for the larger deposits (even if SA(B)=B) than for the 

smaller deposits. This fact has been repeatedly corroborated by empirical observation. Furthermore, the quantity of 

gas contained in large fields is asymmetrically larger than 

that contained in smaller fields. The net effect of the 

asymmetric surface area function combined with the 

asymmetrically smaller contents of smaller reservoirs is 

that the highest probability discovery sequences are those 

that have the larger reservoirs encountered very near the 

front of the sequence and the smaller reservoirs encountered very near the end. Indeed, the highest probability 

discovery sequence is the pure deterministic, descendingsize order of discovery. 

It is useful to think not only of incremental discoveries but also of cumulative discoveries. Cumulative discoveries include the larger reservoirs early in the sequence 

and the smaller reservoirs later in the sequence; therefore, 

cumulative discoveries increase faster at the beginning and 

more slowly at the end. Because larger fields have lower 

unit costs (that is, same fixed cost amortized over many 

more thousands of cubic feet of resources), the implicit 

cumulative supply curve for a play will be relatively flat 

and low at the beginning (representing the larger, lower 

cost reservoirs) and will slope steeply upward at the end 

(representing the smaller, higher cost reservoirs). To wit, 

the cumulative supply curve is determined initially by the 

costs of the large reservoirs and only later by the costs of 

the small reservoirs. Because of the asymmetry in surface 

area and size of large reservoirs, constructing a supply 

curve for the play by assuming strict, deterministic discovery in descending order of reservoir size is quite accurate 

and representative of how the play is most likely to be 

exploited. 

The supply curve for a play shows how cumulative 

reserve additions along the horizontal axis relate to cost 

per thousand cubic feet along the vertical axis. Given the 

asymmetry, the play-level supply curve must ultimately tilt 

upward rather strongly. This is not to say that the basinwide supply curve tilts upward strongly. On the contrary, 

there may be many plays in a given basin and the supply 

curve for each may tilt upward strongly, but the aggregate 

supply curve may not tilt up particularly strongly. 

The propensity of the play to be exploited in descending order of reservoir size (ascending order of reservoir 

cost) is entirely consistent with economically rational behavior of producers. Profit maximization motivates producers to find the large reservoirs first. No rational producer is 

looking for the small reservoirs. Rational producers work 

hard to identify and exploit the large reservoirs. Economic 

forces that motivate producers to look for the largest existing reservoirs in the play accelerate the asymmetry and 

buttress the argument that purely deterministic, ascending 

cost supply curves are surprisingly adequate. • 

STEP 5-ASSEMBLE HISTORICAL SCHEDULES 

OF DISCOVERIES, RESERVE ADDITIONS, 

AND PRODUCTION 

The next step is to assemble historical schedules of 

discoveries, reserve additions, and production for regions 

or plays for which such data are available. The most frequent approach to exploration, development, and production modeling is based on statistically inferring future 

finding rates from the entire history of past and present 

discoveries. Conventional statistical methods strive to fit 

future finding-rate trends to observed historical statistics 

and thereby to determine the most appropriate structural 

model. 

Unfortunately, conventional statistical methods have 

consistently understated future resource potential and exploration success. The reason is that conventional methods implicitly ignore technological innovation, field growth, and 

other phenomena that are apparent to industry observers but 

are not contained in historical data. Conventional statistical 

methods are inextricably wedded to the past-past prices, 
770 THE FUTURE OF ENERGY GASES 

past technologies, past methods, past regions, past expectations of the future, past regulations, and Government policy. 

There is no way to decouple conventional statistical extrapolation from the past. 

Fortunately, there are newly emerging statistical techniques that can overcome the conservative bias of conventional statistical methods. These new techniques, called 

Bayesian statistical techniques, systematically meld historical data with current judgment. (Conventional statistical 

methods do not allow any use of subjective judgment. Everything that is known or knowable is assumed to reside in 

the historical data. Bayesian methods are explained in detail in Nesbitt and Sparks (1990, 1992). In particular, 

Bayesian statistical methods allow one to introduce judgments related to technological innovation, field growth, 

geologic analogy, and other critical phenomena that simply 

do not exist within the historical data. Such phenomena 

would apparently be too new to reside in the historical 

data. Yet, such phenomena must be properly incorporated 

to make accurate projections of resource volumes, costs, 

and prices. There is risk of overlooking judgments known 

to contain valid information that is not available in historical data. Bayesian statistical methods allow such information to be incorporated. 

STEP 6-STATISTICAL ANALYSIS OF 

HISTORICAL SCHEDULES 

After assembling such historical information, it is necessary to-derive parameters of the_reservoir size sequence 

distribution developed in step 4. For simplicity, assume 

that the surface area is proportional to the size of the reservoir, that is, SA(B)=B. 

A play containing N reservoirs in which drilling has 

proceeded only to the point at which n<.N reservoirs have 

been discovered can be postulated. In other words, the 

play has been only partially exploited. Analogous to the 

previous development, expand the probability of observing 

the partial reservoir size sequence {S1, ... ,Sn} about all 

possible orders in which the first n reservoirs might be 

discovered 

=IdB. ···IdB. {S1, ... , SN' i!' ... , iN} {Sl' ... , S } 1n+ I 1

N n (17) 

= ~ {S!' ... ,Sn,i!, ... ,in} 

il' ... in 

The probability of observing the sequence S1, ... ,Sn is 

obtained by integrating out all yet to be made future discoveries in equation 14 according to the following 

expression 

{S1

, ... ,S ,i1

, ... ,i} =IdB .... IdB. n n 1n +I 1N 

n 

Il A.f(A.) (18) lk lk 

k =I =IdB. ...IdB. f(B. ) ... f(B.) 1

n+l 1NN-I N 1n+l 1N 

Il ~ Ai 

k=lm=k m 

It is useful to define the sum of the remaining undiscovered reservoirs 

00 

dSg (S) 

I n 

o Il [S + Sk + ... + Sn] 

k =I 

(19) 

S=B. + ... +B. 1

n +I 1

N 

and the probability density function over that sum to be 

g(S). Making this definition, equation 18 can be rewritten 

in the following form 

n 

(20) 

Substituting into equation 17, we can. write the following 

expression for the probability distribution over the partial 

sequence of discoveries {S1, ... ,Sn} 

n 

Il B.f(B.) 1

k 1k 

~ IdSg (S) ____.:.k_=_l ---

TI [s+ i 8 ;m] 

k=l m=k 

(21) 

There are Nx(N-1 )x(N-2)x ... x(N-n+ 1) possible orders of 

the first n discovery indexes. Therefore, the summation in 

equation 21 can be replaced by the expression Nli(N-n)! 

and the equation can be reorganized as follows 

N' n __ · - { Il SJ(Sk)} 

(N-n)! k=l 

00 

I n 

dSg (S) 

oIl [S+Sk+ ... +Sn] 

k =I 

(22) 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 771 

Equation 22 specifies the probability distribution over the 

size of the first n discoveries in a particular play. 

The most typical approach is to assume that the reservoir size distributionfO obeys a given analytical form (for 

example, exponential, gamma, or lognormal). It is desirable to assume that .fO is lognormal and thereby implicitly 

to assume that g(S) is the sum of (N-n) independent, lognormally distributed variables. The functional form of the 

lognormal distribution is 

1 • I {lnx-~.t) 2 

---exp - - -'------'--

ax!br, 2 a2 

(23) 

where !l and a are parameters of the distribution to be inferred from historical data. Under this assumption, the 

functions j(.) and g(.) in the foregoing formulations are explicitly a function of the parameters !land a: 

n 

r (N + t) 

r(N-n+l) 

dSf(S, !l, a) { TI s / c s k' ~.t. a) } I _n _ __:;____:___:__;__.:__ 

k=I 0 fl [S+Sk+ ... +Sn] 

k = 1 

(24) 

N and n are considered continuous variables, and their factorials can be written as gamma functions. In equation 24, 

the discovery sequence is a function of the parameters ll· 

a, and N of the model. 

For a given historical discovery sequence S1 *, ... , Sn *, 

equation 24 can be applied successively for discoveries 

1,2, ... ,n and n equations characterizing the n partial discovery sequences can be written. Doing so creates n equations in the three unknowns 1.1., a, and N and allows one to 

perform least squares, maximum likelihood, or Bayesian 

statistical estimation of those parameters. An additional 

constraint can be imposed requiring that the total aggregate quantity of resource in the play be equal to the exogenous volumetric estimate. Estimates derived therefrom 

allow one to ensure that the total inventory resident within 

all the reservoirs in the play is precisely equal (in an expected value sense) to' whatever volume is exogenously 

specified for each play. This links the cost and price estimates directly to the exogenous volumetric estimates. That 

is, the parameters ~.t. o, and N of the reservoir size distribution will be lockstep consistent with the exogenously 

estimated volume in place. 

Given the parameters ll· a, and N of the lognormal 

reservoir size distribution, probability calculus (Bayes 

Theorem) can be used to compute the size distribution of 

the reservoirs remaining in the play given the observed 

historical sequence of discoveries. In particular, to infer 

the probability distribution over future discovery sequences in the play given n historical discoveries, Bayes Theorem implies the following relation 

{Sn+ 1' ... , SN/ Sl' ... , Sn} 

{Sl' ... , Sn, Sn+ 1' ... , SN} 

{S1' ... ,Sn} 

(25) 

Substitution from equations 16 and 24 gives an expression 

for the size distribution over the reservoirs remaining in 

the play. It is this distribution {Sn+ 1, ... ,SN/S1, ... ,Sn} 

that must be used to conduct probabilistic simulation of 

future exploration and production in the play. This reservoir size distribution function is R { S n + 1, ... , S N}. The 

expected volume remaining in the play is the expected 

value of the probability distribution over the sum of the 

remaining reservoirs. 

STEP 7-PROBABILISTIC SIMULATION OF 

FUTURE EXPLORATION AND PRODUCTION 

To this point, subjective judgment or statistical extrapolation of past successes has been used to derive estimates 

of parameters for play-level reservoir size distributions. 

The sum of all play-level reservoir sizes adds up to the 

exogenously specified volumetric estimate for the region. 

In short, the reservoir-level deposition of the volumetric 

estimates has been fully specified. However, dry hole 

probabilities and reservoir depth distributions are two critical items yet to be considered. 

The probabilistic simulation approach begins with the 

probability distribution over remaining reservoir size R(.). 

To this distribution, a representation of dry hole probabilities and reservoir depth distributions must be added. 

To add dry hole probabilities to the model is rather 

straightforward. Only some "white" needs to be added between the reservoirs shown in figure 11. That is, some of the 

Figure 11. Areal distribution of reservoirs (shaded area) showing 

how dry-hole probabilities (white circles) can be incorporated 

into a supply-demand model of the natural-gas market. 
772 THE FUTURE OF ENERGY GASES 

darts thrown at figure 11 will not hit a reservoir at all. The 

areal distribution shown in figure 11 simulates that the probability of hitting a given reservoir is a function of the area of 

that reservoir relative to the areas of other reservoirs in the 

play plus the white areas between the reservoirs. The analogy of throwing darts is quite apt. 

How might dry hole probabilities be incorporated into 

the model? One simple way is to assume that the dry hole 

rate is constant and independent of the degree to which the 

play has been exploited. A simple assumption such as this 

allows one to simply derate the reservoirs in the play, assuming that it takes more than one hole drilled to actually 

encounter each reservoir. Such derating introduces a particular aggregate amount of white in figure 11. There are 

more complex methods for our purposes of incorporating 

dry hole rates; however, the usefulness of those more 

complex methods is questionable. The simple derating 

method seems to capture the most important cost issues 

related to dry holes. 

For each play, the reservoir size distribution must be 

estimated simultaneously with the depth distribution. The 

areal distribution must be complemented with a depth distribution that prescribes the depth of each of the reservoirs 

(fig. 12). Just as with the reservoir size distribution, there 

are two ways to estimate depth distributions. These are subjective extrapolation from geologically analogous regions 

and statistical extrapolation of depth distributions within 

the given horizon. The depth distribution combines with the 

areal (reservoir size) distribution to create a joint probability distribution over reservoir size and depth (fig. 12). This 

joint probability distribution over reservoir size and depth 

is the centerpiece of any simulation of the economics of 

exploration and development. 

Quite frequently, the depth distribution is handled by 

simple disaggregation-that is, plays of various depths are 

explicitly distinguished. When making such distinctions, 

individual plays can be considered uniform in depth. 

Therefore, each geographic region must be analyzed for 

-30,000' L------=-------------1 ~ = gas accumulation 

Figure 12. Areal and depth distribution of ga5 reservoirs. See 

text for discussion. 

both deep and shallow plays. A more complex alternative 

would be to include parameters in the probability distributions j{.) to account for depth differentials. For the remainder of this discussion, plays will be assumed uniform in 

depth. Also, it is assumed that deep plays and shallow 

plays are analyzed in parallel. 

The process of considering a single play is shown in 

figure 13. Exploratory drilling, in effect, throws darts at 

the reservoir size and depth distribution for that play, as 

shown in figure 11. For each exploratory hole, the probability of encountering. a reservoir of a given size is represented by the probability that a dart thrown at the areal 

distribution shown in figure 11 will strike a circle that denotes a reservoir of that size. The probability of a dry hole 

is implicit in how much white there is in the diagram relative to black (reservoirs) (fig. 11). 

The probability distribution over reservoir size (and 

depth) is the fundamental representation of the underlying 

geology. Beginning with this representation, what would 

happen if successive holes were drilled into the play must 

be simulated. Such simulation must take into account drilling and completion costs and all the other costs associated 

with drilling and bringing reservoirs . into production. 

Given this cost information, the probabilistic nature of exploration is represented by successively running a large 

number of drilling simulations that exploit the entire play 

in question and keep track of how much cost is expended 

and what reservoirs are encountered in what order. Each 

simulation will encounter the various reservoirs in various 

orders and result in various sequences of discoveries and 

various corresponding cost schedules. In effect, each simulation will generate an order of discovery and a corresponding cost schedule, which together constitute a supply 

curve in the economic sense (cost versus quantity of gas). 

By running a large number of drilling simulations, a 

histogram can be developed of sequences in which the remaining reservoirs, as described by the function R(.), are 

encountered and the corresponding costs incurred by the 

driller. In each sequence considered, each successive reservoir encountered adds a quantity of proved reserves (the 

quantity contained in the next reservoir encountered) along 

the horizontal axis at a cost that is characterized by the 

fixed cost, variable cost, and applicable taxes, finances, 

and regulations along the vertical axis. The situation for 

the 6th reservoir encountered in a hypothetical simulation 

is shown in figure 14. The vertical height is the cost and 

the horizontal width is the quantity of gas in each reservoir. Notice that the sequence is not cost ascending. 

The histogram of such supply curves (shown in 

fig. 15) constitutes in effect a probability distribution over 

the fundamental supply economics of the basin; it contains 

the mean supply curve, the variance about the mean, the 

skewness of the supply curves, and other higher order statistical properties. It is absolutely critical to consider that 

because of the asymmetry of the surface area function and 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 773 

Figure 13. The process of considering a single gas play for a supply-demand 

model. See text for discussion. 

MARGINAL 

COST 

($/Mel) 

II 

I 2 

6th Reservoir 

I I 

I I 

I I I 

I I I I 

3 :4: 5 :(,: 

Cumulative Met Additions 

Figure 14. Hypothetical simulation of adding an incremental reservoir (6th reservoir) to a supply-demand model. Marginal cost 

in dollars per thousand cubic feet. See text for discussion. 

MARGINAL 

COST 

($/Mel) 

Cumulative Mel Additions 

Figure 15. Histogram of reservoir sequence. 

of the quantities resident within the large reservoirs as 

compared to the small reservoirs that a vertical cross section of the histogram (the cost histogram for a given level 

of cumulative discoveries) is a probability density function 

that has a number of important properties. First, particularFrequency 

Minimum Mean Cost ($/Mel) 

Figure 16. Cross section of histogram at given cumulative level 

of natural-gas reserves. Cost in dollars per thousand cubic feet. 

ly at the low quantity end of the range, the probability 

distribution is heavily skewed toward the low end with a 

long, high tail. The cross sectional histogram at a given 

level of cumulative discoveries is shown in figure 16. 

Second, particularly at the low end of the quantity 

range, the mean, median, and mode of the probability distribution are all very near the minimum of the probability 

distribution. The aforementioned asymmetries guarantee it. 

Third, every curve consists of a reordering of the same 

reservoirs with the same costs and the same quantities. The 

different sequences 'merely reorder the gas reserves remaining in the basin; they neither add nor subtract gas 

from the resource base. Therefore, any supply curve other 

than the ascending cost supply curve must be higher in the 

near term and lower in the long term than the pure deterministic, ascending cost supply curve. 

The implications are profound. First, the nuances of 

probabilistic simulation might not be worth the trouble. The 

mean, median, and mode of a complex drilling simulation 

process will turn out to be rather close to the deterministic, 

ascending order of cost curve. Surely the difference between any probabilistic curve and the pure ascending cost 
774 THE FUTURE OF ENERGY GASES 

curve is literally dwarfed by the uncertainty in the underlying volumetric and cost estimates that characterize the resource base and the market as a whole. It seems silly to 

refine the details when the overall numbers are so uncertain. 

Second, because every probabilistic simulation scenario merely reorders a fixed, invariant inventory of reservoirs and Mcf's within those reservoirs, why trifle with 

such reordering? Assuredly, aggregate prices in the market 

do not depend on the specific sequence of reserves nearly 

as much as they depend on total reserves present within 

the region. The total quantity of gas resident within a region dictates the price to a greater degree than the particular cost structure of any reservoir in the region. 

The difference between a deterministic, ascending cost 

supply curve and any supply curve that might be comput-

• ed by probabilistic simulation is shown in figure 17. The 

simulated supply curve is higher initially and lower in the 

long run. Note that the two curves must cross each other. 

The probabilistic curve must be higher initially and lower 

MARGINAL 

COST 

($/Mel) 

/ 

I 

/Probabilistic 

1 Supply Curve 

I 

Cumulative Rese!Ve Additions 

Figure 17. Probabilistic versus pure cost-ascending supply 

curves. Marginal cost in dollars per thousand cubic feet. 

MARGINAL 

COST 

($/Mel) 

I 

I 

I 

I 

Cumulative Reserve Additions 

Figure 18. Implications of probabilistic versus pure cost-ascending supply curves for a supply-demand model of a natural-gas 

market. Probabilistic simulation is required only if the two crossing points are far apart. See text for discussion. 

at the end than the pure ascending order of cost supply 

curve. Whether probabilistic simulation is required depends on whether it affects the supply-demand balance. It 

only affects the supply-demand balance if the two crossing 

points in figure 18 are very different. If not, the complexity is not worthwhile. In my experience, the difference in 

figure 18 is rather small relative to the other uncertainties 

that beset resource-base estimation. 

Third, because of the observed asymmetry, the supply 

curves shown in figure 18 cannot possibly be very different. Because the curves are based on the same inventory 

and the same cost structure, they must cross. It would be 

almost impossible to argue (as some have) that an economic model without probabilistic simulation is intrinsically unable to analyze gas markets. Quite the contrary, a 

model that is based on full-blown probabilistic simulation 

may be overly complicated, inefficient, inflexible, and uninterpretable. It probably overanalyzes the data, Furthermore, such models have not proven the ability to calculate 

supply-demand curve equilibria; they are supply-only 

models. The EEA Hydrocarbon model is a particularly relevant example here. As I see it, the model is incapable of 

calculating price-quantity equilibrium. It concentrates instead on the less important part of the problem-probabilistic simulation-and ignores the important part of the 

problem-the fact that prices and volumes depend on aggregate quantities largely independent of cost structure. 

Models such as the Hydrocarbon model are driven by rapidly deteriorating finding equations and tend to forecast 

skyrocketing prices. Such conclusions depend inherently 

on a limited ability to model markets and a dogged insistence on probabilistic simulation from fixed, immutable, 

and often overly conservative resource-base estimates. 

The series of steps required to generate probabilistic 

simulations of the exploration, development, and production processes throughout North America and the world is 

shown in figure 13. The end product of this step would be 

the mean supply curve for each producing region in North 

America or the world, or, in other words, the mean of the 

histogram of the supply curves generated by the exploration simulation. The mean supply curve generated by the 

probabilistic simulation process is the best of all possible 

inputs to a deterministic (nonprobabilistic) model of North 

American and (or) world gas supply, transportation, and 

demand. However, the mean supply curve is probably not 

much better than the minimum (the deterministic, purely 

cost-ascending curve), the median, the mode, or any other 

curve sufficiently near the minimum. 

STEP 8-DETERMINISTIC SIMULATION OF 

FUTURE EXPLORATION AND DEVELOPMENT 

This section summarizes how to actually calculate regional supply curves throughout North America and the 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 775 

world. Recognizing that the large reservoirs will be discovered with much higher probability than the small reservoirs, the supply curve would be generated by simply 

exploiting the reservoirs in ascending order of presentvalue life cycle cost; this takes into account both reservoir 

size and depth, and it will be a very good representation of 

the fundamental supply economics of. the basin. Rather 

than running the complex probabilistic simulation process, 

an approximate method that exploits the strong affinity of 

the exploration process for large reservoirs in favor of 

small reservoirs is to simply (1) take N samples from the 

reservoir size distribution derived in step 6, (2) reorder 

them in ascending order of cost, (3) create a cost-ascending supply curve, (4) repeat until a large number of costascending curves are generated, and (5) use the mean of 

the large number of cost-ascending curves as the supply 

curve for the region. In effect, for each simulation cycle, 

the reservoirs will be discovered in precisely the order of 

ascending present-value life cycle cost and furthermore 

that drilling costs will be escalated (derated) to account for 

dry holes. The result on each pass through the simulation 

will be to stack the reservoirs in ascending order of 

present-value life cycle cost, inflate the life cycle cost to 

account for the average number of dry holes, and thereby 

form a deterministic ascending cost supply curve. The 

probabilistic nature of the problem emanates from sampling from the pool size distribution R(.). 

The ascending cost supply curve will be a good 

approximation to the mean of the more complex probabilistic simulation process. However, the deterministic approach will be slightly optimistic at the beginning and 

slightly pessimistic at the end of the simulation period 

relative to the fully probabilistic simulation (figs. 17, 18) 

It will be optimistic at the beginning because it will represent exploiting the low cost part of the resource base in 

the early years and leaving none for the later years. By 

contrast, the probabilistic procedure will, through random 

luck, exploit some of the higher cost deposits quite by 

accident in the early years and will thereby leave some 

lower cost deposits in the ground to be exploited in the 

later years. 

Some analysts have stated that supply cannot be represented using supply curves. They argue that one mu~t use 

detailed probabilistic simulation to represent the stochastic 

nature of encountering reservoirs. The only conceivable 

situation in which a particular discovery scenario departs 

from pure ascending order of cost discovery is when there 

is a very long sequence of small reservoir discoveries before a large reservoir is discovered. The reason one needs 

a long sequence of small reservoir discoveries is that a 

short sequence will not add significant volume; a short sequence adds no appreciable volume. Keep in mind, a long 

sequence of small reservoirs occurring before a single 

large reservoir has a negligibly low probability given the 

demonstrable exploration asymmetries. 

PRODUCER BEHAVIOR GIVEN REGIONAL 

SUPPLY CURVES 

The fundamental output of the supply simulation work 

is called long-run marginal cost curve. The long-run marginal cost curve plots cumulative future additions to 

proved reserves along the horizontal axis against present 

value of fixed plus variable cost (marginal cost) along the 

vertical axis. In the most fundamental sense, this type of 

supply curve that characterizes the geology and economics 

of a given region or basin. A long-run marginal cost curve 

is shown in figure 19. 

The way the NARG model represents producer behavior is discussed in detail in Nesbitt and others (1988). In 

particular, the report discusses how producers can be expected to behave in a basin characterized by a long-run 

marginal cost curve of the form in figure 19. 

MARGINAL 

COST 

($/Mel) 

Cumulative Future Additions to Proved Reserves (Tel) 

Figure 19. Long-run marginal cost curve, which is the fundamental output of a supply-demand model of a natural-gas market. 

Marginal cost in dollars per thousand cubic feet. Tcf, trillion 

cubic feet. 

MODELING DEMAND 

BUILDING REGIONAL GAS-DEMAND CURVES 

FROM FUNDAMENTAL INFORMATION 

Without reliable demand curves, supply-demand crossing points can be rather meaningless. To properly characterize gas demand, it is important to distinguish at least 

two types of consumers in gas markets. The first type of 

consumer is the core customer. Core customers are collectively referred to as the core market. The core market consists of captive gas customers, customers for whom 

options other than gas are not particularly viable. The core 

market shows relatively price insensitive (inelastic) demand. Residential, commercial, and industrial customers 

highly committed to gas would fall into this category. 
776 THE FUTURE OF ENERGY GASES 

CORE GAS 

DISTRIBUTION 

OIL 

I 

Figure 20. Network representation of demand for natural gas. The network form 

allows accurate depiction of core and noncore demand. 

The remainder of the market, termed the noncore market, is that segment of the market possessed of an immediate alternative such as fuel oil. As long as gas price 

remains below that of the alternative, noncore gas demand 

will remain relatively firm. If gas price rises to or above 

the price of the alternative, noncore gas demand will 

switch away from gas toward the alternative. It is important to recognize that the noncore market is much more 

disparate and disaggregated than a simplified oil-gas substitutable sector. This discussion is limited to a simple gasoil substitution. 

This simple core-noncore characterization of gas demand can be represented in network form (fig. 20). In the 

figure, energy is assumed to flow along the links through 

the processes from bottom to top. The figure depicts two 

demand "tombstones," one for core demand and one for 

noncore demand. Each tombstone contains a demand 

curve (a price-quantity-time relation that specifies the 

quantity of gas or gas-equivalent that will be consumed at 

every possible price level today and into the future). Notice in the diagram that noncore demand can be satisfied 

either by gas or by the substitute. The circle at the upper 

right represents gas-oil competition, the winner flowing 

upward to satisfy the market. As shown in the figure, core 

demand can be satisfied only by gas. 

What is the general shape of the wholesale gas demand 

curve? What does the demand curve facing the upstream 

transporters and producers look like? What is its general 

shape and slope? The simplest way to answer this question 

is to offer a caricature of the demand curve and thereafter 

refine the caricature to a more realistic form. The core market demand and noncore market demand are placed along 

the horizontal (quantity) axis as shown in figure 21. The 

price of the oil substitute is placed along the vertical 

(price) axis as shown in the figure. Consider a very high 

PRICE 

DEMAND 

CURVE 

OIL PRICE -----------1--------, 

Core Market Noncore Market 

I 

I 

QUANTITY 

Figure 21. Caricature of wholesale demand curve for natural 

gas. See text for discussion. 

price of gas, one well in excess of the oil price. At this 

high price, the core (committed) market will be obliged to 

buy gas, but the noncore (substitutable) market will avoid 

gas in favor of oil. At high gas price, the gas market is a 

"core-only" market. As the price of gas drops from very 

high levels, the core market remains saturated and the noncore market remains entirely committed to oil until the 

price of gas drops to the price of oil. As the price of gas 

drops just below the price of oil, the entire noncore 

(switchable) market will switch en masse from oil to gas. 

As this occurs, the entire noncore market saturates with 

gas, eliminating oil altogether, and gas demand moves horizontally to the right until it includes all core plus noncore 

users. Once the noncore market is completely saturated by 

gas, even if gas prices fall further, there is no more noncore market to capture. 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 777 

The stairstep shape of the gas demand curve in figure 21 is a useful caricature of the shape of the wholesale 

gas-demand curve. If gas price is higher than oil price, gas 

will command only the core market. If gas price is lower 

than oil price, gas will command both the core and noncore market. If gas price is equal to. oil price, gas will 

command the core market and gas and oil will split the 

noncore market. The reality, however, is a slight extension 

of the stairstep demand curve in figure 21. In reality, core 

gas demand is somewhat elastic, and noncore gas demand 

is highly segmented with each segment facing a slightly 

different oil substitute price. Therefore, in reality, the demand graph in figure 22 should be rounded off as shown 

in figure 21. The demand curve in figure 22, very characteristic of gas demand, has an inelastic portion at high gas 

price (the "neck"), a very elastic "shoulder" section where 

gas prices are close to oil prices, and an inelastic "arm" 

portion when gas price lies below oil price. The demand 

curve has the distinctive "neck-shoulder-arm" pattern in 

figure 22. Market clearing prices and volumes are very 

strongly dependent on this distinctively shaped demand 

curve. 

Every demand region in the world must be characterized by a demand curve with this distinctive shape. The 

specific parameters of the regional demand curves will, of 

course, be quite different depending on economic development, pipeline infrastructure serving the region, economic 

growth, electric generation capacity, environmental concerns, industrial mix, contiguous supply, and a host of 

other considerations. 

There are several features of this representation that 

must be noted here. First, it is interesting to note that the 

width of the shoulder in figure 22 has diminished during 

the past two decades as the industrial sector of the United 

States and Canada has been moved to other countries or 

shrunk as industries have died out. Furthermore, environmental restrictions and (or) cleanup costs restricting oil 

DEMAND 

PRICE CURVE 

OIL PRICE 

Core Market Noncore Market 

QUANTITY 

Figure 22. Neck-shoulder-ann representation of demand curve 

for natural gas. See text for discussion. 

consumption have served to make the shoulder narrower 

(less oil capacity) and higher (higher cleanup cost for oil). 

What used to be a relatively broad shoulder in our formerly industrialized economy has now bec.ome a much narrower shoulder in our more environmentally conscious 

service economy. Such narrowing has vital consequences 

for the relation between the market clearing price of gas 

and oil. The narrowing of the shoulder, owing to emigration as well as environmental policy, has led to a much 

weaker degree of coupling between oil and gas price than 

has been true historically. 

Second, the width and height of the shoulder is determined to a significant degree by applicable environmental 

policy. As an example, suppose a C02 tax were to be imposed. Certainly oil price would be more penalized than 

gas price, and the shoulder of the curve would increase 

disproportionately to the rest of the curve. Suppose lowquality heavy oil were banned from certain applications. 

The shoulder would be raised and narrowed. It would be 

raised because heavy oil users would have to use higher 

priced light oil (if they used oil at all). It would be narrowed because there would be fewer prospective oil users 

in aggregate. Suppose finally that electric generation facilities committed to gas entered the mix. Presumably combined cycle electric generation facilities will be core 

market facilities. In the extreme, if environmental restrictions were sufficiently severe, there might be no noncore 

shoulder at all. There would be no alternative other than 

natural gas, electricity, and renewables. 

Third, the simple, aggregated representation of the 

noncore market is highly simplified. The noncore market 

is not as simple as gas versus oil competition. On the contrary, there are many industries, many electric generation 

facilities, and many locations and market segments. Competition between oil and another fuel form is highly segment-specific. How to generalize the simple noncore 

model discussed here to a more disaggregated situation is 

discussed at the end of this section. 

Fourth, there is not a single neck-shoulder-arm configuration that applies in every demand region. On the contrary, 

the neck-shoulder-arm configuration must be specifically 

customized to each region to properly characterize the nature 

of demand in that region. While the demand curve in every 

demand region in the world can be argued to have the same 

generic shape (shown in fig. 22), the specific shape, width, 

height, and location will differ markedly among regions. 

Every demand region in the United States, Canada, 

and the rest of the world must contain the network structure in figure 20 and therefore the demand curve structure 

in figure 22. After making such representation, every demand region in the model is able to represent demand 

stimulation and (or) suppression at different prices as well 

as substitution at the exogenously given price of the oil 

substitute. Furthermore, the specific configuration of the 

core and noncore markets and the assumed height of the 
778 THE FUTURE OF ENERGY GASES 

oil substitution shoulder can be used to characterize a 

broad range of environmental ai;Id economic considerations that pertain in various regions. 

The data needed to structure the demand network in 

figure 20 for each of the demand regions are rather 

straightforward. The first two items are a demand curve 

(price versus quantity versus time) for total core market 

use, and a demand curve (price versus quantity versus 

time) for noncore market use. Noncore market use includes all demand that can be satisfied by either gas or oil 

regardless of which source is actually satisfying that demand today. An estimate of noncore distribution cost, 

which is important to properly represent burner tip gas 

prices relative to oil prices is needed. A projected time 

schedule of the price of oil against which gas must compete is also needed. One can use an exogenously deter-. 

mined prediction of oil price, or one can use a world oil 

model. Finally, lag and price-sensitivity parameters that 

simulate adjustments in capital stock necessary for gas-oil 

substitution are needed. The DFI world oil model is used 

to make oil price forecasts. Extensive documentation is 

available from the author. 

The core and noncore gas demand curves (the first 

two items) can be inferred from historical statistical information. Alternatively, they can be calibrated to a pricequantity demand forecast from an exogenous source as 

summarized in figure 23. A price-quantity forecast from 

another source (labeled "reference point" in the figure) can 

be plotted on a price-quantity axis as shown. Given this 

exogenous forecast, assume that the demand curve passes 

through this reference point. Given that the demand curve 

passes through the reference point, one then specifies 

short- and long-run elasticities to characterize the slopes of 

the curves about the reference point. This procedure is 

quite convenient if one wishes to calibrate the demand 

side of the model to another forecast such as the European 

Community (EC) country demand forecasts in Europe, the 

Gas Research Institute (GRI) baseline forecast in the UnitPrice 

Reference 

Price 

~ Reference Point 

Reference 

Quantity 

Demand 

Figure 23. Calibration of core and noncore natural-gas demand 

curves to exogenous demand forecast. See text for discussion. 

ed States, or the National Energy Board (NEB) of Canada 

provincial forecast for Canada. 

WHAT DOES DEMAND IMPLY ABOUT THE 

CROSSING POINT? 

The neck-shoulder-arm configuration of the gas demand curves shown in figure 24 is indicative of the solution (or crossing point) of the supply and demand curves 

for any region. There are only three possible locations at 

which the supply curve-demand curve crossing point can 

occur-the shoulder, the arm, or the neck. 

Case 1: The Shoulder Crossing-This price parity 

case is shown in figure 24A. The supply curve cuts 

through the demand curve along the horizontal shoulder 

portion of the demand curve. When the supply curve cuts 

across the demand curve along the horizontal shoulder, the 

price of gas is exactly equal to the price of oil. Oil and gas 

are at price parity on a Btu basis. 

This situation occurred historically in North America 

for a very good reason. As the interstate pipeline system 

expanded to serve residential and commercial customers, 

any excess was sold to industrial and electric generation 

customers. Electric generation by gas was discouraged, so 

the customer of last resort tended to be an oil-substitutable 

industrial customer. Furthermore, during the primary expansion, natural-gas prices were regulated at the wellhead 

at an extremely low price. The price was so low that any 

excess not sold to residential or commercial customers 

could be easily disposed of to an industrial customer. As 

such expansion of the pipeline system occurred, the noncore market was split between gas and oil. Gas commanded the market to which it had access, and oil settled for 

the rest. Oil and gas split the noncore market. The marginal source of energy was always oil. 

It is useful to summarize the key insights from the 

shoulder crossing solution. These are the market clearing 

price of gas is equal to the price of oil and that some noncore customers use gas, whereas some use the substitute. 

This shoulder crossing scenario can occur in a given demand region in a moderate oil price case. In other words, 

a case in which the oil shoulder is neither excessively high 

or excessively low relative to gas supply. 

Case 2: The Arm Crossing-In this situation, which 

clearly characterizes most of North America today, the 

gas-supply curve intersects the demand curve below the 

shoulder along the arm (fig. 248). It is a world of abundant gas supply, perhaps a "gas bubble." The market clearing price of gas has absolutely no connection with the 

price of oil except that it lies below the price of oil. First, 

gas supplies are "abundant" and prices are soft. Secondly, 

noncore users are attracted to gas, and gas can and will 

win any price war against oil. Third, a noncore gas user 

will be the marginal user. That noncore gas user will de-
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST, AND PRICE 779 

PRICE 

OIL PRICE 

A 

DEMAND 

PRICE CURVE 

OIL PRICE 

p* 

B q* QUANTITY 

PRICE 

p* 

OIL PRICE 

Core Market Noncore Market 

c q* QUANTITY 

Figure 24. Neck-shoulder-arm configuration of gas-demand 

curves. A, Shoulder crossing; B, Arm crossing; C, Neck crossing. 

tennine the price of all gas to every user. Fourth, both 

core and noncore gas users will buy gas at a discount relative to oil. If gas supply is truly abundant, the price can be 

well below the price of oil. If gas supply is not excessively abundant, the price can be slightly below the price of 

oil. Fifth, there is absolutely no connection between the 

price of oil and the price of gas except that the price of 

gas is lower. 

Case 2 will tend to occur if oil pries are high, that is, 

if the shoulder of the demand curve is high, or if gas demand is low. 

Case 3: The Neck Crossing-In this case, the gas-supply curve intersects the demand curve above the shoulder, 

on the neck (fig. 24C). The market clearing price of gas 

exceeds the price of oil. Indeed, there is absolutely no relation between the price of gas and the price of oil except 

that the price of gas must be higher than the price of oil. 

Case 3 will occur if oil prices are low (low oil prices 

mean that the shoulder of the demand curve is very low) 

or if gas demand is very high relative to supply. To summarize this neck crossing case: Gas supplies are tight in 

any demand region with a neck crossing. For this scenario, 

noncore users are driven to the oil substitute, and core 

users are the marginal gas users. Marginal gas users set 

the price of gas to all customers. There is absolutely no 

relation between the price of gas and the price of oil except that the price of gas is higher. Core users will be 

obliged to buy gas at a premium over oil. 

The foregoing three cases are the only three possibilities that can occur-nothing else can happen. It is absolutely critical to emphasize that it is possible that entirely 

different cases can (and will) hold in different demand regions at the same time. For example, case I (gas-oil price 

parity) can be occurring in New England at the same time 

that case 2 (abundant gas supply) is occurring in the Gulf 

of Mexico. In fact, this is the normal situation except in 

the summer. Transportation costs and restricted capacities 

to New England constrain supply and cause it to cut 

across the New England demand curve along the shoulder. 

At the same time, excess supply in the Gulf of Mexico 

and universal access to local markets cause supply to cut 

across the Gulf Coast demand curve on the arm with consequent gas prices well below oil price equivalent. 

Throughout North America and the world, the particular 

case for each demand region depends on the specific shape 

of the demand curve in that region and the contiguous resource regions that supply it. 

With these preliminaries, what can be said of the supply-demand equilibrium in a large, interconnected economic model? The first and perhaps most conspicuous 

observation is that in general the market clearing price of 

gas will not be equal to the price of oil (figure 24A-C). 

Gas and oil prices will not be at parity. There is no intrinsic force that tends to equate oil and gas prices. On the 

contrary, only in the specific situation in which the supply 

curve intersects the demand curve through the horizontal 

shoulder of the demand curve as shown in figure 24A, will 

the price of gas be equal to the price of oil. As already 

noted, the shoulder has narrowed in North America substantially over the past several decades. This renders it decreasingly likely that case I (the shoulder crossing) will 

hold in any given demand region for any given period of 

time. 
780 THE FUTURE OF ENERGY GASES 

Parenthetically, it is absolutely certain that today in 

early 1993 we live in a case 2 (arm crossing) world. Why? 

Recall when the Iraq war first started that oil price doubled almost instantly. The horizontal shoulder (fig. 24B) 

shot up by a factor of two almost instantly as oil price 

doubled. Yet, the price of gas did not move one iota! 

Clearly, both before and after the oil price escalation, the 

market was clearing on the arm; We lived in a case 2 

world. The oil price shoulder increased, yet the crossing 

point did not change. The market continued to clear on the 

arm, just as the case 2 supply-demand paradigm would 

predict. 

The three supply-demand cases (neck, shoulder, and 

arm) provide a useful paradigm for establishing and interpreting alternative supply-demand cases, that is, different 

runs of a model. Different supply-demand scenarios will 

generally correspond to one of the three cases. For example, a base case might correspond to case 2 (gas supply 

intersects demand on the arm so that gas price is below oil 

price). However, a low resource scenario, all else equal, 

might shift the supply curve upward and to the left so that 

case I rather than case 2 holds. In this situation, gas supply would intersect along the shoulder. Relative changes in 

prices and quantities could be easily explained by comparing the geometries of the case 1 and case 2 supply-demand 

curve crossings. 

Notwithstanding the particular scenarios being considered, comparison of high versus low gas-resource scenarios (and in fact almost any pair of scenarios involving 

different supply, transportation, or demand assumptions) 

leads to a critical conclusion: the market clearing price of 

gas will be different between different demand, supply, and 

oil-price scenarios. If the price of gas remains constant 

between two scenarios, the model that generated them is 

probably wrong. The approach presented here will not 

allow the price of gas to remain constant across two scenarios unless those two scenarios are so trivially different 

that the supply-demand curve geometries are virtually 

identical. 

This approach recognizes that prices and volumes 

must be fundamentally different across different supplydemand curve scenarios and this has profound ramifications. 

First, the customary assumption of oil/gas price parity at 

the burner tip is wrong. To assume such parity is to get 

both the wrong burner tip market clearing price and quantity consumed. The fact that gas price will have to differ 

between scenarios means that in at least one of those scenarios, gas price will have to be different from oil price. 

Second, the customary practice of equating gas wellhead prices to oil price "netbacks" from the burner tip 

through the pipeline system is wrong. To calculate oil 

price netbacks is to get both the wrong wellhead market 

clearing price and quantity produced. 

Third, oil and gas prices are likely to move further 

away from parity as the noncore market decreases relative 

to the core market. Conversely, the larger the noncore 

market, the nearer to parity oil and gas prices are likely to 

become. 

The traditional (and increasingly incorrect) procedure 

of netting back burner tip-equivalent oil prices to the wellhead originated in the days when the United States had a 

large industrial sector and a large noncore market relative 

to the core market. Although not technically correct even 

in those days, oil price netbacks were serendipitous. There 

existed a broad noncore shoulder in the economy, and 

pipeline capacity additions were tightly controlled. These 

forces virtually ensured that case I would apply. However, 

now that the industrial sector has declined in size relative 

to the core sectors, and environmental concerns have risen 

to the fore, case 2 or case 3 is much more likely to pertain 

today. Oil price netbacks are inevitably destined to be 

wrong today and in the future. 

There is an alternative to assuming oil-gas price parity 

at the burner tip and calculating netbacks to the wellhead. 

It is to enumerate all present and potential future supply 

regions using supply curves, all present and potential future demand regions using demand curves with correctly 

sized noncore shoulders, and all present and potential future transportation links connecting supply regions with 

demand regions. Thereafter, the prices and quantities at 

which all supply and demand curves simultaneously intersect can be explicitly computed. 

A MORE SEGMENTED REPRESENTATION OF 

GAS DEMAND 

The logic leading to the simple demand curve in figure 22 is appealing, yet it is assuredly aggregated and approximate. Indeed, the noncore gas market is more highly 

segmented than shown in that figure. Rather than a single 

aggregate market for gas and (or) oil, there are many disparate segments that make up the noncore gas/oil market. 

Each segment has a specific substitute for gas. The substitute for gas can be different in different segments or in 

different regions. 

How can the true diversity of the noncore market be 

represented? To illustrate, consider the expanded diagram 

in figure 25. (Keep in mind, energy is assumed to flow 

from bottom to top in the network diagrams). Figure 25 

depicts the core market (captive gas) and disaggregates the 

noncore market into two categories (industrial and electric) and substitution possibilities into two categories 

(heavy number 6 oil and light number 2 oil). The upper 

right portion of the network shows four noncore demand 

blocks: (1) number 6 substitutable demand in the electric 

segment (for example, boilers); (2) number 6 substitutable 

demand in the industrial segment (for example, boilers and 

other low quality heaters); (3) number 2 substitutable demand in the electric segment (for example, combustion 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 781 

Figure 25. Segmented network representation of natural-gas demand, which 

shows the true diversity of noncore demand. Energy flows from bottom to top. 

DIST., distribution; Subst., substitutable; Ind., industrial; UEG, Utility Electric 

Generation. See text for discussion. 

turbines); and (4) number 2 substitutable demand in the 

industrial segment (for example, combustion turbines and 

clean process heat demand). Each of these four noncore 

demand segments (which in aggregate total up to the noncore market) is characterized by a demand curve. That is, 

each demand block contains a price-quantity-time demand 

function characterizing a single segment. 

A fifth segment, coal-substitutable demand in the electric segment (for example, base load coal plants that could 

be repowered with gas), could be added. This fifth segment is prospectively important in certain foreign countries but probably not in North America, so it will be 

ignored here for convenience. The four circles directly beneath each of the noncore demand blocks in figure 25 represent gas versus liquid competition in each segment. For 

example, the circle labeled "#2 industrial" represents competition between gas and number 2 distillate to provide energy service to this segment of the market. 

The triangles on the links entering each of the circles 

represent the distribution cost of the corresponding fuel type 

to the indicated segment of the market. Notice there are four 

segment-specific, noncore gas distribution costs activities in 

figure 25. They are very important because they represent 

the cost markup from wholesale gas to the point of competition in the various segments against oil. Oil must be refined 

and distributed to the burner tip. The four triangles emanating from the crude-oil circle represent the refining, marketing, and distribution costs necessary to convert from crude 

oil to delivered refined product. These oil and gas distribution costs must be estimated to build such a model. 

The objective of the more complex multisegmented 

structure in figure 25 is to construct a more accurate and 

reliable demand curve for wholesale gas in each demand 

PRICE 

#2 PRICE --- ~- ~------ -:-------

I 

#6 PRICE ------:-----~-~~----;,.: I I 

Core 1 UEG 1 lnd 1 UEG I I 

QUANTITY 

Figure 26. Segmented gas-demand curve. 

region. Such a demand curve takes a fuller account of oil for 

gas substitution possibilities and ensures that the price differentials between different oil products in different segments are consistent both relative to one another and relative 

to crude price. The resulting demand curve is a "multishoulder" curve of the form shown in figure 26. Notice how. the 

segments are arrayed from left to right in decreasing order of 

willingness to pay for gas. Notice further how the prices of 

increasingly high quality of refined product are arrayed on 

the vertical axis. The various product shoulders are clearly 

evident in the diagram. By incorporating a demand curve at 

the level of detail shown in figure 26 into the model, the 

exact form of oil or gas that is the marginal source of energy 

in any region (the "last in/first out" source) and what its cost 

is can be known with certainty. After all, it is the cost of the 
782 THE FUTURE OF ENERGY GASES 

marginal source that sets the price of gas in the region and 

sets the netback prices of gas at the wellhead of every prospective supply region for that demand region. 

To conclude, it is possible to build an even more elaborate representation of end use. DFI has done so many times 

using networks of process models. The model disaggregates 

demand into large homes and small homes. It also disaggregates final demand into space heating, air conditioning, combination space heating plus air conditioning, water heating, 

cooking, drying, and electric only. For each of these final 

demand categories, the model considers the multiplicity of 

technologies competing to satisfy customers. For space heating, the model considers conventional gas furnace, advanced 

gas furnace, recuperative gas furnace, gas heat pipes, electric 

resistance furnace, various gas heat pumps, and various electric heat pumps. Depending upon the market share achieved 

by each of the competing technologies, the market divides 

between gas, electricity, oil, and the other fuel forms entering 

the bottom of the diagram. By running this rather complex 

model of residential end use, the appropriate model of residential gas demand is built. By building similar models of 

commercial, industrial, electric,and transportation demand, 

a detailed, process-specific model of gas and other fuel demand is built. This is perhaps the only reliable way to generalize the gas-demand curve shown in figures 20 and 24C. 

The SRI-Gulf model, the LEAP model, and the GRI 

integrated multifuel models all contain a great deal of demand-side detail. DFI's work with those models demonstrated their intrinsic accuracy, but it also proved that the 

more aggregated, less structurally oriented neck-shoulderarm representation in figure 22 is more than sufficient to 

thoroughly understand North American and world gas 

markets. That is why DFI has adopted the simpler versions 

for its gas models; we opted for more regional disaggregation rather than more process disaggregation. 

Inside each of the demand regions in the United 

States, North America, and the world, DFI's approach is 

structured to take account of key demand-side phenomena 

including demand stimulation at lower prices, demand 

suppression at higher prices, interfuel substitution between 

oil and gas, and demand by segment as a function of economic growth, industrial productivity, and other indexes. 

The demand modeling approach does so in very simple 

fashion by constructing the demand representation with 

the level of detail shown in figure 9. Such detail is a fundamental constituent of any reliable supply-demand model 

of natural gas-one that does not focus only on the volumetric si'de of the equation without sufficient consideration 

for the price and cost side. 

MODELING TRANSPORTATION 

Implicit in the examples is the assumption that the gas 

transportation infrastructure has been properly represented. 

The degree of pipeline detail required to build a reliable 

model must be consistent with the degree of supply basin 

detail and demand region subdivisions everywhere else in 

the model. One could enumerate and distinguish every individual pipeline and LNG transportation link in the United States and the world, but the value (relative to the cost) 

would be highly questionable. Instead, we used commonalities among supply regions, pipelines and LNG routes, 

and demand regions that would allow prudent aggregation 

at a level sufficient to answer the critical volume, price, 

and valuation questions. Rather than represent individual 

nameplate pipelines, pipeline corridors from the ~upply regions selected to the demand regions selected are used. 

Those transportation corridors are systematically defined 

according to the location of supply basins and demand regions and by the configuration of the United States, Canadian, and world pipeline and LNG transportation systems 

that exist today. 

Embracing the notion of pipeline and LNG corridors, 

the network of existing pipelines for North America is 

shown in figure 27. Each of the existing pipeline corridors 

begins in a given supply region, extends perhaps through 

intermediate supply and demand regions, and terminates in 

a demapd region. The network of existing pipeline corridors interconnects all currently producing regions with all 

currently consuming regions. It is no accident that the pipelines connect known supply basins with known demand 

regions. Why would anyone build them any other way? 

The evolution of the natural-gas system over the next 

50 years or more cannot be represented by merely considering existing pipeline and LNG corridors. It is necessary to 

enumerate all prospective future pipelines that might be 

built in the next 50 years. These prospective future pipelines 

connect new producing regions or subregions with various 

demand regions, and they connect Canada and Mexico with 

the United States. Figure 27 enumerates the pipelines that 

might be built within the time horizon of the model. Prospective pipelines are represented by broken lines whereas 

existing pipelines are represented by solid lines. 

The prospective new pipelines shown in figure 27 are 

just that-prospective. They will be built only if they become economic. They will be built only if supplies at the 

upstream end, appropriately marked up to account for the 

cost of the new pipelines, constitute the most competitive 

source at the downstream end. There are nuances of capacity expansion (for example, looping or additional compression of existing capacity). In the model, looping is 

considered an option for all existing capacity in figure 27 

as well as for the existing links of the new corridors in 

figure 27. 

Because the linkage between Canada and the United 

States is so important, figure 27 shows the pipelines in 

Canada that directly or indirectly terminate in the lower 48 

United States. These Canadian pipelines, should they be 

built, provide a route for hundreds of Tcf of Canadian gas 
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 783 

·.· ... OFF SHORE ,·.e. ATLANTIC 

LNG 

• EAST ... : CANADA 

Figure 27. Existing and prospective North American natural-gas pipeline network used for the North American regional gas supply-demand model. Also shown are Canadian export routes to the United States. See 

figure 9 for explanation of abbreviations and symbols. 

into United states markets should that gas become economically competitive. As that gas enters lower 48 United 

States markets, it puts downward pressure on price, upward pressure on aggregate volumes, upward pressure on 

Canadian volumes, and downward pressure on volumes in 

the lower 48 States. 

In reviewing the Canadian export diagram shown in 

figure 27, note the prospective routes from North Alaska 

through Alberta and ultimately to the United States and 

from northern Canada (MacKenzie and Beaufort Sea) 

through Alberta and ultimately to the United States. The 

former pipeline represents the upstream leg of the ANGTS 

system whereas the latter pipeline represents the pipeline 

that will have to be built in order to exploit Canadian Arctic gas (MacKenzie Delta pipeline). Competition between 

these two pipelines will in part determine the competitive 

viability of the various Arctic supply regions and of the 

pipeline projects proposed to serve them. 

Figure 27 integrates the existing pipelines, the prospective pipelines, and the Canadian export pipelines. The geographic structure of the pipeline corridors represented in the 

NARG model is shown in this figure. The model is very 

detailed and quite comprehensive, even though it does not 

explicitly distinguish all "nameplate" pipeline companies. 

Given the geographic structure of the pipeline system 

represented in the model, how can one ensure that the 

model is not violating known pipeline or pipeline corridor 

constraints? To provide a satisfactory answer to this question, DFI contracted with Benjamin Schlessinger and Associates (BSA) of Bethesda, Maryland to assemble capacity 

constraints on all existing North American pipelines, aggregate them into appropriate corridor constraints, and provide 

them to the model. For the world, DFI has contracted with 

the Canadian Energy Research Institute (CERI) and its 

world gas trade program sponsors Exxon, Shell, Chevron, 

Amoco, Texaco, Enron, Phillips, Fina, and the California 

Energy Commission to assemble capacity constraints on all 

existing and prospective future world pipelines and LNG 

facilities. 

As part of the process by which BSA and the world 

gas sponsors assembled realistic corridor capacity constraints, all pipeline capacities for all corridors in the 

model are properly represented. Furthermore, pipeline corridor transportation costs are consistent with the corridor 

capacity constraints. 

All corridors in the model are properly sized. Following the discussion of pipeline transportation costs, the 

question of what it costs to expand capacity on any of 

these corridors will be addressed. In other words, what it 

would cost to add capacity on an existing pipeline corridor 

versus building a new pipeline along a new or existing 

pipeline corridor. 

Given the geographic representation of the ex1stmg 

and prospective new pipeline system and the capacity constraints and bottlenecks in that system, the question arises 

whether transportation costs for new as well as existing 
784 THE FUTURE OF ENERGY GASES 

pipelines and LNG links are properly represented? To provide a satisfactory answer to this question, DFI sought 

from BSA and their world gas trade clients estimates of 

transmission costs on all existing pipeline and LNG routes, 

aggregated them into appropriate corridor transmission 

costs, and converted them in a form suitable for input to 

the model. Such transmission costs typically have two important elements. First, they represent the embedded cost 

of each pipeline. Theoretically, pipelines charge embedded 

cost rates. Pragmatically, however, pipelines charge embedded cost rates only during periods in which margins are 

not squeezed by competitive pressure from oil or spot gas. 

Pipelines usually discount rates during periods of intense 

competition. The BSA and world gas trade analyses specifically account for discounting by pipeline owners. As a 

result of such analysis, all pipeline and LNG corridor 

transportation costs are properly represented and are consistent with recent history. In effect, every link in the network contains a transportation cost estimate. 

In a series of applications of the NARG model by the 

National Energy Board of Canada, pipeline capacities and 

cost structures for all Canadian pipelines (all Canadian 

links) have been reviewed and modified to reflect the most 

current Canadian information. As a result, all pipeline and 

LNG corridor transportation costs for Canada are properly 

represented and are consistent with recent history. 

How can the cost of operating a pipeline along an existing corridor versus expanding that corridor be represented? 

There are three generic levels of pipeline capacity expansion that are explicitly represented within NARG. These are 

(1) expansion of capacity by "minor" actions such as additional compression, looping, pressure increases, (2) expansion of capacity along a given corridor by building an 

entirely new, parallel system, and (3) addition of an entirely 

new corridor. 

The model explicitly represents each of these options 

for each pipeline link in the following manner. The model 

assumes that the embedded cost of the capacity currently 

in place will affect the rates for quantities of gas transported that do not exceed currently known capacity. Thus, an 

initial tier of transmission service with elastic supply for 

quantities not exceeding current capacity can be represented as shown in figure 28A. To transport more gas than the 

current capacity of the corridor, it is necessary to augment 

the capacity through looping or pressure increase. Such 

augmentation is possible, but at a cost. Furthermore, such 

augmentation is usually bound by an upper constraint. 

That is, pressure increases can only add so much additional capacity, and looping can only add so much additional 

capacity. Thus, there is a secQnd tier in the supply curve 

for pipeline capacity as shown in figure 288, and that second tier represents incremental capacity additions along 

existing corridors. Finally, to exceed the capacity of an existing, fully looped, maximum pressure pipeline link, it is 

necessary to add new pipeline capacity along new right of 

PRICE 

Co:-.tAfter 

Capacity 

Expan:-.inn 

A 

PRICE 

CurrL·nt Capacity 

Cost After - - - - - - +---"' 

Capacity 

E!..pan:-.ion 

Current Co~t 1--------' 

Current ('apadty 

B 

PRICE 

C1pacity 

E>.pansi<m 

Cost of New 1- - - - - - - - - Capacity 

CostAfter - - - - - -

Capacity 

Expansion 

Current Cost 1--------' 

c Current Capacity 

... ... Capacity 

Expansion 

QUANTITY 

QUANTITY 

New Capacity 

QUANT/7¥ 

Figure 28. Three tiers of transmission service of a natural-gas 

pipeline. A, Existing pipeline or initial tier of transmission service. B, The second tier of transmission service that results from 

incremental expansion by looping or pressure increases of existing natural-gas pipeline capacity. C, The third tier that results 

from major expansion along a natural-gas pipeline route. 

way. At the incremental cost of securing such right of way 

and building such a pipeline, it is possible to expand the 

capacity of that corridor virtually without bound. Consequently, the overall supply curve for transportation services along an existing pipeline link has yet a third tier as 

shown in figure 28C. 

The NARG and world gas trade models have the rather complex but complete representation of pipeline cost 

and capacity shown in figure 28. Not only is current transportation cost information required of the model, but ca-
APPROACH THAT LINKS VOLUMETRIC ESTIMATES WITH COST AND PRICE 785 

pacity expansion costs through augmentation such as 

looping or pressure increases as well as new capacity addition costs are also required. The generalized equilibrium 

approach has a rather sophisticated representation of transportation infrastructure, current capacity, "minor" expansion, and new system addition. 

The inter-regional transportation linkages represented 

in the world gas trade model. Many of the inter-regional 

linkages are LNG linkages, whereas many others are overland or undersea pipeline linkages. With a few exceptions, 

most of the inter-regional linkages in the figure do not 

presently exist. Future supply-demand equilibrium will depend critically on the cost and competitiveness of these 

inter-regional linkages and when and whether they will be 

drawn into the mix. 

CONCLUSION 

For many years, organizations such as the U.S. Geological Survey have assembled volumetric estimates of gas 

and oil in place. It is legitimate for people in industry to 

ask: "What do such estimates mean to me? What do they 

mean to my business? What do they mean for commodity 

prices?" In a world of ideal, efficient markets, such estimates would have little relevance; the best use of one's 

time would be to merely survey the various markets. In 

reality, markets are not completely efficient, and methods 

other than market observations are required. Volumetric 

estimates can contribute to better decisionmaking if they 

can be associated with cost and price information and if 

their implications in the market can thereby be determined. Until the generalized equilibrium approach, volumetric information has never been linked with the market. 

It has never entered the decision process of private companies the United States, Canada, or the rest of the world. 

With the approach outlined herein, the U.S. Geological 

Survey volumetric estimates can be used to support such 

decisionmaking and lead to better industry profits, more 

enlightened regulation and Government administration, 

and more efficient use of resources. 

SELECTED REFERENCES 

Adler, R., Cazalet, E., Haas, S., Marshalla, R., Nesbitt, D., and 

Phillips, R., 1979, The DFI generalized equilibrium modeling system: published by Decision Focus Inc. 

Ashby, A., Darrow, K., Marshalla, R., Nesbitt, D., January 1985, 

The economic benefits of R&D on gas supply .technologies: 

Gas Research Insights, published by Gas Research Institute. 

Begg, D., 1982, The rational expectations revolution in microeconomics: Theories and evidence: Johns Hopkins University Press. 

Bohi, D., and Toman, M., 1984, Analyzing nonrenewable resource supply-Resources for the future: Johns Hopkins 

University Press. 

Boyd, D., Phillips, R., and Regulinski, S., April 1982, A model 

of technology selection in aggregated markets: Management 

Science. 

Braunstein, T.J., 1983, A decision analysis of a petrochemical expansion study, in Howard, R., and Matheston, J., eds., The 

Principles and Applications of Decision Analysis, Strategic 

Decisions Group. 

Brock, H., and Nesbitt, D., 1977, Large-scale energy planning 

models: A methodological analysis, published by Stanford 

Research Institute. 

Brown, K., February 1988, Towards a continental natural gas 

market: Historical perspectives and long-term outlook: Canadian Energy Research Institute Study No. 26. 

Cagan, P., 1956, The monetary dynamics of hyperinflation, in 

Friedman, M., ed., Studies in the Quantity Theory of 

Money: University of Chicago Press. 

Cazalet, E., 1970, Decomposition of complex decision problems 

with applications to electric power system planning: Stanford, Calif., Stanford University, Ph.D. dissertation. 

Cazalet, E., 1977, Generalized equilibrium modeling: The methodology of the SRI-Gulf Energy Model, Decision Focus Inc. 

Report. 

Cazalet, E., January 1975, Overview of the SRI-Gulf energy 

modeling methodology, published by Stanford Research 

Institute. 

Cazalet, E., November 1976, A Western Regional Energy Development Study: Volume 1: Economics; Volume II: SRI Model 

Data Base, prepared by Stanford Research Institute for the 

Council on Environmental Quality. 

Cazalet, E., and others, May 1975, Western energy resources 

study: Economics: Energy Model Structure, Data Base, and 

Nominal Case Output, prepared by Stanford Research Institute for the Executive Office of the President, Council on 

Environmental Quality, CEQ Contract EQ5AQ007, SRI 

Project MSU-4000. 

Clark, C., and Regulinski, S., September 1984, Calculating the 

cost of producing energy for regulated and nonregulated industry: Gas Research Institute Report GRI-94-0155. 

Dasgupta, P., and Heal, G., 1979, Economic theory and exhaustible resources: London, Cambridge University Press. 

Dimensional Fund Advisors, Sixty years of retums-1925-1985: 

Dimensional Fund Advisors. [Available from 1299 Ocean 

Avenue, Suite 650, Santa Monica, CA 90401.] 

Electric Power Research Institute, February and September 1977, 

Fuel and energy price forecasts, v. I and 2: EPRI EA-433 

Report, prepared by Stanford Research Institute. 

Energy Information Administration, 1985, Natural gas annual 

1984 DOE/EIA-0131(84)/l. 

Everett, H., III, May-June 1963, Generalized lagrange multiplier 

method for solving problems of optimal allocation of resources: Operations Research 3. 

Fama, 1991, Investment vision: Market, p. 54-55. 

Finizza, A., Jacquette, P., Nesbitt, D., and Marshalla, R., 1986, 

Precursors for high and low future World oil prices: IAEE 

Proceedings. 

Gately, D., September 1984, A ten year retrospective: OPEC and 

the World oil market: Journal of Economic Literature. 

Haas, S., Nesbitt, D., and Singh, J., 1987, The GRI North American regional gas supply-demand model: GRI Report Number 

87-0122. 
786 THE FUTURE OF ENERGY GASES 

Haas, S., Marshalla, R., Nesbitt, D., and Oman, D., February 

1983, Data base and model structure for R&D planning and 

price-quantity forecasting at GRI, Decision Focus Inc. report 

to the Gas Research Institute. 

Harberger, A., 1975, Three basic postulates for applied welfare 

economics: An interpretive essay: Journal of Economic 

Literature. 

Henry, J.P., Jr. and others, May-June 1979, World energy: A 

manageable dilemma: Harvard Business Review. 

Hogan, W., 1975, Energy policy models for project independence: Computation and Operations Research, v. 2. 

Hogan, W., and others, February 1978, Evaluation of generalized 

equilibrium energy models and depletable resource pricequantity relationships in support of R and D planning: published by Decision Focus Inc. 

Holtberg, P., and others, 1988, The 1987 GRI baseline projection, 

in Gas Research Insights, published by Gas Research 

Institute. 

Hotelling, H., April 1931, The economics of exhaustible resources: Journal of Political Economy. 

Hudson, E., and Jorgenson, D., Autumn 1974, U.S. energy policy 

and economic growth: Bell Journal of Economics and Management Sciences, v. 5, no. 2. 

Interagency Task Force on Synthetic Fuels Commercialization, 

November 1975, Recommendations for a synthetic fuels 

commercialization program: [Available from U.S. Government Printing Office, Washington, D.C. 20402, Stock Num-

. ber 041-001-00111-3.] 

Intriligator, M., 1971, Mathematical optimization and economic 

theory: Prentice Hall. 

Jorgenson, D., 1969, The theory of investment behavior, in Williams, H., and Juffnagel, J., eds., Macroeconomic Theory, 

Prentice Hall. 

Kantor, B., December 1979, Rational expectations and economic 

thought: Journal of Economic Literature, v. XVII. 

Malkiel, Burton, 1991, A random walk down Wall Street: Norton 

Inc. 

Manne, A., 1976, ETA-A model for energy technology assessment: Bell Journal of Economics, v. 7, no. 2. 

Marshalla, R., Nesbitt, D., and Pine, G., May 1986, An approach 

to measuring the benefits of research and development at the 

Gas Research Institute: Decision Focus Inc. report to Gas 

Research Institute. 

Marshalla, R., and Nesbitt, D., October 1984, Evaluating the 

benefits of supply R&D to consumers and producers-A tutorial: Decision Focus Inc. report to Gas Research Institute. 

Marshalla, R., and Nesbitt, D., January 1986, A technique for 

computing directly comparable measures of benefit for supply and utilization technologies: Decision Focus Inc. report 

to Gas Research Institute. 

Marshalla, R., April 1982, Integrated forecasting model synthetic 

fuels study (v. 1 and 2): Electric Power Research Institute 

Report EA-2358. 

Marshalla, R., Nesbitt, D., and Oman, D., 1984, Cost and performance estimates for energy supply and utilization processes: GRI Report Number GRI-85/0130. 

Marshalla, R., 1978, An analysis of cartelized market structures 

for nonrenewable resources: Stanford, Calif., Stanford University, Ph.D. dissertation. 

Marshalla, R., and Nesbitt, D., March 1984, The Decision Focus 

Inc. (DFI) world oil model: Model structure and methodology, Decision Focus Inc. working paper. 

Marshalla, R., and Nesbitt, D., March 1984, The Decision Focus 

Inc. (DFI) world oil model: Data base, Decision Focus Inc. 

working paper. 

Marshalla, R., and Nesbitt, D., 1986, Future World oil prices and 

production levels: An economic analysis: Energy Journal, 

v. 7, no. 1. 

Nesbitt, D., and Phillips, R., 1981, Financial statements and producer behavior in the LEAP model: published by Decision 

Focus .Inc. 

Nesbitt, D., Marshalla, R., and Darrow, K., May 1982, Allocation 

of R&D resources among projects at the Gas Research Institute, Decision Focus Inc. working paper. 

Nesbitt, D., 1979, A decision analysis of crude oil price controls, 

Decision Focus Inc. working paper. 

Nesbitt, D., and Choi, T., 1988, The numbers say no: Energy 

Journal, v. 9, no. 3, p. 31-59. 

Nesbitt, D., and Choi, T., 1986, Oil price and the rate of return 

on capital investment: Decision Focus Inc. report to the Department of Energy. 

Nesbitt, D., and Phillips, R., 1983, A decision analysis of the 

appropriate R&D strategy for enhanced oil recovery: Energy 

Systems and Policy, v. 7, no. 3. 

Nesbitt, D., and Phillips, R., April 1982, The optimal allocation 

of research and development resources: Decision Focus Inc . 

report to Oak Ridge National Laboratory. 

Nesbitt, D., November-December 1984, The economic foundation of generalized equilibrium modeling: Operations Research, v. 32, no. 6. 

Phillips, R., and Cazalet, E., October 1979, The decision maker 

forecasting within the DFI/EIA demonstration model: Decision Focus Inc. report. 

Potential Gas Committee, April 1987, Potential supply of natural 

gas in the United States: Colorado School of Mines. 

Republic of Argentina/United States Cooperative Energy Assessment, 1982, v. 1, United States Department of Energy report. 

Rinholm, R., 1987, The Canadian natural gas industry: Options 

and opportunities: University of Saskatchewan, M.S. thesis. 

Samuelson, P., 1952, Spatial price equilibrium and linear programming: American Economic Review, v. 42. 

Solow, R., 1957, Technical change and the aggregate production 

function: Review of Economics and Statistics, v. 39. 

Stockman, D., The triumph of politics, 1986, New York, Harper 

and Row. 

Sussman, S.S., and others, October 1976, A Study of the importance of energy R&D for the United States: UCRL-52140, 

published by Lawrence Livermore Laboratory 

Sussman, S.S., and Rousseau, W.F., 1978, A new language for 

economic general equilibrium models: UCRL-52507, published by Lawrence Livermore Laboratory. 

Vidas, E., Lerner, M., and Crawford, R., June 1985, Guide to the 

hydrocarbon supply model: Energy and Environmental 

Analysis Inc. report to Gas Research Institute. 

Woods, T., and Vidas, E., May 1983, The GRI hydrocarbon 

model: The structure, results, and sensitivities of the model 

in its initial form: Gas Research Insights, published by Gas 

Research Institute. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Natural Gas-How Much, At What Cost? 

By Jairam S. Gopa11 and W. William Wood, Jr. 1 

CONTENTS 

Abstract ......................................................................... 787 

Introduction ................................................................... 787 

U.S. Natural Gas Market .............................................. 788 

Natural Gas Resource Estimates .................................. 789 

Application of Regional Resource Cost 

Information in Economic Analyses .............................. 790 

Understanding the Natural Gas Market ................. 791 

California's Need for New Pipeline Capacity ....... 794 

Impact of Resource Cost Estimates on Price of 

Natural Gas ................................................................... 795 

Conclusion ..... ..... ... ........... .................. .... .. ....... ... . ......... 796 

References Cited ... ... ... ....................................... ... ........ 796 

ABSTRACT 

This paper raises an important issue concerning the 

forecasting of natural gas wellhead prices. The paper begins with a historical review of U.S. natural gas market 

development, followed by a description of the U.S. natural 

gas resource information that is currently used at the California Energy Commission to forecast natural gas supply 

and price. A significant amount of information is available 

regarding the potential-reserve estimates in various basins. 

However, information regarding the costs involved in finding, developing, and producing these resources and the 

impacts of technological advances on prices is inadequate. 

This paper discusses some efforts made at the California 

1

Califomia Energy Commission, Fuels Planning Office, Energy 

Forecasting and Planning Division, 1516 9th Street, MS#23, Sacramento, 

CA95814. 

Energy Commissi9n in quantifying the impacts of technology advances on future wellhead prices of natural gas. 

Several examples illustrate the need for additional cost information for planners to meaningfully analyze and set 

policies regarding efficient use of this clean burning fuel. 

The paper concludes with an emphasis on the need to develop information on the cost element of forecasting natural gas supply and prices. 

INTRODUCTION 

The California Energy Commission (commission) was 

established by the California Legislature in 1975. Among 

the duties assigned to it were permitting and siting new 

power plants, establishing building and appliance conservation standards, providing for the development of new or 

alternative energy sources, and providing the legislature 

historical and forecasted trends in energy use and associated prices. The commission is mandated to prepare a report 

every two years, the "California Energy Plan," outlining 

California's long term energy policies. The "California Energy Plan" draws information from four different reports 

published by various divisions in the commission. One of 

the four reports is the "Fuels Report," also a biennial publication, mandated by law. The "Fuels Report" provides 

the basis for development of State energy policies on energy use, supply availability, and future price projections. 

The commission's energy price forecasts have become 

increasingly important in recent years in evaluating consequences of various commission programs. The State's interest in promoting environmentally sensitive energy options 

has prompted the development of new technologies and 

alternative fuels that offer cleaner uses of energy. Natural 

gas has become a premium fuel to meet California's future 

energy needs, mainly owing to its clean burning characteristics, apparent abundance, and competitive price. 

787 
788 THE FUTURE OF ENERGY GASES 

In order to develop the supply and price trends of natural gas availability to California, the commission needs to 

evaluate the supply potential from a variety of natural gas 

supply regions that could potentially serve the State in the 

future. The natural gas market in the United States has 

undergone major changes in the way natural gas is produced and transported to demand regions. The Nation's 

natural gas pipeline system has become fully integrated, 

indicating the need for a multi-regional approach to understand how the natural gas market currently works and will 

work in the future. 

The four basic components in the natural gas market are 

(1) potential supply availability and cost to find and develop 

these resources, (2) pipeline transportation capacity, (3) demand for natural gas, and (4) associated (delivered) prices. 

In this paper we will focus on one of these componentsthe potential resources to support future supply and the cost 

to produce these potential resources. This will be followed 

by examples of how the detailed resource information may 

be used to assess specific issues and market analysis. 

U.S. NATURAL GAS MARKET 

While the natural gas market had it origins in the early 

1800's, it did not fall under Federal regulation until 1938 

with the passage of the Natural Gas Act. This act set up the 

Federal Power Commission (FPC) with the authority to 

regulate interstate pipeline prices. Excessive price increases at the wellhead prompted the Supreme Court to render a 

1954 decision in the historic Phillips Petroleum Co. versus 

Wisconsin case, requiring the FPC to control wellhead 

prices. This set the stage for the development of two separate markets, a controlled interstate market and an uncontrolled intrastate market. 

Toward the late 1960's, natural gas supplies began to 

decline. Prices in the interstate and intrastate markets 

began to diverge as prices of newly discovered gas sold to 

the unregulated intrastate market began to exceed the regulated interstate gas price. The year 1970 marked a turning 

point in the sale of gas in the two markets: The reserves 

dedicated to the intrastate market increased from one-third 

of total natural gas reserves in 1969 to two-thirds in 1970. 

To compound matters, gas transportation across state borders for interstate commerce fell under Federal regulation. 

Neither the intrastate pipelines nor the producers wanted 

their gas to be federally regulated. Accordingly, the intrastate market continued to capture the bulk of the new discoveries, creating supply surplus for the intrastate market 

and supply shortages for the interstate market. 

The Natural Gas Policy Act (NGPA) was passed in 

1978 to stimulate the natural gas market by requiring deregulation of natural gas wellhead prices, commingling of 

intrastate and interstate gas supplies, and streamlining the 

natural gas transportation system. 

Prior to the passage of the NGPA, the interstate pipeline companies were natural gas merchants, responsible 

for both purchasing natural gas from producers at one end 

of the pipeline and transporting and selling it to gas utility 

companies at the other. The gas utility companies, commonly known as local distribution companies (LDC's), 

were solely responsible for providing natural gas to end 

users such as residential, commercial, industrial, and electricity generation customers. The pipelines purchased all 

the needed gas supplies from producers and sold it to 

LDC's under long term contracts. 

Since the early 1980's several factors in the natural 

gas market have led to a fundamental change in the regulatory climate. Interstate pipelines were forced to gradually shed the merchant function. Under the NGPA the 

Federal Energy Regulatory Commission (FERC) set in 

motion several regulatory changes to the ways in which 

natural gas is bought, transported, and sold in the market 

place. These changes include open access transportation 

options, unbundling of transportation costs, capacity brokering, and the development of market hubs at which natural gas purchasing transactions will be conducted. (The 

FPC became the Federal Energy Regulatory Commission 

when the Department of Energy was created.) 

Today interstate pipelines are no longer solely gas 

merchants. Increased transportation-only services by the 

pipeline companies provide end users an opportunity to 

negotiate for supplies directly with producers and to contract separately with pipeline companies for transportation 

of natural gas. Both the utilities and end-use customers 

may now purchase gas directly from producers. Along 

with unbundled, or discrete, transportation and distribution 

services offered by pipelines and utility companies, the 

end users and LDC's have the option of purchasing shortterm supplies from the cheapest supply sources and have it 

transported through the complex network of interstate and 

intrastate pipelines. Their purchases are no longer confined 

to limited supply areas and pipelines. 

The U.S. pipeline system now provides a network that 

connects almost every producing region with all the demand centers. Free from cumbersome regulation, natural 

gas may be purchased from any supply region and transported to any demand center. As an example, Canadian 

Alberta natural gas has been delivered to demand regions 

in Florida and Mexico. This was accomplished using several pipeline interconnects and common supply/receipt 

points. More recently, ENRON Company is offering an alternative to moving Alberta natural gas to California via 

the traditional Pacific Gas Transmission system or the proposed AltamonUKern River pipeline system. ENRON 

Company would use Northern Border, Northern Natural, 

and Transwestern pipeline systems to move Alberta gas to 

California. The natural gas would flow from Alberta to the 

U.S. Midwest, then south to Texas, and west to southern 

California. 
NATURAL GAS-HOW MUCH, AT WHAT COST? 789 

NATURAL GAS RESOURCE ESTIMATES 

A proper characterization of the natural gas resource 

base in the entire North American Continent is critical to 

understand how the natural gas market will perform in the 

future (see Nesbitt, this volume). This involves both the 

quantity of potential natural gas available from each region and the costs needed to develop and produce these 

resources. "Potential resources" refers to the quantity of 

natural gas that is economically producible from these resources and does not explicitly consider the cost of production. The potential resources considered in preparing 

resource estimates include conventional supplies of natural 

gas existing in onshore and offshore areas, shallow and 

deep reservoir formations, and unconventional natural gas 

from tight sand formations, Devonian shales, and methane 

in coal seams. Publicly available resource estimates for the 

United States are prepared by the Potential Gas Committee (PGC), the U.S. Department of Energy (DOE) and the 

U.S. Geological Survey (USGS) (see Dolton and others, 

this volume; Gautier and Brown, this volume). A recent 

study by the National Petroleum Council adds to the list of 

available sources for reserve estimates (National Petroleum Council, 1992). 

Estimates of reserves are available from each of the 

above mentioned sources. Potential resource estimates vary 

considerably among these sources and are not directly 

comparable. Each entity uses different methods of resource 

characterization and a differing mix of resources in preparing its potential resource estimates. More importantly, the 

resource estimates developed generally do not include the 

costs required to incrementally develop and produce these 

resources. This creates a major problem when considering 

the future potential for natural gas production from each 

resource. 

It is not enough to characterize resource potential only 

in terms of the quantity of gas that is available. It is equally essential to characterize the cost structure associated 

with the development of the resource base. Resource estimates without associated costs provide little information 

for a planner in addressing long-term natural gas supply 

and price forecasts. For example, an estimate of 1,200 trillion cubic feet (Tcf) of proven and potential U.S. natural 

gas resources indicates that there is about 60 years of supply of natural gas (based on annual consumption of 20 Tcf) 

but does not provide information for planners to evaluate 

potential wellhead prices, market competition among various resources, and the impact of geographic distribution of 

the potential resource base. 

To understand the future natural gas market, planners 

need information that is far more detailed than what has 

been provided in the past. Natural gas planners need resource information that includes both regional estimates 

by resource type and detail on the associated costs to find, 

drill, and develop potential resources. 

The impact of new technology is a major factor that 

influences the pricing of potential reserves. The scarce information that is currently available on cost estimates of 

potential resourc~s is based on technology that is currently 

available. These cost estimates do not include impacts of 

expected future technology advances. Forecasts that are 

based strictly on this assumption will provide results that 

could be significantly different from an analysis that incorporates new technologies. 

During the past 5 years, gas reserve additions per foot 

drilled have doubled from what they were in the previous 

I 0 years. Many observers of the natural gas market have 

expressed the view that new technologies and efficiency 

improvements are responsible for the increase in reserve 

additions per foot drilled and in increased finding rates 

(Ellis, 1991 ). 

New technologies and operational techniques, such as 

new 3-dimensional seismic analyses, horizontal drilling, 

slim-hole drilling, new drill-bit technology, tension-leg 

drilling platforms for deep offshore drilling, and others are 

being developed. It is anticipated that these technologies 

will further reduce the costs to find and develop natural 

gas resources. In addition, it is also expected that reserve 

additions from unconventional resources will increase. A 

typical example would be the horizontal drilling technique, which has the potential to access pockets of reserves or thin pay zones that are inaccessible and (or) 

uneconomical by drilling conventional vertical wells. 

Overall, it can only be expected that the use of new 

technologies, such as those discussed above, as well as 

many others, will become more prevalent in the future. In 

evaluating the future natural gas market, planners need to 

know how these new technologies will impact finding, 

drilling, and production costs for each potential resource 

type in each region. If planners do not have access to 

these costs, their estimates of future natural gas supply, 

wellhead prices, and interregional gas movements will not 

be reflective of the future gas market. 

In addition to costs incurred in exploration for new 

reserves, the development costs associated with bringing 

a natural gas well to production form an important element in the pricing of natural gas. Although technology 

improvements have lowered the costs in finding and drilling for new reserves, it has been observed that the overall 

cost of a producing well may not decrease even with 

lower drilling costs. This is attributed to new environmental requirements, which increase the cost of drilling and 

developing a well. These additional costs may partially or 

fully offset the savings in drilling costs achieved through 

technology advances. On the other hand, new well development and downhole logging and fracturing techniques 

are being developed. An assessment of the impact of 

these advances becomes paramount in addressing the economics and viability of natural gas production in different 

regions. 
790 THE FUTURE OF ENERGY GASES 

APPLICATION OF REGIONAL 

RESOURCE COST INFORMATION IN 

ECONOMIC ANALYSES 

The California Energy Commission is mandated by the 

State Legislature to provide a 20-year forecast of natural 

gas supply and price availability in the State. As long as the 

pipelines were natural gas merchants, the commission 

needed only an understanding of the specific regions from 

which California's natural gas supplies were traditionally 

obtained to prepare the natural gas supply and price forecasts for California. Those early supply forecasts were 

based on the potential supply available from specific regions and the market shares that each LDC had with pipelines serving their regions. These shares were unlikely to 

change over the forecasted horizon, owing to the long-term 

contracts signed between the producers, pipelines, and the 

LDC's. Wellhead natural gas prices were equated to regulated wellhead prices as set forth in the Natural Gas Policy 

Act. Burner tip prices were equated to forecasted oil prices. 

The changes in the natural gas market, brought on by 

the implementation of the NGPA, obviated the conventional 

method that was being practiced by the commission in forecasting natural gas prices and supplies. In order to address 

the complex nature of the evolving natural gas market, the 

commission now uses a sophisticated, state-of-the-art computer model to simulate the natural gas market in the United 

States, Canada, and Mexico. This model, "the North American Regional Gas Model" (NARG) (Hass and others, 1987), 

utilizes detailed resource information. 

The commission's natural gas resource data includes 

information for 10 primary natural gas production regions 

in the lower 48 States. These regions are defined according to their geological characteristics. Each producing region is further split into one or more resource types with a 

total of 35 natural gas resource types. 

The resource types included in the data base can be 

broadly classified as onshore conventional or unconventional resources and offshore resources. The conventional 

natural gas resources are further divided into shallow and 

deep resources, depending on the depth of each producing 

natural gas pool in each region. Shallow resources are those 

found above 15,000 ft, whereas deep resources are those 

found at or below 15,000 ft. The unconventional resources 

include natural gas producible from tight sand formations, 

Devonian shale, and methane from coal seams. Offshore 

resources are subdivided into shallow and deep. Shallow 

offshore resources are in waters less than 200 m and offshore deep resources are in waters 200 m and deeper. 

Each resource type is represented by a resource supply 

and cost curve, well operation and maintenance cost 

curve, and a production decline profile. In some cases, 

where the gas production is associated with liquids production, an additional parameter is included to account for 

the revenues obtained from the natural gas liquids production. Additionally, new technology advances and operational efficiency improvements that would reduce the costs 

to find, develop, and produce natural gas from these resources may be considered in determining the future wellhead price of natural gas. 

The commission's current resource data base in 

NARG was obtained from Decision Focus, Inc. (DFI) of 

Palo Alto, California. DFI has drawn on reports by the 

PGC, the Canadian National Energy Board (CNEB), and 

additional information it has obtained through its many 

contacts with the gas industry (for further information of 

data used in NARG, see California Energy Commission, 

1989a). The commission has subsequently updated resource data for several of the resource types based on 

workshops and hearings held at the commission during the 

"1991 Fuels Report" proceedings (California Energy Commission, 1991 ). 

The NARG is a dynamic equilibrium model that captures the effects of gas-on-gas competition, changing technology characteristics, regulatory impacts, and impacts of 

producers' decisions on the price and supply availability of 

natural gas. The NARG model views the natural gas market as a network of gas supply regions connected to demand regions by a system of pipelines. The analytical task 

of the model is to find a set of gas wellhead and delivered 

(end use) prices and a corresponding set of quantities of 

natural gas delivered through pipelines, which balance supply and demand in all regions and at all time periods over 

the model's 45-year time horizon. In the long run, the economic and competitive forces in each region will determine the market-clearing prices. 

The network of supply and demand regions connected 

by pipelines is used to calculate market clearing prices and 

quantities simultaneously at all points throughout the gas 

system. It is most useful for forecasting prices and supplies, evaluating strategic planning alternatives, and analyzing the impacts of market uncertainties and government 

policies over the long term. Most significantly, the model 

is not an extrapolation of past trends. Rather, its focus is 

the most likely evolution of the fundamental structure of 

the gas industry in the future. 

Natural gas resource and cost information forms a 

major input in addition to other parameters in the commission's assumptions in addressing the future price and supply availability of natural gas. This information is specified 

by "supply-cost curves" and "production profiles" as input 

assumptions for each resource type identified in the NARG 

model data base. These resources and costs are the driving 

forces in the NARG. Given the costs required to develop 

and prove potential resources, the model's logic determines 

the cheapest available resource in order to satisfy the given 

demand for natural gas in any specific demand region at 

any specific time on the forecast horizon. If a specific resource is not economic compared to other sources, that resource is not produced at that time. When that resource 
NATURAL GAS-HOW MUCH, AT WHAT COST? 791 

becomes economically competitive in the future, then supplies from that resource are made available. 

With the NARG model's capabilities, the commission 

is able to address a number of natural gas related issues. The 

commission has gained knowledge on how the natural gas 

market operates and the interrelationships of the various 

regions in Canada and the United States. In addition to the 

mandated forecast of natural gas supply and price, the commission has used the model to address a variety of specific 

issues. For example, in the mid-1980's, five new pipeline 

projects were proposed to deliver natural gas to California. 

The commission prepared an economic evaluation of the 

alternative pipeline proposals to determine the need for these 

new pipeline capacities (California Energy Commission, 

1989a). Another application of the model was demonstrated 

in 1992, when the commission analyzed the need to expand 

a specific intrastate natural gas pipeline serving the northern 

California market (Gopal, 1992). The following provides a 

brief discussion on how the NARG model has been used in 

a variety of analyses conducted at the commission. 

20. 

-(.) 

1-

c 

>- 15. 

0.. 

0.. 

::::J 

(/) 

10. 

UNDERSTANDING THE NATURAL GAS MARKET 

Every 2 years the commission prepares, adopts, and 

publishes a natural gas supply and price forecast. In preparing these forecasts, the commission uses the NARG 

model to provide supply and price forecasts for natural gas 

delivered to the California border. In obtaining the supply 

and price information concerning California, information 

regarding the rest of the United States and Canada is also 

obtained. This section discusses what has been learned 

about the North American gas market in general from the 

commission's most recent biennial fuels report (California 

Energy Commission, 1991 ), which considers the natural 

gas market for the years 1989-2011. The 1989 supply and 

demand data are historical values. 

To meet the increased demand for deliveries to end 

users, U.S. annual production increases from 17.5 Tcf in 

1989 to 23.8 Tcf in the year 2011 (does not include pipeline, lease, and plant fuel). As shown in figure .1, the U.S. 

Gulf Coast region maintains its present production levels 

1989 1994 1999 2004 2009 2014 

~Gulf Coast 

I1~:1J:Jl Appalachia 

Year 

D Southwest ~Rocky Mountain 

D Other 48 States ~ Imports 

Figure 1. Forecasted natural gas supply for the lower 48 States. Tcf, trillion cubic feet. From California Energy Commission (1991). 
792 THE FUTURE OF ENERGY GASES 

over the next 20 years. Production in the Southwest (Anadarko, Permian and San Juan Basins) increases whereas 

the Rocky Mountains and Appalachian supply regions 

emerge as prominent production regions in the future 

(fig. 1). Imports from Canada and liquefied natural gas 

(LNG) purchases increase substantially over the forecasted 

horizon. Canadian imports peak in 2004 while LNG imports increase over time to exceed the present capacity of 

U.S. regassification facilities by 2009. 

In the future, production from conventional onshore 

natural gas resources declines. Other resource types replace the decline in conventional production to meet the 

growing demand for natural gas. Figure 2 shows projections of natural gas production from different types of resources. As shown in figure 2, offshore supply declines 

initially, then gains back its market share to current production levels. Deep onshore resources, followed by tight 

sands meet a growing natural gas need (fig. 2). Technology to produce natural gas from San Juan Basin coal beds 

is now on the forefront and will play a significant role in 

the future in meeting western regional supply needs. Fu12.0 

10.0 

-

~ 8.0 

c 

c 

.g 6.0 

(.) 

:::J 

-o 

0 c: 4.0 

2.0 

ture estimates will include coal-seam gas reserves in other 

basins, such as the Rocky Mountain region, as information 

becomes available. 

Figures 3A and B provide information on forecasted 

pipeline flows between supply regions and demand areas. 

These two figures can be used to compare the actual pipeline flows for the year 1989 with forecasted pipeline flows 

for the year 2011. 

By comparing natural gas pipeline flows on figures 3A 

and B, it can be clearly seen that there is a counter-clockwise shift in natural gas flows. The Gulf Coast supply region is the principal production area in the United States, 

providing about 50 percent of the Nation's natural gas 

supplies. Production from this region shifts from being the 

dominant supplier for the West South-Central demand region, to meeting a greater share of the East South-Central, 

South Atlantic, and Northeastern States demands. 

As Gulf Coast supplies shift to serving the East and 

Northeast markets, the future will see the West South-Central demand region outbidding other demand regions for 

natural gas from the Permian and Anadarko Basin produc1989 1994 1999 2004 

Year 

2009 2014 

Figure 2. Gas production by resource type for the lower 48 States. Tcf, trillion cubic feet. From California Energy 

Commission (1991). 
NATURAL GAS-HOW MUCH, AT WHAT COST? 793 

tion regions. This will result in significant increase in supply flows from these two basins to the West South-Central 

demand region, while their market share, exemplified by 

flows out of the Permian Basin to the traditional West 

Coast demand region, decreases (fig. 3). 

The San Juan Basin also experiences significant 

growth in production, but maintains and even increases its 

flows to California (fig. 3). Historically, El Paso Natural 

Gas Company and Transwestern Pipeline Company pipelines have transported natural gas to California from the 

Permian, Anadarko, and San Juan Basins. Analysis conducted at the commission indicates that while San Juan 

Basin will continue to feed the California market, flows 

from the Permian Basin to San Juan Basin will reverse, as 

WeAN • <: ~ SASKA 

. ~a .·.·· .. ·.·. ALB .oa " . 

BC ~ c::::;) c:=:::::t> CZ3J> o.o 1.2e 

A 

Figure 3. North America Regional Gas model maps of forecasted natural gas pipeline flows between supply and demand 

regions. Supply regions are shaded oval areas; demand areas 

are large black dots; arrows represent pipeline links and show 

direction of pipeline flows with arrow width indicating relative 

magnitude of pipeline flow; numbers are pipeline flows in trillion cubic feet of natural gas per year. A, 1989 gas flow. B, 

2011 gas flow. ONT, Ontario; ECAN, Eastern Canada; SASKA, 

they did on the El Paso Natural Gas Company pipeline 

during 1992 (George Lippman, El Paso Natural Gas Company, oral commun., 1992). Further, the analysis indicates 

that production from the San Juan Basin, and possibly 

from the Rocky Mountain supply region, will flow to markets in the East, including the West South-Central demand 

region, through the reversal of flows in the El Paso and 

Transwestern pipelines. 

Production in the Rocky Mountain region increases, 

providing a larger share of supply to the Southwest and 

California markets. Rocky Mountain flows increase to the 

West North-Central demand region and to other Eastern 

markets, compensating for reduced flows from the Anadarko and Permian Basins. 

ECAN 

.u 

=====:>• 

Saskatchewan; ALB, Alberta; WCAN, Western Canada; PNW, 

Pacific Northwest; CA, California; NGP, Northern Great Plains 

States; WNC, West North-Central States; NC, North-Central 

States; ENC, East North-Central States; APP, Appalachian; NE, 

New England; MATL, Mid-Atlantic States; SATL, South Atlantic States; ESC, East South-Central States; WSC, West SouthCentral States; PERM, Permian Basin; ANAD, Anadarko Basin. 

From California Energy Commission (1991). 
794 THE FUTURE OF ENERGY GASES 

Increased Appalachian production becomes very important for the South Atlantic and Northeastern States. As 

the figures 3A and B indicate, the South Atlantic States are 

remote from the conventional large supply basins. Without 

increased Appalachian production levels, the South Atlantic 

demand region would place even greater pressure on the 

Gulf Coast region, LNG, and possibly, Canadian natural 

gas supplies. Although only two of the LNG facilities are 

currently operational, by the end of the study period (2011), 

LNG supply is expected to reach operational levels that are 

significantly higher than the existing capacity of the four 

regassification facilities (see Attanasi, this volume). 

Canadian production also increases, as does its exports 

to the United States. Although Southwest supply regions 

are meeting the ever greater needs of the West South-Central States, Canadian imports increasingly compete with the 

Rocky Mountain supplies for market shares in the Pacific 

Northwest, California, West North-Central and East NorthCentral demand regions. Increasing quantities of Canadian 

natural gas also find their way into the New England States. 

Large reserves in Western Canada with lower wellhead 

B 

Figure 3. Continued. 

prices compete with U.S. produced natural gas, gaining a 

significant market share over the forecast horizon. Canadian imports and Rocky Mountain supplies compete to meet 

the increased demand in California and displace supplies 

available from southwest supply regions. 

CALIFORNIA'S NEED FOR NEW 

PIPELINE CAPACITY 

During the mid- to late 1980's, there were nine natural 

gas pipeline proposals to build new capacity to California. 

As early as 1986, the commission had been on record 

stressing the need for additional pipeline capacity to meet 

the growing needs of California (California Energy Commission, 1986). The commission has repeatedly emphasized the need for construction of new pipeline capacity to 

the State (California Energy Commission, 1986, 1987, 

1989a, 1989b). By 1989 there were only five of the original 

nine competing pipeline proposals vying for the burgeoning 

natural gas market in California. The attrition of proposals 

ECAN .311 

=====C>• 
NATURAL GAS-HOW MUCH, AT WHAT COST? 795 

was attributed to the combining of two of the projects, 

whereas others dropped out of contention owing to economic reasons. 

Using the NARG model, the commission analyzed the 

economic viability of alternative pipeline projects and the 

need for new pipeline capacity for California. A study was 

initiated in late 1988, and completed in March 1989, with 

the publication of a staff report (California Energy Commission, 1989a). 

In the preparation of that report, 12 pipeline combinations and 11 sensitivity cases were examined. Each pipeline 

proposal was evaluated by itself and in combination with 

one or more of the other proposals. The sensitivity analysis, 

applied to all the proposals in combination, explored the 

impacts of varying potential resource availability, potential 

resource costs, changes in demand, and differing pipeline 

costs. Three important conclusions were drawn from the 

analysis: 

1. The greatest benefits occurred when all customers 

had access to the new pipelines. At the time of the analysis, only thermally enhanced oil recovery operations were 

proposed to receive natural gas service from several of the 

new pipelines. The commission's analysis, using NARG, 

indicated that the resulting gas-on-gas competition among 

the pipelines would benefit all natural gas customers, if the 

utilities had access to the new pipelines. 

2. The proposed Kern River pipeline proposal and 

proposed expansion of the Pacific Gas Transmission pipeline would provide the most benefits, on the order of $14.6 

billion. Benefits of these two pipelines were about the 

same when analyzed separately. The results indicated that 

their benefits to California were cumulative. 

3. The analysis indicated that the natural gas wellhead 

price is more important than the transportation cost to 

bring the gas to the market. This implies there are benefits 

to building more capacity than would be indicated by a 

simple supply-demand balance. The derived benefits result 

from opening up new natural gas supply regions, allowing 

the market to compete for the cheapest available supplies. 

Conclusion three indicates the .importance of the resource cost in analyzing the benefits of natural gas. Cost is 

the major driver in determining the potential supplies 

available to the market and also the price at which the gas 

can be consumed in the market. It is therefore important 

that we put as much effort in determining the cost of potential supplies as we do in determining the future potential of available natural gas reserves. 

IMPACT OF RESOURCE COST 

ESTIMATES ON PRICE 

OF NATURAL GAS 

The above sections have emphasized the importance 

of cost estimates in evaluating the price and supply availability of natural gas in the future. As mentioned above, 

technology plays a major role in determining the future 

availability of natural gas, the quantitative estimates of 

supplies projected to be available, and the price at which 

these supplies can be delivered to the market. Figure 4 

shows the impacts of reduced exploration and development costs, owing to technology advances on forecasted 

average natural gas wellhead price. The figure draws from 

the analysis of the natural gas market in the commission's 

"1991 Fuels Report" (California Energy Commission, 

1991). In the preparation of that report, a set of resource 

supply-cost curves were assumed for forecasting the supply and price of natural gas over a 20-year time horizon. 

The supply-cost curves assumed technology that was currently available (the analysis assumed a base year of 

1989); new drilling technology assumptions were then applied to the supply-cost curves to capture the reductions in 

finding and development costs over time owing to technology advances. 

Figure 4 shows two price paths; the higher wellhead 

price path results from using the supply-cost curves without applying any new exploration/drilling technology. For 

the second wellhead price path, it was assumed that new 

technology advances would reduce the future cost of finding and developing new reserves by 25 percent of the estimate based on current technology. This reduction was 

assumed to occur at an annual rate of 10 percent. It was 

further assumed that the reduction, owing to technology 

advances, is the same in all categories of natural gas resources. As indicated in figure 4, new technologies will 

significantly reduce wellhead prices. In 1994, as the result 

of new technologies, lower 48 average wellhead prices 

$5.00 

0 

~ 

$4.50 

~ m 

<Xl 

m $4.00 . 

oi 

0 

it $3 50 -o 

(1j 

(j) 

.L 

(ij $3.00 

!5: 

<Xl 

" Q; $2.50 ;: 

0 

_J 

cri 

::i $2.00 

$1.50 

1994 1999 2004 2009 2014 

Years 

Figure 4. Technology impact on natural gas prices. Mcf, thousand cubic feet. From California Energy Commission (1991). 

Plus symbols indicate prices with technology impact; open 

boxes indicate prices without technology impact. 
796 THE FUTURE OF ENERGY GASES 

drop by $0.24 per thousand cubic feet (Met) from $2.11 

per Mcf (in the no-technology-impact case) to $1.87 per 

Mcf (fig. 4). By 2014, the forecasted reduction in wellhead 

price is $0.61 per Mcf, a drop from $4.89 per Mcf to 

$4.28 per Mcf (fig. 4). 

Some may question whether the commission's analysis overstates the effect of new technologies. Robert L. 

Brown, manager of gas marketing development for Mobil 

Oil in Jennrich (1992) states, "we found an underlying 

technology-based cost savings of about 3 percent per 

year." Assuming just half of the 3 percent per year new 

drilling technology impact (drilling expenses represent 

about half of the cost to bring a gas well into production) 

for the five years extending from the base year 1989 to the 

first forecast year 1994 would reduce the 1994 wellhead 

price of $2.11 per Mcf by $0.16 per Mcf, a close approximation of the commission's analysis results. If the new 

technology effects were to continue through the study period, the 2014 wellhead price would be reduced from 

$4.89 per Mcf to $3.37 per Mcf, considerably lower than 

the commission's analysis. Although the commission's 

analysis and an analysis bases on a 3 percent per year 

technology impact yield differing answers, the order of 

magnitudes are the same. 

The commission staff recently has prepared an evaluation of the potential effects that four new technologies 

would have on drilling costs for each of the supply regions 

and resource types within the supply regions (Wood and 

Hewitt, 1993). The technologies considered include 3-dimensional seismic surveys, slim-hole drilling, horizontal 

drilling, and new drill bits. The results of this analysis indicate that a full implementation of these technologies 

would have the potential of reducing drilling costs from 

30 percent to over 50 percent, depending on supply region 

and resource type. The analysis was prepared for use in 

the commission's "1993 Fuels Report," which is still in 

the development stage. Preliminary results of applying the 

new technology effects in the NARG analysis indicate 

considerable reductions in wellhead prices over what was 

reported in the "1991 Fuels Report" (California Energy 

Commission, 1991). 

To understand the relative merits of technology impacts and the extent to which different categories of resources will be affected, resource estimates for each 

natural gas resource basin or field should include the cost 

needed to economically produce the gas from that basin. 

This factor plays a major role in the gas-on-gas competition that occurs in any given demand region. The natural 

gas pipeline network in the United States is so interconnected that each demand region could potentially purchase 

natural gas from a variety of supply sources, thereby competing for the most economical supply. 

CONCLUSION 

An indepth analysis of the future natural gas market is 

not possible using the conventional methods of reporting 

potential natural gas resources. An estimate of potential resource data is meaningless without accompanying cost 

data. Better estimates of resource cost data along with impacts of technological advances is a necessity in evaluating 

the potential benefits of natural gas as a future source of 

energy gas. 

The analysis as described here is made possible for 

two reasons: (1) By the availability of estimates of potential natural gas resources, capital cost estimates to bring 

the resources into production, operational costs, and production profiles; the evaluation and quantification of the 

impacts of new technologies in finding, drilling, and developing potential natural gas resources wiil be important 

to future analyses. (2) A model like the NARG is also essential in determining the economics of natural gas production and the viability of these resources competing in 

the marketplace. 

The studies conducted at the commission have indicated that the application of these resource data, both quantitative estimates of reserves and the costs associated with 

bringing these resources to production, play a major role 

in analyzing the future potential of natural gas and its use 

in the United States. The NARG model has provided an 

indepth understanding of the natural gas market. Analysis 

of pipeline needs, regional issues, and impacts of regulations are made possible only if the detailed resource data 

as described in this paper are available. 

REFERENCES CITED 

California Energy Commission, 1986, Biennial Fuels Report: 

Sacramento, California Energy Commission, P300-86-007, 

p. ES-3 and p. 36-40. 

---1987, Biennial Fuels Report: Sacramento, California Energy Commission, P300-87-016, p. 2. 

---l989a, An economic evaluation of alternative interstate 

pipeline projects to serve California, staff report: Sacramento, 

California Energy Commission, P300-89-001, p. ES-1, -2 and 

p. 5-17 through 5-37. 

---1989b, Biennial Fuels Report: Sacramento, California Energy Commission, P300-89-0l8, p. 5. 

---1991, 1991 Fuels Report (working paper)-Natural Gas 

Market Outlook: Sacramento, California Energy Commission, P300-91-018WP6, p. 2-3. 

Ellis, P.A., 1991, Management perspective; new technology for 

gas finding-How important has it been?: Oil and Gas Journal, v. 89, no. 39, p. 42. 
NATURAL GAS-HOW MUCH, AT WHAT COST? 797 

Gopal, J.S., 1992, Testimony for the purpose of considering expansion of Pacific Gas and Electric Line 300 alone or in 

conjunction with expansion in gas storage facilities: Submitted by the California Energy Commission before the Public 

Utilities Commission of the State of California (CPU C), San 

Francisco, Investigations: 88-12-27, Rulemaking: 88-08-018. 

Hass, S., Nesbitt, D., and Singh, J., .1987, The Gas Research Institute North American regional gas supply-demand model: 

Gas Research Institute Report 87-0122. 

Jennrich, J.J., 1992, National Petroleum Council task group hikes 

estimate of gas supply to 150 years: Natural Gas Week, v. 8, 

no. 15, 14 p. 

National Petroleum Council, 1992, The potential for natural gas 

in the United States, source and supply: Washington, D.C., 

National Petroleum Council, v. 2. 

Wood, B., and Hewitt, C., 1993, Impacts of new technologies on 

well cost: Prepared for the NARG users meeting, California 

Energy Commission, March 22-23. 
Here we present the personal perspectives of several 

prominent explorationists. They have been included in this 

volume because-in addition to science and technologysuch things as experience, intuition, and luck have played 

important roles in the exploration for both oil and gas. 

These papers provide insight into the future of natural gas, 

and they discuss what role society as well as oil and gas 

companies will play as we move into this future. 

EXPLORERS' VISIONS 
FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Natural Gas and the Role of Competition in the United States 

By Keith E. Anderson 1 

CONTENTS 

Abstract .... .. ...... ... .... ... ... ..... ... ......... ..... ....... ... ......... ....... 799 

Introduction . .. .. .. ...... .. ....... .. ... .. . ......... ............ .. .. .... .. .. . .. . 799 

Demand for Natural Gas .............................................. 800 

Issues Affecting the Supply of Natural Gas ................. 801 

ABSTRACT 

Increasing demands for natural gas will result in exceptional opportunities for explorationists, investors, and 

consumers. The stability of price, the certainty of supplies, 

and the convenience of utilizing natural gas are all factors 

• considered by consumers. Suppliers who are able to locate 

new deposits of oil and gas, who have the skills to lease 

the lands, drill the wells, profitably produce the reserves, 

and who have a proven track record will gain most from 

the shift to natural gas. 

INTRODUCTION 

Natural gas is the fuel of the future. In 1992, consumption of 20 trillion cubic feet of natural gas in the 

United States supplied nearly 25 percent of the country's 

energy demands. Based on the 1992 Arthur Andersen Oil 

and Gas Industry Outlook Survey, 61 percent of oil and 

gas exploration company executives believe the U.S. demands for natural gas will increase 2 to 4 percent annually 

during the remainder of the 1990's. I share this optimism. 

However, the employees or investors in an oil and gas ex1

Washington Energy Resources, 601 Union, Two Union Square, 

Suite 2200, Seattle, WA 98101. 

ploration company should not expect that their business 

will survive simply because the conditions in the industry 

are improving. I believe that only skilled explorationists 

will survive the competition from other explorationists as 

well as the competition of other fuels. 

For many years the American Gas Association (AGA) 

and local gas-distribution utilities have advertised that natural gas is environmentally clean, economical, and plentiful. The cornerstone of President Clinton's national energy 

policy is natural gas. Natural gas is the best choice of energy sources for many reasons. 

Although many experts are saying that 1pore gas will 

be burned because it's clean, in reality the demand for gas 

will increase because of its competitive price. The Federal 

Energy Regulatory Commission (FERC) has completed its 

deregulation of the gas industry. Prices were deregulated 

for sales of "new" gas in 1984. Regulation of prices for 

"old" gas expired on December 31, 1992. (New gas is gas 

reserves drilled and produced subsequent to deregulation 

in 1984; old gas is gas covered by government price regulations. At the end of 1992 even new prices for old gas 

were deregulated.) Some experts in the oil and gas industry voice concerns that wellhead prices are too low. As 

stated in an article in the March 16, 1992, issue of "Time" 

magazine, The Great Energy Bust in the United States, 

natural-gas wellhead prices in 1982 were $2.46 per Mcf 

(thousand cubic feet), but by 1992 the price had declined 

over 50 percent to $1.16 per Mcf. 

One would think that under these marketing conditions-low price, an environmentally clean product, and 

aggressive advertising--executives in the gas industry 

would view the gas market with enthusiasm. Many do, but 

they are unwilling to commit funds to drill new wells at 

current prices. I believe that competition among energy 

sources will have a significant influence on the consumers' 

decision to switch fuels or select natural gas as the fuel of 

choice. In spite of the environmental benefits of natural 

gas, the P,ricing strategies of suppliers who sell coal, oil, 

799 
800 THE FUTURE OF ENERGY GASES 

electricity, and gasoline could delay the increase in demands for natural gas in the near term. 

DEMAND FOR NATURAL GAS 

Let's examine the issues that customers think about 

when making a fuel decision. First, consider certainty of 

price. Industrial customers consume huge quantities of energy-primarily oil, coal, and electricity. For environmental reasons, industrial plant-combustion facilities are 

carefully engineered and designed for the fuel used. Likewise, the processing equipment to heat-treat a manufactured item is carefully engineered with the material and 

heat source in mind. Fuel costs may represent only 15 to 

25 percent of the manufacturing cost, but the cost of 

changing to a new fuel is substantial. Not only does the 

cost of the new gas-fired equipment need to be considered, 

but the space and size of the equipment could require 

changes in floor layout and building size. For industrial 

plant owners, these conversion costs can amount to millions of dollars. Customers will therefore need to be convinced that fuel-cost savings from natural gas will be 

sufficient to recover the expense of conversions. 

Also of concern to customers are profitability and how 

long their manufactured products will be competitive in 

the marketplace. These issues are often so complex that 

industrial customers will choose to stay with current energy sources, even though natural gas could do the job more 

efficiently and at a lower cost. This is particularly true 

when suppliers of coal, oil, or other fuel give customers 

better terms or a better price to keep from losing sales. 

The assurance of long-term supplies is almost as important to the consumer as the price of natural gas. This 

issue is a common selling point of competitors who are 

trying to sell oil and coal to new factory or electric generating plants. Projections by the U.S. Geological Survey, 

American Gas Association, Department of Energy, and 

other agencies suggest reserves of proved, probable, and 

possible natural-gas .supplies are adequate for expected demands in the United States for the foreseeable future. Actions by the U.S. Government to select natural gas as a 

cornerstone of the national energy policy also suggests the 

evolution of programs to encourage the development of 

long-term gas supplies. Concerns about the future availability of foreign suppli~s of natural· gas would be lessened by 

the pending North American Free Trade Agreement. The 

agreement will allow natural gas to be sold and delivered 

across the Canadian and Mexican borders without government intervention. While I believe that natural-gas reserves 

are abundant, unfortunately some customers still remember 

shortages in the 1970's and especially the curtailments of 

gas service during the cold winter of 1989. 

The public is increasingly concerned about the environment. The no-growth and NIMBY (not in my backyard) 

activists are especially skilled in using environmental issues to inhibit the growth of demand. Although employees 

in the gas industry are actively promoting natural gas as an 

environmentally clean fuel, they have been unable to convince the public that exploration, production, and refining 

activities will not result in a large-scale environmental catastrophe. This lack of public trust often results in pipeline 

construction delays. Natural-gas regulations can potentially 

create other problems for customers. For most fuels, there 

are alternative suppliers to turn to if you can't get a particular fuel or if you are unsatisfied with the service. This is 

not so for natural gas. For the end-use customer who uses 

gas at the burner-tip, the natural-gas industry is regulated. 

Over 90 percent of the natural gas consumed in the United 

States is distributed locally to customers in a pipeline network owned by private and municipal utilities. Each utility 

serves the consumer under a franchise, issued by the local 

city council or county government. A franchise gives the 

utility the exclusive right to build, distribute, and sell natural gas for a number of years, often 20 or more. These 

arrangements are regulated by local and state public-utility 

agencies. The skill of state public-utility commissioners in 

regulating natural gas and electric utilities is commendable 

given the complex nature of the industry and the political 

arena in which the process functions. Regrettably, local issues and public involvement regarding growth, environment, and (or) safety often act as a deterrent to expanding 

the system, which would otherwise accelerate the shift to 

using more natural gas. 

Another issue the gas explorationist has to be aware of 

is the transition of pipeline regulation in the gas-supply 

chain. As pipeline deregulation takes place at the national 

leveJl'(under FERC Order 636), the merchant function is 

shifting away from the system in which natural-gas producers sold gas directly to the pipeline to a new system in 

which producers sell directly to utilities and other end-use 

customers. At the same time, the producers have had to 

accommodate buyers who want to buy gas on short-term 

"spot" contracts as compared to the historical 20-year, 

long-term contract. 

Often the inability to adapt to these rapid changes in 

the energy market limits the ability of small producers to 

compete effectively for consumers in the downstream market or to attract investors to fund natural-gas exploration 

and development activities in the upstream segment of the 

industry. 

Producers will benefit in the future because customers 

are becoming increasingly more aware of the opportunities 

to use more natural gas. Gas prices are an excellent energy 

value compared with the cost of other available fuels. 

However, the uncertainty of long-term natural-gas supplies 

and prices could deter many existing large energy consumers from making the investment to convert from their current fuel to natural gas. Environmental regulations could 

mandate the use of natural gas in existing plants. More 
NATURAL GAS AND THE ROLE OF COMPETITION IN THE UNITED STATES 801 

stringent air-quality regulations will encourage the selection of gas in new plants. The skilled explorationist who is 

able to anticipate consumer needs for long-term supplies 

at competitive prices will have an exciting future. 

ISSUES AFFECTING THE SUPPLY OF 

NATURAL GAS 

The challenges facing explorationists are often viewed 

in three segments. One challenge is identifying the optimum surface locations to drill. The second is obtaining the 

legal permission to drill for and produce from new wells. 

The third challenge is drilling and producing wells to 

make acceptable profits. 

Improved techniques in gathering and processing vast 

quantities of technical information have allowed explorationists to accurately locate likely sites of new oil and natural-gas reserves. These techniques allow geologists and 

geophysicists to find new reserves at deeper horizons and 

to look at old producing fields for bypassed traps. 

New techniques and equipment to drill, complete, and 

produce oil and gas wells are being exploited almost as 

quickly as they are developed. The ability to fracture formations more effectively, and to use new horizontal drilling 

techniques to interconnect fractures in low-deliverability 

fields, will often provide economic returns where older 

techniques would have resulted in an unprofitable dry hole. 

In 1984, according to Arthur Andersen in its publication, Oil and Gas Reserve Disclosure, the industry replaced 105 percent of the natural reserves produced. 

"Finding Costs of Exploration" ranged from $5.05/boe 

(barrels of oil-equivalent, with gas at 6 Mcf per hoe) for 

majors to $9.62/boe for non-majors. Seven years later, in 

1991, the report stated the industry had replaced only 94 

percent of the produced natural gas reserves. The weighted 

average replacement costs were $5.98 per hoe. It should 

be noted the industry did not replace all of the oil and 

natural .gas produced during the year but the reserves that 

were replaced, were done so at about the same cost. 

Profit margins have disappeared for many explorationists because of lower gas sale prices and higher administrative costs. Over the past 10 years, the upstream segment 

of the oil and gas industry has changed dramatically. Of 

the estimated 25,000 oil and gas operators that existed in 

1982, only about 7,000 remain in business today. Industry 

jobs dropped from 708,000 in 1982 to 390,000 in 1992. 

The primary factor affecting the industry during this period was a 50 percent decline in oil and gas prices. 

To reduce the cost for finding and producing new reserves of natural gas, the explorationists of the future need 

to be on the cutting edge of new technology. Management 

needs to be informed and skillful in complying with the 

increasing number of environmental, safety, and tax regulations enacted by Federal, state, and local agencies. The 

employees also need to be creative and diligent in their 

efforts to assemble acreage and negotiate drilling contracts. 

Finally, executives need to plan ahead and be persistent. 

One of the important business matters for the company is the acquisition of the rights to the oil and gas from 

the mineral owner. It may take years to locate. mineral 

owners and to negotiate favorable terms for the oil and gas 

lease. These terms will include payments for royalty and 

damages as well as access for the drilling equipment, pipeline, roads, and production facilities. Later on when the 

leases are combined into federal units or consolidated arid 

pooled for operating or risk-sharing reasons, changes in 

the lease tef!US may be required from the owners. Because 

the mineral owner of the oil and gas has no out-of-pocket 

investment in drilling the well and pays none of the operating costs, the percentage of royalty payment and other 

payments have a significant economic impact on the operating profit of the well. 

Taxes are another cost of doing business. All states 

levy severance taxes on the proceeds from production. 

Counties levy ad-valorem taxes on the value of the lease 

equipment. Franchise and sales taxes may be added at the 

point of sale. Business and occupation taxes are levied 

along with employee taxes. Taxes can quickly add 35 percent to the cost of doing business. Tax credits, such as the 

Section 29 Nonconventional Fuels Production Credit, can 

be useful. Often, however, those who most need the tax 

relief are the ones who do not have a profit or have profits 

that do not meet alternative minimum tax thresholds. 

In the end, explorationists and investors must carefully 

value profits versus the costs and risks of being in business. In this analysis, consideration should be given to 

customers, employees, and shareholders. Owners benefit 

from increasing profits, which result in higher stock values 

and dividends. Employees benefit through the company's 

compensation package, which includes salary and benefits. 

Usually in periods of lower gas prices, customers will benefit most and the shareholders least because of lower profit 

margins. Many employees have been the unfortunate victims of corporate downsizing and bankruptcies as a result 

of the dynamic refocusing taking place within oil and gas 

industry. 

Increasing demands for natural gas in the future will 

result in exceptional opportunities for the industry. This 

alone does not guarantee that customers, owners, or employees will prosper. Those explorationists with a keen 

awareness and knowledge of the business together with a 

proven track record will gain most from the shift to natural gas. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Reflections After 62 Years of Exploration 

By Michel T. Halbouty 1 

A recent National Petroleum Council (NPC) study estimates the recoverable natural gas resource base of the lower 

48 States at 1,295 Tcf (trillion cubic feet). This is more than 

a 60-year supply to meet estimated future demand growth. 

The NPC study concludes "the natural gas resource base is 

abundant and can be produced and developed at prices that 

allow both an expansion of the marketing and continuing 

development of the resource." This bullish estimate reinforces the long-accepted view, by those who have searched 

for and produced gas, that supply is plentiful, the future is 

bright, and all we need to do is explore. 

Exploration for oil and gas has evolved rapidly during 

petroleum geology's history. Many theories have been proposed, accepted, tested, and later exchanged for newer 

ones, in all aspects of oil and gas exploration. The history 

of petroleum geology, and exploration attitudes associated 

with it, has a broad base, developed by scientists and nonscientists alike. 

As early as 1842, 1 7 years before Col. Edwin L. 

Drake's well in Titusville, Pennsylvania, signaled the birth 

of the oil industry, Sir William Logan studied oil springs 

at Gaspe in his native province of Quebec, Canada. He 

concluded that the oil springs were located near and associated with anticlinal folding. My research indicates that 

Logan's written comments on the seeps were the first expression of the anticlinal theory of oil accumulation. By 

1860, this theory was a prominent, controversial topic in 

geology. Early proponents of the theory, such as J.P. Lesley, first championed the theory but later denounced it. 

Three years later, wildcatter John Galey and William A. 

Erseman, two Pennsylvania oil operators called Dr. Israel 

C. White to their field. Their drilling observations suggested that there definitely was some relation between existing 

gas fields and anticlines. Although White had previously 

1

Michel T. Halbouty Energy Co., 5100 Westheimer Rd., #500, 

Houston, TX 77056. 

written two papers extolling the virtues of the theory, he, 

also, later rejected it. 

After visiting with Galey and further surface studies, 

White, desperate to prove the theory to his own satisfaction, formed a company and drilled a well on a surface 

anticline to test the theory. The result was the discovery and 

establishment of the first significant oil production in West 

Virginia. White then announced his rediscovery and acceptance of the anticlinal theory, proving also, that nothing 

succeeds like success. 

All of our knowledge about oil and gas exploration 

was not gained from scientists. The nonscientists, the nonprofessionals, and the wildcatters who applied common 

sense, courage, and stubbornness in the search for oil 

added much to our vast store of geologic knowledge. 

Often, the wildcatter's approach was not very scientific. 

Random drilling based on surface seeps was more the rule. 

Drake made his famous discovery in 1 859 near Titusville, 

Pennsylvania, on the basis of surface seeps. 

The great discovery of Spindletop in 190 I was the result of the faith of one man, Patillo Higgins, who interpreted several surface observations as indications of a 

good drilling site. Yet the respected geologi.sts of that time 

rejected the prospect as unworthy of exploration. They 

surmised that the unconsolidated sands in the Gulf Coast 

would not be favorable to the origin and accumulation of 

oil. The discovery of Spindletop ushered in a new era of 

exploration. Surface indications like those found at Spindletop became guidelines used in the search for other salt 

domes in the Texas Louisiana Gulf Coast region. 

The petroleum geology profession was just beginning. 

During these early days, management relied primarily on 

conceptual skills of geologists to identify drillable prospects. Imagination and vision were the prime guides, and 

these were stimulated by our senses. The basic exploration 

technique was to study the surface, seeps of whatever nature, and other unusual surface conditions. During this period geologists had little difficulty locating places to drill. 

803 
804 THE FUTURE OF ENERGY GASES 

Anticlines, surface faults, and even some buried salt domes 

were easy to locate. Many outcrops and other surface features indicated drilling prospects. Gradually, prospects 

which could previously be seen on the surface, became less 

and less obvious and exploration dramatically decreased. 

Then, when a real breakthrough was needed, geophysics appeared. Geophysical techniques were tremendously 

successful. The torsion balance and refraction seismograph 

were introduced during the early 1920's. These new tools 

brought instantaneous and remarkably successful results to 

exploration efforts. By the early 1930's, the reflection seismograph had been introduced to aid in exploration. The 

phenomenal success of this instrument in imaging subsurface structures resulted in worldwide acceptance of geophysics and relegated other exploration methods to minor 

roles in the search for petroleum. 

After a series of spectacular successes, many management groups believed that these new geophysical and electronic instruments had, at last, solved the problem of 

finding new reserves. At first, these developments suggested the geologist as an explorationist might become obsolete. From the early 1930's to the late 1960's, any anomaly 

conceived through geologic thinking was submitted to the 

seismograph and was classified as drillable only after the 

"black box" confirmed it. For a while, the black box completely replaced the brain. 

But in the early 1970's, prominent structures became 

harder to find and many of the small seismic anomalies that 

suggested stratigraphic traps proved to be dry. Many explorationists found themselves presenting only data they could 

positively defend before, and after, the prospect was drilled. 

It is unbelievable that even today there are some exploration managers who still insist on drilling only structures, 

avoiding every other trap concept. Unfortunately anyone 

submitting and recommending a wholly stratigraphic prospect was considered radical. Management would accept 

only the structural prospect, however weak the basis for the 

structural interpretation. It is sad to reflect on those years in 

which the geologist was subjected to ordinary and, sometimes, menial assignments. During this period new geologic 

thinking was rare. Stagnation set in-the electronics were 

doing all the thinking and recommending. 

We, as students of the Earth, must bear in mind that 

from the beginning, geology has grown and advanced on a 

balance scale of probability rather than in the rigid, less 

flexible framework of mathematics. Geology has always 

been an inexact, speculative science-depending at times 

wholly on sheer geologic deductions. Commonly suffering 

from speculation beyond the limits of observation and experience, geologic hypotheses and theories have been proclaimed and later disregarded, but not without some benefit 

to each succeeding generation of earth scientists. 

It is precisely this inexactness of geology that makes it 

such a great challenge. It takes real courage to meet this 

challenge and keep the science of geology always in the 

forefront of our thinking. However, we have failed many 

times in the past to use geology properly. We depended 

too much on other disciplines to guide us and did not 

practice geology as we should have. As a result, we became less creative and less courageous. We became afraid 

to express ourselves unless we had the perfect closure. 

We kowtowed to and became dependent on the black 

electronic boxes and transistors and failed to rationalize 

for ourselves. Those black boxes and transistors are and 

will continue to be a vital part of our methodology, but we 

should have made them only a part and not the whole. Our 

dependence led to routine thinking, without probing and 

seeking to better understand the true meaning of geology. 

We became afraid to experiment with an unusual concept 

or idea. This should never happen again. 

Although technology has expanded into all areas of 

the industry, for the most part, our exploration efforts have 

been constrained by the overwhelming attitude of complacency in using only the tried, tested approaches. As a profession, we ignored, or delayed, our participation in new 

advances. At last, however, we are beginning to catch up. 

We are looking to the future with more clarity of mind 

and determination than ever before. For example, it is remarkable how remotely sensed images from Landsat are 

changing our thinking about areas for exploration. Remote-sensing data has shown us that even mature producing regions yield intriguing new possibilities for future 

exploration. 

New concepts are leading to new discoveries in areas 

previously considered unfavorable. The Rocky Mountain 

Basins, classified as mature, are now enjoying a resurgence 

in exploration because of new geoscientific concepts and a 

greater understanding of tectonics. For example, it took the 

industry 125 years before wells in the Rocky Mountain 

region were drilled through Precambrian rocks-igneous 

rocks, mostly granite-into sedimentary sections that are 

concealed and virtually unexplored beneath mountain-front 

thrusts. 

Petroleum has been found under the Precambrian mantle, which has encouraged leasing and seismic data acquisition on every mountain-front thrust in the Rockies. Millions 

of acres remain to be tested in these areas of resource potential. I don't think there exists a geologist who, 15 years 

ago, would have recommended to management drilling 

through 8,000 to 10,000 feet of granite to reach underlying 

sedimentary rock. But this is becoming commonplace now. 

Mature basins offer explorationists many opportunities to 

search for and discover substantial reserves of new petroleum. I still consider them areas of great potential where 

exploration wUI continue to show positive results. 

More optimism, enthusiasm, and daring is needed in 

the field of wildcatting. Daring is the vital word. This 

means we must have . the drive to drill unconventional 

prospects. We must be innovative and more creative· by 

using our most important tool-the brain. 
REFLECTIONS AFfER 62 YEARS OF EXPLORATION 805 

In this regard, it is strange that we pay so little attention 

to new ideas in a deliberate search for those reserves that 

lie in subtle traps. Finding the elusive traps requires highly 

imaginative thinking combined with every applicable scien_-

tific discipline. The geophysicists' computers and new chart 

mechanisms are tremendous aids in illuminating some of 

the scientific facts needed for finding subtle traps. Great 

advances have been stimulated through seismic modeling, 

better data acquisition, more advanced data processing, and 

the extensive use of color seismic display formats. But 

these kinds of data are just part of a broader analysis and 

must remain just that in our search for the subtle traps. 

Other important aspects of the search for the subtle 

trap are evaluations of the source and kind of sediments, 

facies changes, geologic history, tectonic control of sedimentation, and kinds of environmental conditions present 

when sediments were deposited. These evaluations are 

vital to the search for the stratigraphic and other subtle 

traps. In other words, plain geologic thinking is needed. 

We have accomplished more in the past few years to 

revitalize geology in the search for petroleum than ever 

before. Because of this revitalization, we are creating more 

new concepts and ideas on where to look for oil and gas 

in places previously considered unfavorable. By doing so, 

we are being highly imaginative and seeking new knowledge through ingenuity. Although we may have failures 

and wrong turns, we must continue to ferret out new ideas 

and add them to our understanding of geology. 

Unless we think creatively and boldly as scientists, 

without fear of honest mistakes, and by so doing create 

new concepts and use them, we will never be able to meet 

the challenges of the future. The key to a new exploration 

philosophy is to become comfortable with and put into 

practice those unusual, unconventional ideas and concepts, 

which we have been too afraid to even think about. 

The vital characteristics an exploration geologist must 

possess to succeed are strength of conviction and reliance 

on one's own geologic deductions, however strange or far 

out they may be. 

As one of the great petroleum geologists, Wallace 

Pratt, so aptly put it, "oil is found in the minds of men." 

So if you want to be a successful explorer, never forget 

the wisdom behind that observation. 

Regardless of the amount of natural gas that will be 

discovered in the future, the quantity will depend on the 

number of wildcat wells drilled in search of new reserves. 

Most of the natural gas produced in the United States is 

from wells that are 12 years old or older, which underscores 

the urgent need for new drilling programs. Yet, the restrictions and regulations imposed on wildcatting are so severe 

that the large operators have gone overseas to explore and 

the independents have been so decimated that there are no 

incentives left for them to "wildcat." Most new wells drilled 

in the United States during the past few years are "infill" 

locations drilled between existing producers where there are 

no risks and successful completions are virtually guaranteed. 

Although the potential domestic gas reserves are evident, it will be a long time before this potential is brought 

to the surface and even then the new supply could be insufficient to meet our growing consumption demand. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

New Thinking About Natural Gas 

By Robert A. Hefner III 1 

CONTENTS 

Abstract . .... ..... .. ....... ... . ...... .. ... ... ...... ... ....... .. .. .. .... ... . .. .. . . 807 

Introduction . .... . . ... .. ............ ... .. . ... . ..... .... . . . .. .... .. . .. .. . .... . .. 808 

Some Preliminary Observations ................................... 808 

Natural Gas-A Distinctly Different Fuel ................... 808 

Blinders of the Past ...................................................... 811 

The Natural Gas Resource Base of the 

United States ................................................................. 815 

The Anadarko Basin .............................................. 817 

A More Optimistic View of the Natural Gas 

Resource Base . ... .. ..... ........ .... .. .. . ... .. ... ... .. . .... .. .......... .. . . 823 

The Gold Hypothesis .................................................... 825 

Conclusions ... . ..... .. .. ......... ..... . .. . .... ........ ... . .... . . .. ... .. . .. .. . . 826 

References ... . ... .. ...... . .......... .... ... . .. .. ........ ... .. ... .. .. ... .. ... .. . 827 

Appendixes ................................................................... 829 

ABSTRACT 

This paper is about opening our minds to natural gas. 

Though conventional thinking holds that commercial natural gas resources rank third behind coal and oil, recent 

studies require that this thinking be challenged. Even 

today our view of natural gas is permeated by a type of 

thinking that has grown out of the historical close association of natural gas with oil. This "oil thinking" has created 

a generally accepted perception, even among professionals, that often impedes research, development, innovation, 

and implementation of much needed new ideas in the 

realm of natural gas. 

1

Robert A. Hefner III, The GHK Company, 3030 Northwest Expressway, 18th Floor, Oklahoma City, OK 73112-5467. 

Even though estimates of the natural gas resource base 

recently have been revised upward, to the range of 1200 to 

1500 Tcf, they are 1>till overly conservative. My estimate 

of potentially available natural gas resources, based on accepted theories of the origin of oil and natural gas, forecast the U.S. natural gas resource base to be within the 

range of 3,000 to 4,000 Tcf. I believe that this significantly 

larger natural gas resource base can be developed at prices 

within reasonable economic limits using both in-hand 

technology and technological innovations likely to be 

available soon. 

On the basis of a large natural gas resource base and 

other information presented here, I predict (I) that in the 

United States natural gas will remain an affordable and 

reliable fuel beyond the middle of the 21st century, (2) that 

natural gas will replace oil as the United States principal 

energy source, (3) that the only limits to the use of natural 

gas will be well in the future when C02 emissions from 

natural gas could possibly begin to exceed limits set by 

future global warming treaties, and (4) that to use natural 

gas as a principal energy fuel will be exceptionally beneficial for both developed and developing economies and 

therefore a great catalyst to the growth of the global economy in a manner that will significantly improve the environment. In developed economies, increased use of natural gas 

will reduce coal and oil pollution and lower the rate of 

addition of carbon dioxide to the atmosphere while enhancing economic efficiency and productivity. In developing countries, the use of locally derived natural gas will 

reduce the capital required to produce the energy necessary 

for economic growth while allowing these countries to 

conform to global environmental goals. 

The world is now entering "the age of energy gases," 

which will progress toward an environmentally benign energy system that will allow civilization, for the first time, to 

sustain economic growth within a clean global environment. 

807 
808 THE FUTURE OF ENERGY GASES 

INTRODUCTION 

Natural gas, composed principally of methane (CH4), 

may well be the world's most abundant hydrocarbon, possibly exceeding in amount both coal and oil (U.S. Geological Survey, 1992). Though conventional wisdom holds that 

commercial natural gas resources rank third behind commercial coal and oil, recent studies of the origin of natural 

gas, the abundance of methane in the solar system, the pervasive nature of natural gas in the Earth's lithosphere, and 

the vast quantities of methane trapped in gas hydrates require that this old thinking be vigorously challenged. 

The thoughts I present here concerning natural gas are 

both simple and radical. I think that commercial natural 

gas is vastly more abundant than even our most optimistic 

estimates suggest and that our limited view of the potential of this fuel is based in our insistence on holding to the 

historical mind set of the association of natural gas with 

oil. Throughout most of its history in the United States, 

natural gas has been found principally in geologic and economic association with oil. Until the 1970's, natural gas 

was considered by most a nuisance or, at best, a by-product of oil with little intrinsic value. But understanding the 

real quantities of economically recoverable natural gas that 

exist in the Earth lies far beyond accepted concepts of the 

physical, chemical, technological, and economic limits of 

oil. Until we break the mental bonds that tie us to these 

oil-related ideas, we will be unable to foresee the real future of energy gases. To discern that future, we need a 

radically new paradigm for natural gas resource thinking 

and an intense focus on research and development to test 

the ideas that arise from this fresh and fertile perspective. 

One of the main theses of this paper-that our view of 

natural gas is permeated even today by thinking that grew 

out of the close association of natural gas with oil-is 

based in an historical view of the development of hydrocarbon fuels. During the past decade, this view of natural gas 

has begun to change. However, my purpose here is not to 

address the cutting edge of natural gas science and t~chnology, it is to speak of the inertia, resulting from decades of 

focus on oil, that impedes more rapid development and 

implementation of new ideas in the realm of natural gas. I 

will also show that thinking from a perspective based in 

natural gas rather than oil supports a far more optimistic 

view of the natural gas resource base than is suggested even 

by the most recent, higher estimates of such agencies as the 

U.S. Department of Energy (DOE), the National Petroleum 

Council (NPC), and the Gas Research Institute (GRI). 

The observations and arguments that support this view 

come from a lifetime devoted almost exclusively to natural gas exploration and production and, equally important, 

not to oil. It is a view deeply grounded in experience as 

well as theory, intuition as well as science, logic as well as 

fact, and it has been formed in a marketplace where ideas 

mean little until they have been tested in practice. The 

ideas contained herein are an outcome of that testing. 

Wallace Pratt once said that "oil is found in the minds of 

men." If this is accurate, and I hold no doubt that it is, 

perhaps it is time that we recognize that natural gas also is 

found in the minds of men and women, and that to find more 

we need to free our vision from the bounds of oil so we can 

think natural gas. In my opinion, this volume is a major 

move in that direction. This paper is designed to highlight 

some of the changes in thinking that my experience with 

natural gas has convinced me we must now make, as well as 

to inspire new ideas about natural gas in the minds of the 

men and women in whose hands our energy future lies. 

SOME PRELIMINARY OBSERVATIONS 

Methane-the major component of natural gas-is the 

simplest and most stable of the hydrocarbon molecules. It 

is a major component of the atmospheres of Jupiter, Saturn, Uranus, Neptune, and Pluto and the planetary satellites 

Titan and Triton. On Earth, large quantities of methane 

exist in the crust. Of the various known sources of methane, the most abundant occurs in the form of methane hydrates in the sediments of ocean basins and within the 

permafrost of polar regions (see Kvenvolden and also Collett, this volume). Recent estimates of the quantity of natural gas held in these hydrate deposits range from 13xl03 

trillion cubic feet (Tcf) to 26xl06 Tcf (Kvenvolden, 1988). 

Although much of this gas hydrate resource may be noncommercial in the foreseeable future, natural gas has been 

produced from hydrates on the Yamal Peninsula in Russia 

(Gustavson Associates, Inc., 1992; Collett, this volume). 

Although methane is always associated with oil and coal 

deposits, it is also found in many other habitats: (1) Methane 

leaks from most of the Earth's surface rocks and oceans; (2) 

it is found in swamps, landfills, and the stomachs of animals; 

(3) methane is found in diamonds (Melton and Giardini, 

1974), which form at ultra-high pressures and temperatures, 

presumably at great depths in the Earth; and (4) it occurs, in 

quantity, in geologic domains where oil is relatively rare or 

absent, such as within fold and thrust belts (Howell and 

others, 1992), in some large basins such as the West Siberian 

and San Juan Basins, and at depths below 15,000 ft. Natural 

gas has been found at depths of 21 ,000 ft in the granitic rocks 

of Sweden's Siljan meteorite impact crater, of 31,441 ft in 

Oklahoma (the Lone Star-GHK Company Bertha Rogers 

No.1 well was spud on November 25, 1972, and completed 

on August 14, 1974), and of over 40,000 ft on the Kola 

Peninsula in Russia (USSR Ministry of Geology, 1991 ). 

NATURAL GASA DISTINCTLY DIFFERENT FUEL 

In the past, the commonly accepted assumption has 

been that oil and natural gas are similar substances, traveling together along parallel paths from origin to production. 
NEW THINKING ABOUT NATURAL GAS 809 

This is neither surprising nor unreasonable as oil is rarely 

found without associated natural gas, and these fuels, in 

the past, have been explored for, produced, transported, 

and marketed by what is frequently perceived as a singular 

and monolithic enterprise-the oil industry. However, natural gas and oil are not the same; natural gas is as different from oil as oil is from coal. And natural gas occurs in 

large quantities unassociated with oil. The natural gas industry is now emerging in its own right as completely separate from the oil industry. As this emergence progresses, 

more people are recognizing the distinct physical, chemical, and geological differences between oil and natural 

gas, differences which produce equally distinct economic, 

environmental, technological, and political effects. Each of 

these differences and effects are discussed below: 

1. Physical character: Methane is a gas that is lighter 

than air; oil is generally a viscous liquid that is lighter 

than water. Oil, as we know it, is virtually destroyed at 

temperatures that exceed 150°C at low pressure, whereas 

methane is found throughout the Earth's crust at temperatures to at least 800°C. These figures indicate that methane 

can exist to significantly greater depths in the crust than 

can oil. Kerogen profiles from deep wells in Oklahoma's 

Anadarko Basin indicate that natural gas could be present 

at a depth of 60,000 ft (Hefner, Kinchloe, and Wheeler, 

1973), whereas little oil is found below 12,000 ft and virtually none below 15,000 ft. 

2. Chemical composition: Methane, the primary component of natural gas, is the simplest of all hydrocarbons, 

containing one carbon and four hydrogen atoms (CH4). 

Approximately one-half of the energy from burning methane comes from carbon and one-half from hydrogen. Oil, 

on the other hand, is a mix of very complex long chain, 

and simpler, hydrocarbons. When burned, oil derives 

· about three-quarters of its energy from carbon and only 

one-quarter from hydrogen. Coal derives nearly 100 percent of its energy from carbon. 

3. Geologic occurrence: Natural gas can be, and seems 

to be, ubiquitous in the Earth's rocks, occurring in commercial quantities in strata as old as, and occasionally older 

than, 600 m.y. Though frequently found in traps of limited 

extent, natural gas virtually permeates the deeper parts of 

some basins, such as the Anadarko Basin (discussed 

below) and the Alberta Basin (Masters, 1979). Oil, on the 

other hand, is geographically, geologically, and physically 

limited in its occurrence and commonly accumulates in 

unique traps under normal pressures at depths less than 

10,000 ft in relatively young rocks. More than one-half the 

world's oil, for example, occurs in rocks younger than Jurassic, or less than 180 m.y. old. About 60 percent of the 

world's known oil reserves lie beneath less than one percent of the Earth's surface in the Middle East (World Oil, 

1992); 7 percent is concentrated in the Ghawar field alone. 

Many of the world's largest natural gas fields contain relatively small amounts of oil, whereas all of the world's 

large oil fields contain significant quantities of natural gas. 

4. Economic considerations: Until the early 1970's, except in a few limited cases, natural gas was considered at 

best a marginally economic by-product of the oil industry. 

Only during the past 20 years has natural gas achieved 

independent economic value, whereas oil has maintained 

significant intrinsic value as an important, easily traded, and 

readily transported energy commodity since the 1920's. 

Conversely, the large-scale natural gas transmission system 

of the United States was built after World War II. Today, 

however, natural gas is the fastest growing fuel in the world, 

whereas oil use has barely fluctuated over the past 10 years 

(International Energy Statistics Sourcebook, 1992). 

5. Environmental differences: Natural gas is the cleanest burning hydrocarbon, a reflection of its simple chemical 

composition and low carbon content. Although natural gas 

is usually grouped with coal and oil as a "fossil fuel" by 

those concerned with the environment, the use of natural 

gas produces significantly fewer of the atmospheric pollutants associated with coal and oil. The burning of natural 

gas, for example, produces 25 percent less carbon dioxide 

than oil and 50 percent less than coal. Indeed, a natural-gas 

fueled vehicle, compared to an average gasoline-fueled vehicle, emits 24 percent less carbon dioxide and nearly 90 

percent less reactive hydrocarbons and carbon monoxide 

(American Gas Association, 1991), which are the main 

contributors to the photochemical smog that pollutes most 

of our cities. An advanced natural-gas-fueled combinedcycle electrical generation plant emits 50 percent less carbon dioxide and 80 percent less nitrogen oxides than a 

conventional oil-fueled plant and 65 percent less carbon 

dioxide and 99 percent less nitrogen oxides than a 

scrubbed coal-fueled plant (Flavin, 1992); unlike coal-and 

oil-fired electrical plants, a natural gas plant emits no sulfur dioxide, eliminating a major cause of acid rain. 

Methane is a greenhouse gas, and leakage from the 

natural gas production and distribution system must be 

taken into account in any calculation of the contributions 

that increased use of this resource will have on problems 

of atmospheric contamination. However, as the intrinsic 

value of natural gas to the economy increases, the new 

infrastructure that develops will have insignificant leakage, 

especially compared to the current loss of methane from 

the production and handling of oil and oil products and 

from coal mining operations. Controls for the prevention 

of methane leakage from oil and coal sources are meager 

or nonexistent because the need for such controls has been 

largely ignored. Methane is also added to the atmosphere 

from natural surface seeps, ocean vents, rice paddies, wetlands, landfills, and the stomachs of animals. 

6. Technological possibilities: Historically, during the 

initial years of economic development of an energy 

source, the technology associated with it experiences exponential growth, economic efficiency is enhanced, productivity increases, and a new long wave of economic growth 

is unleashed. In the 1840's, exponential growth of coalrelated technologies (for example, the steam engine, the 
810 THE FUTURE OF ENERGY GASES 

substitution of coke for charcoal, and coal-related innovations in the steel industry) and the resulting increase in 

economic efficiency and productivity became the catalyst 

for the Industrial Revolution. In the late 1920's, a similar 

period of technological innovation related to oil (for example, the rotary drill bit, advances in exploration and refining; and improvements in the internal combustion engine) 

fueled the economic growth that led to the developed economies we know today. Oil technology has now reached the 

mature phase. However, natural gas is just beginning its 

wave of exponential technological innovation, a result of 

the relatively recent recognition of its intrinsic value. As 

natural gas continues to increase in value to the economy 

and gain an increasing share of the energy market, we can 

expect an acceleration of technological innovation at all 

stages of natural gas production, from exploration to end use 

(for example, "nonconventional" production of natural gas, 

natural gas vehicles, and natural gas fuel cells). This may 

soon lead to a 50 percent or greater increase in overall efficiency in the exploration to consumption cycle for natural 

gas (Nakicenovic, 1990, and this volume; Mills, this volume), an increase which, in turn, may bring extraordinary 

100 

Iw 

~ 

a: 80 

<( 

~ ··\~~~h. 

_J 

~ 0 60 

ILL 

0 

w 

C) 40 

~ z 

w 

() 

a: 20 

w 

a.. 

0 ,.,.,.,.,.,.,.,,,,,,",,,.,.,,,,,,,.,.,.,,,.,,.,,.,,,.,,,.,.,,,,,"''''' 

1850 1900 

Figure 1. Primary energy sources for the United States, showing 

how successively cleaner, more efficient primary energy sources 

replace existing sources. Thin lines represent actual consumption. 

Thicker lines are mathematically fitted to these curves in the hiseconomic and environmental benefits to society. As natural 

gas use increases, our economy will be more able to maintain sustained growth. 

7. Political aspects: In the United States, natural gas has 

been significantly more regulated than oil and coal. For 

decades, governmental policy has heavily favored oil and 

coal over natural gas. This government intervention has 

caused natural gas to be the only fuel used in smaller quantities in the United States today than in the early 1970's (see 

Fanelli, this volume). Primary energy substitution curves 

(fig. 1) for the United States clearly show how market forces 

drove the orderly transition of energy sources from wood to 

coal to oil for nearly one century. Notice, however, the 

diversion from this pattern beginning in the 1970's. At that 

time, government intervention, which favored coal, oil, and 

nuclear power, created artificial shortages of natural gas and 

disrupted the historically predictable transition to natural 

gas. In 1978, Congress, overreacting to the artificial shortage, legislatively prohibited the use of natural gas for new 

electrical generation plants, and discouraged the use of natural gas in all markets. As a result, most U.S. citizens believed that natural gas was no longer a viable fuel and 

Period of massive 

government 

intervention in 

U.S. energy markets 

~ 

1950 

YEAR 

2000 2050 

torical portion of the chart and projected into the future. The decline in consumption of natural gas since the mid 1970's represents 

a cumulative drop in consumption from that period of approximately 59 Tcf. From Hefner (1993). Copyright, 1992, GHK Company. 
NEW THINKING ABOUT NATURAL GAS 811 

nearly all of the increasing demand for electricity was generated from less efficient, dirtier, and costlier new coal- and 

nuclear-fueled power plants. 

Using 1973 as a baseline, the total amount of additional electricity produced from coal and nuclear plants 

could have been generated by using 40 Tcf of natural gas 

(based on figures from the Energy Statistics Sourcebook, 

1992), a quantity that was readily available as shown on 

figure 1 by the 59 Tcf cumulative decline in natural gas 

consumption. The misperception of a limited natural gas 

resource base, resulting principally from the direct association of natural gas with oil, led to an energy policy that 

caused the United States to become the only developed 

economy in the world to reduce its use of natural gas. Between 1970 and 1989, U.S. natural gas use declined by 11 

percent. During this same period, countries as diverse as 

England (based on figures from the International Energy 

Statistics Sourcebook, 1992, and Jenkins, 1977) and Bangladesh (Janet Rains, GHK Company, oral commun., 1992, 

from an official of the U.S. State Department) increased 

their natural gas usage by over 20 percent. The energy 

policies of the U.S. government during this time cost the 

U.S. economy more than a trillion dollars in unnecessary 

capital expenditures to generate more costly electricity and 

created significantly greater environmental damage than 

would have resulted from the use of natural gas. This 

wasted capital, which was used to convert less efficient 

coal, oil, and nuclear fuel to electricity at higher overall 

costs and additional external expense, lowered U.S. economic productivity and reduced our potential to increase 

and sustain economic growth. 

BLINDERS OF THE PAST 

To quote from Daniel Yergin's epic account of the oil 

industry: "Oil is the world's biggest and most pervasive 

business, the greatest of the great industries that arose in 

the last decades of the nineteenth century * * *. The expansion of the business in the twentieth-century embodies 

the twentieth-century evolution of business, of corporate 

strategy, of technological change and market development, 

and indeed of both national and international economies" 

(Yergin, 1991). The immense influence of the oil industry 

on the development of our society and culture has been 

institutionalized in academics, policymaking, and the collective mind of the general public. Without question, until 

the 1970's, natural gas was a "by-product" of oil exploration, oil drilling, and oil production. Unfortunately, natural 

gas continues to be perceived in that context. Even today, 

university degrees are granted in petroleum geology, petroleum engineering, and petroleum land management. Petroleum,, originally defined as "rock oil," signifies oil and only 

oil in the minds of most people, and we must recognize 

that many universities, oil companies, and natural gas companies even today educate and train people to be oil engineers, oil geologists, and, most unfortunately, oil thinkers. 

(As late as 1979, the primary definition of petroleum in the 

American Geological Institute Glossary of Geology clearly 

stated that the word petroleum refers to liquid oil. The secondary definition, a more general one, includes all liquid 

and gaseous hydrocarbons.) 

In the past, oil thinking has so dominated the natural 

gas extraction industry that it has distorted the process of 

natural gas exploration, production, and, particularly, past 

and present estimates of the remaining natural gas resource 

base. Until recently, most of the respected and accepted 

estimates of the natural gas resource base rather accurately 

approximated the quantity of natural gas that would be 

produced in association with future oil production within 

the economic and technological parameters that were predicted for the oil industry. Those estimates excluded most 

of the natural gas that will be found and produced, in very 

large quantities, outside the geologic, economic and technological domains of oil. Below are six quite typical examples of oil bias and misunderstandings about natural gas 

that have led to very real, though unintended, distortions of 

the U.S. natural gas resource base estimate. 

1. In 1957, with a degree in petroleum geology from 

the University of Oklahoma, I joined Phillips Petroleum 

Company as a trainee, spending time in the Economic 

Analysis Section where each drilling proposal was closely 

reviewed. At the time, natural gas prices were fixed by the 

Government at only a fraction of the equivalent Btu value 

of oil. As a result, the price of natural gas was of no significance in risk analyses of drilling proposals or the calculation of future revenue and rate of return on investment. 

Natural gas was to be used, at best, as a "plus factor" that 

might pay for the overhead of operating an oil well. 

Throughout the 1950's and 1960's Phillips, and I presume 

most major oil companies, analyzed geology and forecast 

economics strictly by using geologic and economic factors 

appropriate to oil. Natural gas discovered during this period of oil exploration was found largely by chance and had 

little relationship to the amount of gas that might have 

been found if the emphasis had been on natural gas rather 

than oil. As a result, all econometric projections, such as 

the one in the example below, that used these factors to 

predict the future of natural gas had little bearing on the 

actual amount of natural gas in the ground. Rather, these 

models, based principally on oil-based economics and geology, estimated only the amount of natural gas that would 

reasonably be found and produced in the future by the U.S. 

oil industry during its search for oil. 

2. Oil thinking has had a major impact on the econometric modeling of gas resources even by natural gas companies and associations. An estimate of future natural gas 

supplies and production made by the American Gas Association (AGA) in the mid-1970's provides a classic example. 

Having already become the principal public advocate for a 
812 THE FUTURE OF ENERGY GASES 

large natural gas resource base, the "optimistic" scenario of 

the AGA appeared to me to be ultraconservative to pessimistic, and I became curious about the sources of information on which the study had been based. It turned out that 

the AGA economists had· followed a highly logical approach; wanting to project the highest, reasonably possible 

quantities of natural gas that would be found from estimates 

of future drilling, tliey had used the highest historical natural gas finding rates per well drilled. The limitation of this 

study was inherent in the natural gas finding rates used, 

because the highest historical finding rates were achieved 

during the 1950's when oil companies, solely on the basis of 

oil economics, with no thought of natural gas as a commodity with intrinsic value, were exploring and drilling mainly 

in the rather shallow geologic environments where their 

geologists expected to find oil. Though the AGA projection 

was indeed more optimistic than most other forecasts for 

natural gas, it had little relevance to future natural gas extraction as it included no consideration of natural gas to be 

found not in association with oil or in domains in which 

natural gas is prolific and oil does not exist, such as the vast 

volume of rocks in overthrust belts and at depths below 

which oil is generally absent (see Woods, this volume). 

3. The artificially created shortages of natural gas production that occurred in the early 1970's as a result of decades of unrealistic Government price controls led to an 

equally artificial shrinkage of the Uniteq States proven natural gas reserves by the late 1970's. This exceptionally telling example of the effect of perception upon prediction is 

the essential thesis of this article. Spurred on by the common misperception that the United States was rapidly running out of natural gas, John O'Leary (head of the Federal 

Energy Administration, February 1977 to September 1977, 

Deputy Secretary of Energy, Department of Energy, October 1977 to September 1979) declared and often repeated 

that "natural gas has had it." This perception became the 

official Government view, and soon most prognosticators, 

including the major integrated oil companies as well as 

many natural gas companies, were forecasting "grave" 

shortages and espousing their concerns. The shortage mentality was seized upon by the Nation's coal and nuclear 

industries, so natural gas, of course, became an "unreliable" 

source of energy. In 1977, as a result of the perception of 

shortages, the Secretary of the Interior ordered a study of 

six major offshore natural gas fields in the gulf coast region 

to determine if they had reserves as large as were currently 

estimated by the field operators. Though these six fields 

were selected for their large size and with the expectation 

that they might have a high potential for increasing production, the study, conducted by the Committee on Gas Production Opportunities of the National Research Council 

(1978) found that all six fields had significantly less natural 

gas than had been originally estimated. This finding essentially confirmed the official Government position that our 

nation indeed had a critical shortage of natural gas and 

suggested that the United States natural gas resource base 

was both limited and scarce. Since 1977, however, these six 

fields have produced 4.7 Tcf, which exceeds the committee's estimate of remaining reserves by 65 percent. This 65 

percent may be a reliable figure by which we should increase our current estimates of proven producing reserves 

in order to achieve a more realistic idea of the quantities of 

natural gas available from existing fields. 

4. In 1984, Charles B. Wheeler, Senior Vice President, 

Exxon Company, U.S.A., and I were called before Congress to testify about the nation's natural gas future. Mr. 

Wheeler testified that, "We estimate the volume of yet undiscovered natural gas from conventional sources in the 

United States to be about 300 Tcf * * *.This is very close 

to our last published assessment of the volume of resources 

in 1976." Based upon this limited and pessimistic view of 

our natural gas supplies, he went on to predict that, "Future 

demand for [natural] gas will exceed the supply available 

from the domestic resource base. Requirements for natural 

gas will significantly outstrip domestic supply capability 

by the late 1980's." He concluded with Exxon's dim view 

of the natural gas future of the United States saying, "We 

project a shortfall of economically available gas from any 

source." Unfortunately, this overly negative view, coming 

from the nation's largest oil company, had a detrimental 

effect upon other industry and government estimates of 

America's natural gas future. (Quotes from testimony before the Committee on Energy Regulation, Subcommittee 

of the full Committee of Energy and Natural Resources, 

April 26, 1984, Washington, D.C.) 

At these hearings, I made the point that Exxon's estimates, and all the other comparably small estimates, were 

founded upon oil thinking and that a more realistic estimate, 

based on a great deal of experience in natural gas exploration and production, would be the natural gas resource base 

estimate I originally presented in 1978 at the Aspen Institute 

(Hefner, 1978; fig. 2) of from 1,000 to 1,500 Tcf, three to 

five times Exxon's figures. At the time, Exxon, other oil 

companies, and policymakers gave little weight to estimates 

made by a small independent natural gas producer. However, as in the example above, time has been on the side of a 

new understanding of natural gas-the National Petroleum 

Council, an advisory committee to the Secretary of Energy 

composed mainly of representatives from the oil industry, 

has recently estimated the natural gas resource base to be 

1,295 Tcf (National Petroleum Council, 1992). This is a 

significant step forward for an organization dominated by 

oil, and an affirmation of the validity of my estimates, made 

15 years ago, based on natural gas experience and thinking 

outside the confines of conventional oil-based wisdom-the 

type of thinking I hope to stimulate with this chapter and on 

which we need to base our energy future. 

Contrary to Exxon's projections, during the entire decade of the 1980's natural gas supplies have so outstripped 

demand that the average wellhead price, instead of contin-
NEW THINKING ABOUT NATURAL GAS 813 

ually rising as Exxon and most others predicted as a result 

of their pessimistic estimates of the resource base, actually 

declined from an average of over $3.50 per thousand cubic 

feet (Met) in constant dollars in 1984 to a spot price of 

less than $1.00 per Mcf in February 1992. 

5. The influence of oil thinking on estimates of the 

future of natural gas continues today. An excellent current 

example of this influence is from the Ouachita overthrust 

belt in western Arkansas and southeastern Oklahoma. The 

northern limit of the Ouachita overthrust belt is defined by 

the location, at the surface, of the large regional Choctaw 

fault. Conventional oil wisdom has always suggested that 

significant amounts of oil, and natural gas, should not be 

present south of the Choctaw fault because the sediments 

had been subjected to temperatures and pressures that 

would destroy any oil and reservoir pore space that had 

originally been present. As a result of this belief, prior to 

1988, few exploratory wells had been driped within the 

Ouachita overthrust province. However, beginning in 1988, 

a number of large new natural gas discoveries, including 

several wells that rank among the world's largest, were 

made south of the Choctaw fault, at progressively deeper 

levels. These wells include the Zipperer, with initial flows 

of 40 million cubic feet per day (MMcfd) and Estimated 

Ultimate Reserves (EUR) of 35 billion cubic feet (Bet), the 

Baumann, with initial flows of 60 MMcfd and EUR of over 

40 Bcf, and the recent Windingstair, with initial flows of 50 

MMcfd and EUR of 50 Bcf. Some 125 wells have now 

been drilled, discovering approximately 1 Tcf of new gas 

reserves in an area once thought to be virtually barren. The 

average ultimate production of each of these new wells will 

be well over the equivalent of 1 million barrels of oil 

(MMbo). The natural gas industry is currently drilling 12 

deep wells (below 15,000 ft) to further test the large potential of this fold and thrust belt. Already, several completed 

deep wells have paid back their complete investment in one 

year or less and have established new reserves at a cost of 

about $0.25 per Mcf. Unfortunately, as of the date of this 

34 r---------~---------,r---------~----------r----------.--------~3.00 

32 

30 

28 

(/) 

<( 

(.!J 

u.. 26 

0 

fw 

w 24 u.. 

(_) 

((i 

:::J 22 

(_) 

z 

0 20 _J 

_J 

a: 

f- 18 

16 

14 

12 

1975 1980 1985 

'Production capability through 1983JS based on actual production plus excess 

production capaCity as eslimated by Goldman, Sachs & Co., oil analysts, 4/84. ,/ 

Produclion capability from 1984 through 1991is based on annualizmg the 

highest natural gas consumption month ~ess Withdrawals from storage) 

We belie1 e this senously undereslimated real produclion capability (see 

dashed line). 

,/ 

/~\{' 2.50 

/' tO" 

•' ~· o\ '{; ·"' •' '1>\'1- ·~' / '\ot "Based upon passage of a natwnal energy bill, mamtenance of the "ifil" /' '5 

Clean Atr Act, U 5 Willmgness to hold the line on C02 emiSSions '--.§1:. , 

1990 

YEAR 

·Cl<;- / iS'/ ;}.:$ • 

't:,.<{ /,/~:;s- "'q; ~Cl 

·<~Y /' ::.."<> 

""' a '""" / ... ;;;.~ J" /<.)\' 

~· / .,.. I .,.. ...... o''li' 

,....!-.,... \eo\ 'l,t 

• lt'lo til 

I 

Actual Production 

Capability• 

1995 2000 2005 

(/) 

a: 

<( 

_J 

_J 

0 

0 

0 

:::J 

z 

w 

(_) 

a: 

a.. 

0 

<( 

w 

I 

_J 

_J 

w 

~ 

w 

(.!J 

<( 

a: 

w 

~ 

Figure 2. Natural gas projected production versus actual production capacity for the United States. Hefner projections are based 

in part on a natural gas resource base originally estimated in 

1978 at 1,000 to 1,500 Tcf. Lines descending from "actual production capability" curve are projections of production by various organizations since 1975. The inaccuracy of these projections is easily seen. From Hefner (1992). Copyright, 1992, 

GHK Company. 
814 THE FUTURE OF ENERGY GASES 

paper, the large potential of this geological province, which 

I predict to be in the range of 30 to 50 Tcf, is not yet 

included in official estimates of the United States natural 

gas resource base. In spite of the fact that the province now 

contains its first new giant field, which I call the South 

Choctaw field, the official estimate remains at only 5 Tcf, in 

part because of the lag time in official estimating and reporting and in part owing to the natural hesitancy of experts 

to predict the potential for new and large discoveries of 

natural gas in areas where many pyople, including myself, 

were originally taught no oil or gas could occur. 

6. Oil is a viscous, noncompressible fluid that could 

not be economically produced from many excellent natural 

gas reservoirs even if it were present. Methane is a highly 

compressible gas with negligible viscosity; this condition 

leads to significant differences between the production of 

oil and the production of natural gas. One highly important factor not well understood by economists and policy0 

2000 

4000 

6000 

Iw 

w 8000 

LL 

z 10000 

I 

Ia.. 12000 

w 

Cl 

14000 

16000 

18000 

20000 

makers is the difference between the recovery of usable 

energy (Btu's) from oil reservoirs and the recovery of usable energy from natural gas reservoirs at increasing 

depths below the surface. Below 8,000 ft a natural gas reservoir will nearly always produce more usable Btu's than 

an oil reservoir and at 15,000 ft over 1.5 times the usable 

Btu's could be recovered from a natural gas reservoir 

(fig. 3). A barrel of oil at 20,000 ft, for example, equals a 

barrel of oil at the surface, but a barrel volume of natural 

gas at 20,000 ft in an overpressured basin such as the deep 

Anadarko Basin, Texas and Oklahoma, equals as many as 

500 barrels of natural gas at the surface. The compressibility (defined by Boyle's law and called the "Z factor" in 

estimates of natural gas reserves) and negligible viscosity 

of natural gas are generally taken into account in economic analysis, drilling, and production practices; however, 

decades of experience focussed on noncompressible oil 

and only slightly compressed ("normally pressured") natu0.5 1.0 1.5 2.0 2.5 

RECOVERABLE BTU'S, IN MILLIONS 

Figure 3. Recoverable Btu's per I barrel volume of natural 

gas versus oil from reservoirs of increasing depths. The following assumptions were used to determine Btu recoveries: 1 

bbl of oil=5.616 ft3; oil gravity=28 degrees API; gas/oil 

ratio=300; gas gravity=0.6; 20 percent oil recovery; 80 percent 

gas recovery at low pressure increasing linearly to 90 percent 

recovery at 20,000 feet; temperature gradient= I °Fil 00 ft; surface temperature=70°F; pressure gradient=0.45 psi/ft; 1,000 Btu 

gas. Oil: A temperature shrinkage factor was applied; therefore 

a barrel of oil from depth contains slightly fewer Btu's than a 

barrel at the surface. Gas: A formation volume factor (Bg) was 

used to determine total at-the-surface volumes. Overpressured 

Anadarko Basin gas: The normal pressure gradient of 0.45 psi/ 

ft was used for depths less than 11,000 ft; below 11,000 ft, 

the pressure gradient was increased linearly to 0.9 psi/ft at 

20,000 ft. . 
NEW THINKING ABOUT NATURAL GAS 815 

raJ gas has led frequently to oversight of the effects of 

compression and flow characteristics unique to natural gas 

on both the drilling for deep natural gas and the ultimate 

volume of natural gas production. The following examples 

illustrate my point: 

Oil-dominated thinking, for example, has caused most 

of the "blowouts" I am aware of in my career and has added 

much, largely unnecessary risk, time, and expense to drilling 

in high pressure natural gas regions. I have been made 

aware many times (and even recently) that drilling engineers with decades of oil drilling experience overlook the 

fact that an inflow of natural gas from a high-pressure reservoir at depth, hardly noticeable in pit volume at the surface, 

undergoes an enormous rate of expansion as it approaches 

the surface. In the Anadarko Basin example above, 50 percent of the expansion would take place in the last 1,000 ft, a 

rate which would easily cause a blowout if it was overlooked and unsuspected. 

The misunderstanding of deep high-pressure natural 

gas reservoirs on the part of reservoir engineers was poignantly illustrated one day in 1982 when I presented a 

core from a depth of 18,000 ft in the deep Anadarko Basin 

to the senior engineer of one of the world's largest banks 

specializing in petroleum financing. Thinking that it was 

the fi1;1est looking example of a clastic reservoir rock that I 

had ever seen from the deep Anadarko Basin, I was 

shocked when he took one look at the core and pushed it 

away with the curt comment, "that rock will never produce any oil!" It didn't, but the well was completed for 35 

million cubic feet (MMcf) of natural gas per day and has 

produced over 20 Bcf of natural gas; it will eventually 

produce the energy equivalent of 6 MMbo. 

Reservoir engineers maintain that the unique characteristics of a gas, including compressibility, have been taken 

into full account in estimates of deep high-pressure, natural 

gas reserves and therefore that their estimation of ultimate 

reserves should be viewed generally with a high level of 

confidence. However, my experience suggests that we do 

not fully understand what is happening in high-pressure 

reservoirs, particularly the mechanisms of movement of 

high-pressure natural gas through the various types of connected pore space found at depths greater than 15,000 ft. 

We must remember that petroleum reservoir engineering is 

founded on the work of Henri-Philibert-Gaspard Darcy 

(1803-1858), a French engineer who in his study of the 

sewers of Paris measured the flow of various liquids through 

sand packs. Darcy's early simple equations, still in use today 

with little modification, were suitable to normally pressured 

liquid oil moving through sand, the most prevalent oil reservoir. I believe, however, that Darcy's equations are significantly lacking in their ability to describe and predict the 

movement of natural gas through the broad variety of natural gas reservoirs that exist. We simply do not yet understand the dynamics and rates of flux of natural gas moving 

through the complexity of microfractures, micro and macro 

vugs, primary and secondary porosity, natural macrofractures, and induced and propped fractures that occur in deep 

high-pressure natural gas reservoirs. As a result, procedures 

used to estimate natural gas reserves in shallow low-pressure reservoirs do nof give an accurate picture of the quantity of natural gas resources available at depth. Engineering 

technology and techniques for the estimation of deep highpressure natural gas reserves did not keep pace with the 

industry's ability to produce natural gas from these complex reservoirs particularly during the drilling and production boom of the late 1970's and early 1980's (Jack KI"Qg, 

oral commun., 1993). I am confident that this is one cause 

of the general underestimation of proven reserves in the 

deeper higher-pressure domains. The production decline 

curves shown in figure 4, typical of the U.S. midcontinent 

region, graphically demonstrate this point. 

THE NATURAL GAS RESOURCE BASE 

OF THE UNITED STATES 

A number of circumstances have arisen recently that 

have caused many estimates of the natural gas resource 

base to be revised upward. These reassessments have been 

forced by a variety of factors, including (1) new prolific 

discoveries in places long ago written off by oil explorationists, (2) new views of existing natural gas reserves, (3) 

a growing awareness of the differences between oil and 

natural gas, (4) a wave of recent exploration and production technology enhancement specifically related to natural 

gas, and (5) the recent recognition that the overall decline 

in production of many natural gas reservoirs turns out to 

be more gradual than initial estimates suggested (fig. 4). 

The three most prominent groups of estimators are the 

Potential Gas Committee (PGC), the U.S. Department of 

Energy (DOE), and the U.S. Geological Survey (USGS). 

Recent estimates by the DOE (U.S. Department of Energy, 

1990) and PGC (1990) are 1,370 and 1,033 Tcf (with 

proved reserves added) respectively. Though it is sometimes difficult to compare estimates because they are based 

on different definitions and categories of resources, the 

DOE and PGC estimates suggest a sufficient supply of natural gas to meet significantly increased demand for 30 to 

40 years. The most recent USGS study (Mast and others, 

1989), based on data available as of January 1987 and considering conventional resources only, estimates supplies of 

natural gas at 399 Tcf, a number comparable with the oilthinking estimates of the past. 

In 1991, Enron Corporation, the United States leading 

integrated natural gas company, revised upward its estimate of the remaining economically recoverable resource 

base from 805 Tcf in 1989 to approximately 1,200 Tcf in 

1991 and increased it again to 1,303 Tcf as of January 

1993. In 1991, Enron stated that, "A major reason for our 

optimism, * * * is the development and rapid diffusion of 
816 THE FUTURE OF ENERGY GASES 

technology * * * These developments portend both an increase in the economic viability of new resources * * * and 

an upsurge in the yields from traditional producing regions" (Enron Corporation, 1991). In 1993, Enron noted 

the close similarity of its 1993 estimate with the National 

Petroleum Council (NPC) estimate of 1,295 Tcf as of January 1991 and agreed with the NPC statement that, "Natural 

gas is an abundant domestic resource and can be produced 

and delivered at prices that allow both expansion of the 

market and continued development of the resource" (cover 

A 21ooo 

18000 

15000 

(/) 

CL 12000 ~ 

letter accompanying Enron Corporation, 1993). In addition· 

to these estimates, the Gas Research Institute (GRI) has 

recently released a figure of 1585 Tcf (Fisher, 1993). 

Though these new estimates are a significant step toward a more realistic assessment of our real recoverable 

natural gas resources, I believe they are still overly conservative. My position is based on new information and my 

experience in natural gas exploration and production, particularly in the Anadarko Basin, where the history of d~velopment suggests that natural gas reserves are significantly 

w 

0: 

:J 

(/) 

(/) 

The first estimates of ultimate production, which were based upon 

volumetric calculations of the reservoir size and early flow rates, were less than 4 Bcf. 

w 9000 0: 

CL 

6000 

0 

3000 

1st 

3.5 Bcf 

0 

0 2 4 6 8 

The 1st "highly confident estimate" was 16 Bcf. 

As of December 1992 cumulative 

production was 15 Bcf. Ultimate 

production is now forecast to be more than 25 Bcf. 

~:'" > 10 Bel 0 (well loads up) 

3rd 

>16 Bel 

10 12 14 16 18 20 

CUMULATIVE PRODUCTION (BCF) 

Figure 4. Production decline curves for 3 natural gas wells. 

These examples show how ultimate reserve estimates grow with 

production. This results from a variety of factors including application of new technology, lack of understanding of fluid flow and 

drainage, particularly in deep natural gas reservoirs, and reluctance on the part of engineers to increase initial low estimates 

until forced to by increased production. 0=24 hour shut in state 

test; Z=calculated bottom hole pressure; MMcfd=millions of 

cubic feet of natural gas per day; Bcf=billions of cubic feet. A, 

GHK Company No.1 Green well, completed 1969 at 21,600 ft. 

Carbonate reservoir, open flow test 24.3 MMcfd, initial flow rate 

19 MMcfd at 7,010 psi flowing tubing pressure. B, Phillips Petroleum Company Bowers B well. Fractured carbonate reservoir, 

completed at 19,700 ft. C, Amoco Gallagher well. Sandstone reservoir, 8,000 ft, open flow test 30.6 MMcfd, initial flow rate 43.7 

MMcfd. 
NEW THINKING ABOUT NATURAL GAS 817 

larger than most of us imagine, much less calculate. The 

history of the Anadarko Basin indicates that the distinction 

between conventional and unconventional sources of natural gas is largely one of perception, controlled by a combination of the state of our technology, our estimates of 

future prices, our familiarity with a particular source, and 

politics. The Anadarko Basin also provides a striking example of the fundamental differences in the occurrence of 

oil and natural gas that continue to affect estimation resource methodology. 

THE ANADARKO BASIN 

In the early 1960's, the GHK Company decided to explore for non-oil-associated natural gas in the Anadarko 

9000 

7500 

Basin, recognizing that this would require searching at 

depths well below known oil reservoirs. At that time, the oil 

industry utilized models that indicated deep drilling would 

be totally unproductive-accepted geochemical models 

showed that all hydrocarbons would be burned off by high 

temperatures, and shallow drilling experience combined 

with theoretical models indicated that porosity would decrease with depth and disappear entirely at about 20,000 ft, 

collapsed by overburden pressure (fig. 5). Even if porosity 

and hydrocarbons were preserved at these depths, in 1960 

few believed that the technology for drilling and production 

of such deep wells existed. 

Nevertheless, in a series of deep wells drilled in the 

Anadarko Basin in the late 1960's and early 1970's by the 

GHK Company and others, it was shown that both porosity 

and natural gas do exist even at depths of over 30,000 ft 

The 1st estimate of ultimate production was 40 Bcf. 

(/) 

~ 

UJ 

a: 

;:::) 

(/) 

(/) 

UJ 

a: 

a.. 

6000 

4500 

3000 

1500 

0 

Figure 4. Continued. 

40 

The first "highly confident" estimate of ultimate reserves 

forecast more than 85 Bcf. 

80 120 160 200 

Cumulative production as of 

December 1992 was 105 Bcf. 

Ultimate production is now forecast 

to be about 120 Bcf. 

280 320 

CUMULATIVE PRODUCTION (BCF) 
818 THE FUTURE OF ENERGY GASES 

(Hefner, 1980). The GHK Company found that conventional thinking no longer applied below a zone I call the 

transition zone, usually encountered near 15,000 ft and 

characterized by rocks that have been strongly affected by 

pressure solution, recementation, and fracturing. Below 

this zone, pressures jumped beyond their normal gradient 

and porosity actually increased (Hefner, 1980). In 1969, 

GHK's historic No.I Green discovery in Beckham County, 

Oklahoma, was the first well to prove the misconception of 

porosity disappearing with depth. The No.1 Green was 

spud in October, 1967 and completed in the spring of 1969 

after being drilled to a total depth of 24,473 ft, at that time 

the second deepest well bore ever drilled into the Earth. In 

this well, porosity of up to 18 percent was measured at a 

depth of 21,600 ft in a reservoir containing a surface shutin pressure of 15,130 lb/in2 (fig. 6), which at the time was 

c 5600 

4800 

4000 

the highest pressure ever measured in the world. The well 

produced at a rate of over 19 MMcf of gas per day and on 

an annual basis was capable of producing an amount of 

energy equivalent to one-third of the energy produced by a 

nuclear plant. It soon became evident that below the transition zone, a rapid shift generally occurred in the pressure 

gradient from the normal 0.465 pounds per foot of depth to 

near 0.60 pounds per foot of depth, a shift which continued 

to increase to gradients as high as 1.0 pounds per foot of 

depth at a depth of 31,441 ft in the Lone Star-GHK Rogers 

well, Washita County, Oklahoma. The transition zone 

proved to be a pressure barrier below which porosity is 

enhanced and held open by high-pressure natural gas. At 

first, my colleagues in other companies thought the high 

porosity of the No.1 Green well would only be found in 

carbonate reservoirs, owing to greater rock strength as 

The 1st estimate of ultimate reserves was less than 20 Bcf. 

(/) 

a... 3200 -

w 

a: 

::J 

(/) 

(/) 

w 

a: 2400 

a... 

1600 

800 

0 

0 10 20 30 

Figure 4. Continued. 

After 30 Bcf had been produced, estimates of about 45 Bcf 

of ultimate r,roduction were made with a "very high level of 

confidence. ' 

40 

After nearly 40 Bcf had been produced, estimates were 

increased to more than 50 Bcf, also with a "high level of 

confidence." 

50 

As of December 1992 the well has 

cumul<1tive production of 51 Bcf. 

Ultimate prOduction is now estimated 

to be q~ore,than 60 Bcf. 

5th 

>60 Bel 

60 70 80 90 

CUMULATIVE PRODUCTION (BCF) 

100 
NEW THINKING ABOUT NATURAL GAS 819 

5000 

Iw 10000 w 

LL 

z 

I -

I-

(L 

w 

0 

15000 

20000 

I I I 

I I 

I(!!} 

o------~-lll108) 

I 

I 

5 

I 

I 

I 

I 

I 

I 

I 

I 

PERCENTAGE POROSITY 

35 

Figure 5. Porosity data from Pennsylvanian and Permian sandstones in north Texas and Oklahoma, reflecting the pre-1970 

view that porosity would decrease with depth, disappearing at 

about 20,000 ft. Porosities below 20,000 ft on this diagram 

were calculated from sonic and neutron logs. Horizontal bars 

represent measured porosity variation in the pay sands sampled, 

with small rectangles indicating average porosity for the unit. 

The temperature gradient is noted along the line limiting maximum porosity. From Maxwell (1964). 

compared to sandstone reservoirs. By 1982, however, approximately 380 wells had been drilled to below 15,000 ft 

in the Anadarko Basin, and porosity in sandstone reservoirs 

had been found to range frequently from 15 to 20 percent; 

a large number of these reservoirs were capable of production rates similar to the No.I Green well. 

As large quantities of natural gas were extracted from 

these deep, prolific reservoirs and the pressure lowered in 

the vicinity of wellbores, reservoir rocks would indeed collapse, requiring artificial fracturing for continued high rates 

of production. Below the transition zone, traditional fracturing with silica sand or glass beads proved detrimental to 

production because crushing of both these materials at the 

extreme overburden pressures actually reduced permeability and flow rates, thus limiting the quantity of commercially recoverable reserves. However, at this time, Exxon had 

Figure 6. Enlarged photograph of rock sample from a producing reservoir from GHK Company No.I Green well, Beckham 

County, Oklahoma. Producing zone 21,570-21,590 ft: gray, tan, 

and brown fine crystalline dolomitic limestone with weathered 

vugular to honeycomb porosity. 21,590-21,605 ft: tan fine to 

medium crystalline dolomitic limestone with intergranular and 

pinpoint porosity, also vugular porosity. Many vugs have secondary crystal growths in cavities. 

developed sintered bauxite as a proppant with two to three 

times the compressive strength of silica beads, and four to 

five times that of sand. Once the problem of the extremely 

abrasive nature of the material was overcome, sintered 

bauxite fracturing proved to be a highly effective treatment 

and is a prime example of how new natural gas-related 

technology increases the availability and quantity of natural 

gas resources. The flow rates and commercially recoverable 

ultimate reserves were usually increased several fold and 

sometimes by nearly an order of magnitude (fig. 7). This 

breakthrough in fracture treatment proved to be as important to deep high-pressure natural gas production as the 

introduction of hydraulic fracturing was to oil in the 1950's. 

Deep gas is no longer an unconventional source in my 

view, after drilling several hundred wells to depths of 4 to 

5 miles, with reservoir pressures ranging beyond 20,000 

psi, at least within the context of current technological understanding and ability. Perhaps the only remaining truly 

unconventional source of natural gas lies in the methane 

hydrates of the ocean and polar regions. Because we have 

seen how perceptions significantly influence resource estimates, changes in the perception of what is technologically feasible within the limits of foreseeable economics will 

almost certainly lead to continued increases in most estimates of the natural gas resource base. 
820 

A 14ooo 

12000 

10000 

~ 8000 

w 

a: 

::> 

(/) 

(/) 

w 

a: 

a.. 

6000 

4000 

2000 

0 

B 

I' 

1-

z 100 

0 9 

~ ~ () 6 

:::2: 5 

~ 

z 

0 

i= 

() 

::> 

0 

0 

a: 

a.. 

(/) 

<( 

(!) 

10 

0 5 

n 78 79 80 

THE FUTURE OF ENERGY GASES 

The I st estimate of less than 15 Bcf of ultimate reserves was based upon 

initial flow tests, production rates and decline before fracture treatment. 

~;;-....... ~---~The 1st "highly confident estimate" of 

ultimate reserves was more than 25 Bcf. 

10 

81 82 

0 

15 20 25 30 

As of December 1992 cumulative 

production was 26 Bcf. 

Ultimate production is now forecast 

to be more than 35 Bcf. 

3rd 

>35 Bcf 

35 40 

CUMULATIVE PRODUCTION (BCF) 

83 84 85 86 87 88 89 

YEAR 

90 91 92 

25.6 Bet• (Dec. 31, 1992 

Cumulative Production) 

93 94 95 

50 

96 
NEW THINKING ABOUT NATURAL GAS 821 

Perhaps a more immediate and striking example of the 

limitations on our view of natural gas resources is provided by the history of development of the Anadarko Basin 

and what this reveals about the nature of the occurrence of 

oil and natural gas. Historically, oil developers followed 

trends along which unique but similar oil pools would be 

found. One technique of estimating future oil reserves that 

arose from this process involves the analysis of a basin by 

~ Figure 7. Production decline curves for GHK Company 

No.1-8 Berry well. Fractured sand reservoir, 15,200 ft completed 

1976, open flow test 32 MMcfd, initial flow rate I 0.9 MMcfd; 

0=24 hour shut in state test; Z=calculated bottom hole pressure; 

Bcf=billions of cubic ft. A, Demonstrates the growth of reserve 

estimates through time. B, Compares projected straight line estimated production decline curves with actual production history. 

In addition to application of stimulation techniques and the inherent conservatism of resource estimates, the difference between 

estimated production and actual production may result from inadequate understanding of reservoir behavior. Jagged line shows 

gas production; straight lines show decline estimates. (*) Total 

cumulative production to date. 

"trends" and "plays" that could be forecast reasonably on 

the basis of the location, character, size, and production 

history of existing oil fields. In the past, this analysis has 

worked well in U.S. oil basins, most of which contain 

many small- to medium-sized oil pools. 

In 1965, during the early development of the Anadarko 

Basin, it looked very much like an oil basin, with scattered, 

small oil and gas pools separated by areas of no production 

(fig. 8). However, as time passed and more wells were 

drilled to increasing depths, producing areas began to 

change to gas fields, and the gas fields began to merge, 

creating a pattern indicating that the Anadarko Basin, at 

depths generally below the main level of oil production, is 

actually one gigantic natural gas field (fig. 9), approaching 

the size, by volume of resource, of the large gas fields of 

Siberia. Production in the Anadarko Basin is from multiple 

horizons, beginning in Permian rocks near the surface and 

extending to the world's deepest natural gas production at 

26,566 ft from the Arbuckle Group of Late Cambrian and 

Ordovician age. The deepest production in the Anadarko 

Basin and the world is Chevron's No.I Ruth Ledbetter, 

completed in 1977. Drilled in Wheeler County, Texas, the 

No.I Ledbetter flows from Arbuckle production (Ellenburger Group in Texas) from perforations as deep as 26,566 ft 

' •BEAVER • HARPER WOODS 

TEXAS 

.,. . 

. 

ELLIS WOODWARD 

.HANSFORD 

• DEWEY 

ROBERTS HEMPHILL BLAINE 

' ROGER 

MILLS CUSTER 

GRAY 

-, ' WHEELER 

CARSON 

' ·WASHITA 

1965 

,. ~ OIL. COLLINGSWORTH 

GAS TEXAS 

12 18 

GRADY CADDO 

. ··: I 

. ..... . ~ ,~ 

·, IOWA~· 

OKLAHOMA r; '"-. I 

. .. 

Figure 8. Map of oil and gas fields in the Anadarko Basin, western Oklahoma and Texas Panhandle, 1965. 
822 THE FUTURE OF ENERGY GASES 

(Petroleum Information Corporation, 1982; Alan Petzet, Oil 

and Gas Journal, oral commun., 1993; and Dwight's Database). I think a similar pattern of natural gas distribution 

will appear in other areas-as deeper wells are drilled, we 

will begin to see that natural gas accumulations, below the 

zones that are predominantly oil, are essentially continuous 

over very large areas. 

Given this type of pervasive distribution, the old but 

often used practice of estimating potential natural gas reserves using the oil technique of "play" and "trend" analysis based on fields and individual structures only limits our 

ability to achieve an accurate estimate of the real resource 

base of natural gas. Because of this thinking, during the 

1970's and 1980's my estimates of the natural gas resource base were often challenged on the basis that no 

more "giant" fields and very few "significant" fields were 

being found. My reply was that the Anadarko Basin was 

indeed a giant field, which was continuing to be developed, that actually contained at that time some 300 individual wells each capable of ultimately producing over 6 

Bcf of gas, the equivalent of 1 MMbo. 

• • ••• 

Perhaps the most important lesson from the Anadarko 

Basin is contained in estimates of the total quantity of natural gas present in this region. Below the transition zone, 

rocks of the Anadarko Basin form an overpressured envelope within which porosity is held open largely by the presence of methane. This overpressured envelope has recently 

been described as a "megacompartment complex" by AIShaieb and others ( 1992; fig. 1 0). The rocks of this pressure 

complex are by volume primarily Mississippian and Pennsylvanian shales. We have calculated the quantities of methane in place within these shales to be in the range of 2,000 

Tcf (appendix A). This estimate does not include local overpressured compartments present outside the megacompartment complex in many stratigraphic intervals, particularly 

in rocks of the Hunton and Simpson Groups (Al-Shaieb and 

others, 1992; fig. 10). Most of this natural gas occurs in 

shales with significant porosity but, other than microfractures, little or no permeability. The amount of natural gas 

that may be ultimately available is thus uncertain and would 

depend upon the economy, technology, and the rate of flux 

through the fractured shales and coals . 

• • 

~ ... . . ~· . (,~ 

HARPEfl • 

.. -~, 

1985 

~ OIL. COLLINGSWORTH 

GAS TEXAS 

11 18 

Figure 9. Map of oil and gas fields in the Anadarko Basin, western Oklahoma and Texas Panhandle, 1985. 
NEW THINKING ABOUT NATURAL GAS 823 

In general, natural gas wells produce significantly more 

natural gas than indicated by original estimates. In my experience, this has nearly always been true for wells producing 

from below the transition zone in the Anadarko Basin. The 

decline curves and ultimate reserve forecasts for the wells 

shown in figures 4 and 7 are typical examples of engineering 

underestimation of natural gas wells in the Anadarko and 

Arkoma basins. These figures show that early estimates of 

ultimate production, based on initial flow rates, pressure 

decline, and volumetric calculations, are almost always 

overly conservative. This is particularly true for larger, more 

prolific, natural gas wells that frequently produce several 

times the quantity of natural gas indicated by early estimates. 

These underestimates of reserves are the result of several 

factors including new technology (fig. 7). I suspect, however, that the major contributor to significantly low estimates 

of reserves, even in the light of apparently adequate production and reservoir data, is the continuing failure to recognize 

the complex multiple flow and drainage regimes of these 

reservoirs. In the recent past, this oversight has resulted in 

sw 

t 

l: 

~ 

a. 

UJ 

Q 

w 

z 

zz 

ow 

O>-C 

>-WW 

w:I:a: 

a:oc 

forecasts, based on straight line decline, that tended to be 

extremely low. Unfortunately, the low estimates in a. well, a 

field, or a producing region then became generally accepted 

and reservoir engineers were commonly reluctant to increase 

their low forecasts until forced to by increased production of 

natural gas. In addition, I believe that high-pressure natural 

gas is able to flow at commercial rates from reservoirs with 

porosities as low as 5 percent or less, porosities far less than 

those which are accepted to be reservoir quality for natural 

gas. This factor would also increase actual natural gas production in excess of original estimates, as would additional 

natural gas flows that enter the reservoir from adjacent overpressured and fractured shales. 

A MORE OPTIMISTIC VIEW OF THE 

NATURAL GAS RESOURCE BASE 

Considering the degree of inaccuracy in past natural gas 

resource base estimates and the large quantities of natural 

N 

100..,; 

Figure 10. Schematic cross section of the Anadarko Basin. The area within the thick line indicates regional overpressured megacompartment complex (mcc) (stippled). Large arrows identify local overpressured compartments. From AI-Shaieb and others (1993). 
824 THE FUTURE OF ENERGY GASES 

gas that we know exist in such habitats as deep gas reservoirs and methane hydrates, I am led to believe that natural 

gas, recoverable with present technologies and at prices 

within reasonable future estimates, is immensely more 

abundant than even recent, more optimistic calculations 

suggest. The analysis that follows is both general and speculative in nature and is included here to stimulate discussion 

and promote the research and development that is necessary 

to achieve a fuller understanding of the natural gas resource 

base. This discussion assumes the validity of generally accepted ideas concerning the origin and stability of oil 

(which, as I explain below, I have many reasons to doubt) 

and does not take into account the newest information that 

may bring these established ideas into significant question 

(see Gold, this volume). 

Most petroleum scientists believe that oil forms from 

the breakdown of biological materials deposited in lakes, 

marshes, swamps, and along the flanks of continents. During burial, when temperatures reach about 95°C, the biological material kerogen begins to convert to bitumen, oil, 

and natural gas. This process continues to about 175°C, a 

temperature above which it is thought that oil can no longer exist and will partially break down to methane and 

other light hydrocarbons. At higher temperatures, in the 

presence of sufficient hydrogen, oil and kerogen are converted to methane. Specialists in the field of maturation of 

organic material estimate that 50 to 70 percent of total 

kerogen is converted to oil and natural gas. In the absence 

of hydrogen, graphite is the end product. Oil generation 

thus takes place geologically at relatively low temperatures and pressures, so, unlike natural gas, the physical 

and geological limits of the oil window are narrow. 

The window of generation for natural gas, on the other 

hand, seems to have no practical physical limits within and 

even beyond the confines of known sedimentary basins. 

Natural gas is generated biogenically, through the action of 

microorganisms, at ambient, and quite possibly much higher, temperatures and pressures. Thermogenically, generation 

of methane occurs throughout the "oil window." Above 

175°C methane can be generated from oil and other hydrocarbons to temperatures that may exceed 600°C (Hunt, 

1975). Moreover, after the process of oil and gas generation 

and migration from source rocks has taken place, significant 

amounts of kerogen, bitumen, and oil remain at or near the 

place of origin, available for conversion to additional quantities of natural gas. My rough calculations (appendix B), 

experience, and intuition, as well as some research by others 

(Comer and Hinch, 1987), indicate that the quantity of natural gas ultimately generated from the original biological 

material can be assumed to be approximately four times the 

mass of oil generated. 

For this to occur, a large source of additional hydrogen must be available, as the original organic material 

does not contain enough hydrogen for efficient conversion 

to take place. The availability of hydrogen is always the 

main limiting factor for the generation of oil and natural 

gas, as well as for the continued generation of methane at 

temperatures and pressures beyond the oil window. A 

number of factors suggest that ample hydrogen is available to drive the process: (1) Hydrogen is one of the most 

abundant elements in the solar system and is found 

throughout the Earth's sediments, (2) hydrogen may diffuse upward through the crust as a result of subduction of 

water under the continents and (or) continued outgassing 

from disassociation of hydrogen-rich compounds associated with the Earth's origin, (3) hydrogen is found in many 

of the deepest test wells drilled (Behr and Raleigh, 1988; 

Kozlovsky, 1986) and is often vented from volcanoes and 

midocean rifts (Krauskopf, 1982); and (4) at higher temperatures, in the absence of hydrogen, any remaining oil 

and unconverted kerogen would be converted to graphite. 

However, the presence of graphite in sedimentary and 

metasedimentary rocks is low compared to the volume of 

oil and gas, a fact which suggests that sufficient quantities 

of hydrogen have been available to allow conversion to 

hydrocarbons. 

By accepting the assumption that the quantity of 

methane generated from organic materials is at least four 

times that of oil, we may then estimate the natural gas 

resource base as a multiple of known quantities of oil in 

the United States. These calculations for natural gas utilize 

a simple multiple of the original oil in place, adjusted for 

differences in recoverability of oil and natural gas. I assume here an average recoverability for oil of 30 percent 

and for natural gas of 80 percent. These figures are both 

approximations. Though oil field recovery may reach 40 

percent or more in some fields, in others it may be as low 

as 20 percent and in a few cases even as low as 10 percent. Therefore, on a historical basis, the assumption of 30 

percent recoverability is perhaps reasonable. 

Estimate of all U. S. conventional oil reserves ( Bbo=billion barrels of 

oil): 

(1) Proven reserves (Howell and others, 1993)-------------

(2) Undiscovered resources (Mast and others, 1989)------

(3) Already produced reserves (Janet Rains, GHK 

Company, oral commun., 1992, from a 

representative of the American Petroleum Institute)--

Ultimate recoverable resources -----------------------

Original oil in place (OOIP) (assuming ultimate 

recoverable reserves equal 30 percent of OOIP) ------

45.0 Bbo 

49.4 Bbo 

149.6 Bbo 

244.0Bbo 

813.0 Bbo 

Conversion to natural gas (Tcf=tril/ion cubic feet; 1 barrel oil ( Bbo )= 

5,800 cubic feet of gas): 

Assuming 4 to I ratio of gas in place to oil in place, 

then 813.0x4=3252.0 Bbo= ------------------------------- 18.906.2 Tcf 

Ultimate recoverable reserves estimated to be 80 

percent of gas in place=8,906.2 Tcfx0.80=------------- 15,125.0 Tcf 

Minus cumulative production to date 

(Potential Gas Committee, 1990) ------------------------ 730.0 Tcf 

U.S. Natural Gas Resource Base=-------------------- 14,395.0 Tcf 
NEW THINKING ABOUT NATURAL GAS 825 

This speculative estimate of methane originally generated and potentially recoverable is I 0 times higher than 

the conventional resource base estimates that now hover 

between 1,200 and 1,500 Tcf; because the calculations are 

based solely on proven amounts of oil entrapped and in 

place, they do not take into account early, biogenica~ly derived methane or methane hydrates nor the vast quantities 

of oil that may have leaked away during geologic history. 

We can reconcile the conventional estimates with the 

14,400 Tcf figure only by assuming that (I) trapping 

mechanisms for natural gas are not as effective as those 

for oil, and large quantities of natural gas have leaked, and 

continue to leak, into the atmosphere, or (2) much gas is 

located in reservoirs that have not yet been tapped (some 

of which may not be commercially producible, such as the 

high-pressure fractured shales of the deep Anadarko Basin 

and the tight gas reservoirs of the Green River Formation). 

At present, little data is available on the methane flux 

either in deep high-pressure regions or at the surface, and 

though some work ~s now in progress to establish what 

surface flux might be (see Clayton and others, this volume), considerably more research is needed in this area. 

We do know that natural gas accumulates in solid waste 

landfills and swamps without effective "caprocks" and that 

flows of natural gas streaming upward through the sediment column tend to form their own barriers to migration. 

These observations, along with my experience in natural 

gas exploration, indicates to me that trapping mechanisms 

for natural gas are effective, though perhaps not as efficient as those for oil. 

If this is true, then there must be a vast quantity of 

natural gas still in the crust that we have not yet located. 

The analysis above suggests that the original natural gas 

resource base may have been easily four times that of oil 

on an energy equivalent basis. I suggest that after leaking, 

the amount of recoverable natural gas remaining is likely 

to be, at a minimum, equal to the original amount of recoverable oil. Assuming that sedimentary basins contain at 

least as many reservoirs for gas as for oil (and they may 

well contain more), the recoverable natural gas resource 

base for the United States is thus likely to be in the range 

of 3,000 to 4,000 Tcf, rather than the 1,200 to 1,500 Tcf 

predicted today. This higher estimate is much more compatible with the enormous amounts of natural gas known 

to exist in the form of gas hydrates (see K venvolden, this 

volume) and in habitats such as the Anadarko Basin overpressured megacomplex. 

The focus here is not on the absolute accuracy of the 

larger estimates. Rather, I am suggesting that there exists a 

reasonable and supportable view of our natural gas resource base that is significantly higher than the one presently held by most oil and gas professionals. That many 

will disagree with this new view is understandable; whenever a paradigm shifts, new ideas seem uncomfortable and 

drastically out of line with what was held to be true. However, I have shown in a variety of ways that the view of 

natural gas resources that has resulted from oil thinking 

reflects a model that no longer fits the data. Though oil 

thinking applied to the realm of natural gas has held our 

creativity, our ingenuity, and our technological innovation 

in check, its hold on our thinking is now crumbling. We 

are in a time of fundamental reevaluation and some bold 

new thinking has begun. 

THE GOLD HYPOTHESIS 

Although the very large quantities of methane calculated above, and the much greater amount that could be 

estimated similarly for the world, can be explained generally by calling on conventional ideas about oil and natural 

gas, I question seriously whether the large quantities of oil 

and natural gas found in the Earth are of biological origin. 

Early in my career, I wondered why oil is usually found 

around the shallow edges of basins at depths less than 

10,000 ft, whereas natural gas, which is less dense and 

found above oil when they occur together, occurs in abundance below oil, down to the deepest levels drilled. Later, 

when deeper wells revealed the region of high-pressure 

natural gas and enhanced porosity below the transition 

zone at about 15,000 ft, I questioned the origin of this gas 

and wondered what mechanisms had created the large 

zone of abnormally high pressure lying below normally 

pressured oil and natural gas. As I began to develop my 

own conviction of the existence of vast natural gas resources, I wondered if the original organic content was indeed sufficient to provide the raw materials necessary to 

generate these potentially enormous reserves. 

When I first read an article in 1977 (article in New 

York Times, June 8, 197..7) concerning Thomas Gold's theory of the origin of hydrocarbons through outgassing of 

carbonaceous compounds from the mantle, I was immediately struck by how well Gold's abiogenic hypothesis fit 

my experience in drilling for and producing deep highpressure natural gas. Gold (1987), for example, discusses 

in detail the origin and effect of the "critical layer," a zone 

below which higher pressure regimes are encountered. 

Gold's critical layer is the transition zone I have described, 

below which all deep Anadarko Basin wells encounter abnormal pressures. In Gold's hypothesis, these abnormally 

high pressures are readily accounted for by the trapping of 

higher pressure gas from the mantle on its way toward 

lower pressure domains. Gold's ideas are presented in detail elsewhere in this volume (see Gold, this volume). 

Though I recognize that few geologists give credence 

to Gold's hypothesis, I have had personal communication 

with several physicists and petroleum geologists who do. 

However, most importantly, I cannot escape the fact that 

my knowledge and experience of natural gas, gained from 

operating many of the world's deepest and highest pressure 
826 THE FUTURE OF ENERGY GASES 

natural gas wells, are accounted for more clearly by Gold's 

ideas than by conventional theories of the biological/thermogenic origin of natural gas: Because of its enormous 

implications to the economy and the environment, Gold's 

hypothesis is an area of new thinking about natural gas that 

undoubtedly needs significantly increased study and research, in spite of the pressures of conventional thinking. 

CONCLUSIONS 

In the context of the broad review of energy gases presented in this volume we should remember that our knowledge of the Earth is still exceptionally limited, particularly 

as we drill deeper into the crust, into the realm of deep 

high-pressure natural gas. Although a number of papers in 

this volume reflect the new and exciting research that is 

taking place in the realm of energy gases, they also remind 

us of the present limits of our understanding. For example, 

compared to the hundreds of billions of dollars that have 

been spent on research and development of coal, oil, and 

nuclear energy systems and technology, pitifully little has 

been spent on the basic research necessary to understand 

the real potential of natural gas as a long-term energy 

source. As a result, our educational system, our national 

energy policy, and our economy have traditionally focussed on oil, coal, and nuclear energy. Though this focus 

is slowly changing, we continue to sustain the momentum 

in our society for the use of these less efficient, environmentally degrading energy technologies, even though their 

external economic and social costs have placed significant 

limits upon U.S. economic growth, particularly over the 

last decade. While debate over the role of various fuels 

during the next several decades will undoubtedly continue, 

the worldwide increase in use of natural gas clearly reflects 

the growing demand for a significantly cleaner, more efficient fuel. Even within the limitations of oil-based thinking, recent estimates of the natural gas resource base reflect 

a changing view of the abundance of natural gas. The size 

of the natural gas resource base is likely to continue to 

grow in proportion to the degree to which we are able to 

free our thinking from the comfortable limits of outdated 

perceptions and acc.ept the many new physical and chemical facts that surround the field of geology and the origin 

of our solar system. 

In my view, the long-term impact of natural gas as a 

primary component of our national energy mix will have 

profound and positive effects on our economy, our ability 

to compete in world markets, our national and global environment, our strategic defense systems, and ultimately our 

very role in the 21st century global community. By implementing policies that will allow natural gas to displace oil 

and coal and to become America's ·principal energy source, 

we will enhance the efficiency, productivity, and security 

of the economic system, reduce the pollution produced 

from energy consumption, and decrease the potential for 

future Middle East wars and predictable oil-price shocks. 

The impact of decisions made now concerning our energy 

future is so important that increased focus on scientific investigation of the origin and occurrence of natural gas has 

become urgent. I believe that such work will show that the 

world has more usable Btu's in the form of methane than 

in either oil or coal and that the United States has sufficient 

quantities of natural gas to sustain the increased use of this 

fuel as a principal energy source well beyond the middle of 

the 21st century. On the basis of new thinking about natural gas, I predict that: 

1. In the United States, natural gas will remain an affordable and reliable fuel beyond the middle of the 21st 

century. 

2. Natural gas will replace oil as the United States 

principal energy source within a decade. 

3. Natural gas is so abundant that the only limits to its 

use will be well in the future when C02 emissions from 

natural gas use could possibly begin to exceed limits set 

by future global warming treaties. 

4. Natural gas use will be exceptionally good for the 

global economy for both developed and developing nations. 

In the developed countries, the increased use of natural gas 

will enhance economic efficiency, expand production, and 

decrease pollution and carbon dioxide. In the developing 

countries, the use of locally derived natural gas will reduce 

the capital required to produce the energy necessary for 

economic growth and, at the same time, allow these countries to conform to global environmental goals. In China, 

for example, the use of its vast supplies of natural gas 

(Hefner, 1985) will stimulate growth by reducing demand 

for capital and by removing huge quantities of coal from its 

already bottle-necked transportation sector. For developed 

economies such as the United States, increased use of natural gas will eliminate the enormous capital drain on our 

domestic economy that would be required by the development and continued use of frontier oil, "clean coal," or 

advanced nuclear technology. 

5. Natural gas is the beginning of the next long-term 

energy transition (fig. 11). Throughout human economic 

history, each transition in a basic energy system has been 

driven by a new wave of technological innovation and has 

uplifted increasingly larger segments of the world population to a higher quality of life. The human economy began 

with a long period during which we relied upon rather 

crude, dirty, solid sources of energy such as animal dung, 

wood, and coal. More recently, we have been in a period 

dominated by a more advanced, cleaner energy system 

based on liquids, using principally oil-based fuels. I think 

history will record this period as being relatively brief. The 

liquid/oil phase is declining even now and being superseded by the next long-term transition, which will be fueled by 

energy gases, beginning with methane and leading to hydrogen. As in the past, the energy-gas transition will contin-
NEW THINKING ABOUT NATURAL GAS 827 

100 

Wood 

I- I ~ 

UJ m 

:::s::: -

"' 80 Solids I 

~ 

a: ~~ Actual Consumption! 

::?!' 

....J 

~ Non sustainable Sustainable 

~ 60 economic growth economic growth 

LL 

0 

UJ 40 (!) Petroleum Oil and natural 

~ oil gas liquids 

z 

UJ 

u 20 "City gas' 

a: hydrogen 

UJ 

0.. 

0 

1850 1900 1950 2000 2050 2100 

YEAR 

Figure 11. Global energy systems transition forecasting the "age of energy gases." From Hefner ( 1993 ). Copyright, 1993, GHK 

Company. 

ue toward more technologically advanced, more efficient, 

and cleaner energy inputs to our economy. This transition 

will move steadily toward an environmentally benign energy system. As the age of energy gases advances, together 

with revolutionary changes in communications, information 

transfer, and education, the world economies will become 

increasingly capable of sustaining economic growth. To: 

ward the end of the 21st century, humankind for the first 

time will be able not only to lift the entire world population 

to and perhaps even beyond the standards of living and 

education now known only in the developed nations but to 

do so within a clean global environment. We must begin 

now to implement policies and economic change that will 

accelerate our transition into the age of energy gases. 

REFERENCES 

Al-Shaieb, Z., Puckette, J., Ely, P., and Tigert, V., 1992, Pressure 

compartments and seals in the Anadarko Basin: Oklahoma 

Geological Survey Circular 93, p. 210-215. 

American Gas Association, 1991, A comparison of alternative 

vehicular fuels with conventional gasoline: Gas Energy Review, v. 1, p. 9-13. 

Behr, H.J., and Raleigh, C.B., eds., 1988; Exploration of the deep 

continental crust, volume 1-Deep drilling in crystalline bedrock: Springer Verlag. 

Comer, J.B., and Hinch, H.H., 1987, Recognizing and quantifying 

expulsion of oil from the woodford formation and equivalent 

rocks in Oklahoma and Arkansas: American Association of 

Petroleum Geologists Bulletin., v. 71, no. 7, p. 844-858. 

Committee on Gas Production Opportunities, National Research 

Council, 1978, The potential for increasing production of 

natural gas from existing fields in the near term; final report 

to the Secretary of the Interior: National Technology Information Service, U.S. Department of Commerce, 110 p. 

Energy Statistics Sourcebook (7th ed.), 1992: Tulsa, PennWell 

Publishing Company. 

Enron Corporation, 1991, Outlook for Natural Gas: Houston, 

Texas, 15 p. 

Enron Corporation, 1993, The outlook for natural gas technology 

marches on: Houston, Texas, 15 p. 

Fisher, W.L., 1993, The new emerging domestic oil and gas industry: The Professional Geologist, p. 8-10. 

Flavin, Christopher, 1992, Building a bridge to a sustainable future, in Linda Starke, ed., State of the World, 1992: London 

and New York, W.W. Norton and Company, p. 27-45. 

Gold, T., 1987, Power from the Earth: London, J.M. Dent and 

Sons Ltd., 202 p. 

Gustavson Associates, Inc., 1992, Petroleum geology and exploration potential in the former Soviet Republics: Boulder, 

Colo. 

Hefner, R.A., III, 1978, The future for conventional U.S. natural 

gas supply-Aspen Institute, workshop on R and D priorities and the gas energy option: Aspen, Colo., Aspen Institute, 15 p. 

---1980, Depth-porosity relationships of the Anadarko 

Basin: Petroleum Engineer International, v. 52, no. 7. 

---1985, Onshore natural gas in China: World bank energy 

round table discussion on gas development in less developed 

countries. 
828 THE FUTURE OF ENERGY GASES 

---1992, An econergenic policy for 21st century AmericaEssential issues for debate in the 1992 Presidential election: 

Oklahoma City, Hefner Foundation, p. 17-19. 

---1993, The Hefner report, June 17th, 1993: Oklahoma 

City, Hefner Foundation, p. 6. 

Hefner, R.A., III, Kinchloe, R., Wheeler, R., Jr., 1973, The drilling and production of ultra-deep natural gas accumulations 

occurring below 20,000 feet in the Anadarko Basin: Proceedings of the 12th World Gas Conference, Nice, May 

1973. 

Howell, D.G., Bird, K.J., and Cunningham, R.D., 1992, Compressional tectonics point to more gas reserves: World Oil, 

v.213, no. 6,p. 117-120. 

Howell, D.G., Bird, K.J., and Gautier, D.L., 1993, Oil-When 

will we run out?: Earth: v. 2, no. 2, p. 26-33. 

Hunt, J.M., 1975, Is there a geochemical depth limit for hydrocarbons?: Petroleum Engineering, March 1975, p. 112-124. 

International Energy Statistics Sourcebook, 1992: Tulsa, PennWell Publishing Company. 

Jenkins, G., 1977, Oil Economists Handbook: London, Applied 

Science Publishers, Ltd., tables 4-12, p. 87-95. 

Kozlovsky, Y.A., 1984, The worlds deepest well: Scientific 

American, v. 251, no. 6. 

Krauskopf, K.B., 1982, Introduction to geochemistry, 2nd ed.: 

McGraw Hill. 

Kvenvolden, K.A., 1988, Methane hydrate-A major reservoir of 

carbon in the shallow geosphere?: Chemical Geology, v. 71, 

p. 41-51. 

Ulley and others, 1982, CH4, H2, CO, and N20 in submarine 

hydrothermal vent waters: Nature, v. 300, p. 48-50. 

Marchetti, C., Nakicenovic, N., 1979, The dynamics of energy 

systems and the logistic substitution model: Laxenburg, Austria, International Institute for Applied Systems Analysis, 73 p. 

Mast, R.F., Dolton, G.L., Crovelli, R.A., Root, D.H., Attanasi, 

E.D., Martin, P.E., Cooke, L.W., Carpenter, G.B., Pecora, 

W.C., and Rose, M.B., 1989, Estimates of undiscovered conventional oil and gas resources in the United States-A part 

of the Nation's endowment: U.S. Geological Survey/Minerals Management Service Report. 

Masters, J.A., 1979, Deep basin gas trap, Western Canada: 

American Association of Petroleum Geologists Bulletin, 

v. 63, p. 152-181. 

Maxwell, J .C., 1964, Influence of depth, temperature, and geologic 

age on porosity of quartzose sandstone: American Association 

of Petroleum Geologists Bulletin, v. 48, no. 5, p. 697-709. 

Melton, C.E., Giardini, A.A., 1974, The composition and significance of gas released from natural diamonds from Africa 

and Brazil: American Mineralogist, v. 59, p. 775-782. 

Nakicenovic, N., 1990, Dynamics of change in long waves, in 

Tibor Vasko and Robert Ayres, eds., Life cycles and long 

waves: Springer Verlag, p. 147-192. 

National Petroleum Council, 1992, The potential for natural gas 

in the United States, 1992, executive summary: Washington, 

D.C., National Petroleum Council. 

Petroleum Information Corporation, 1982, The deep Anadarko 

Basin: Petroleum Information Corporation. 

Potential Gas Committee, 1990, Potential supply of natural gas 

in the United States: Potential Gas Agency, Colorado School 

of Mines, p. 169. 

U.S. Department of Energy, Energy Information Administration, 

1990, The domestic oil and gas recoverable resource baseSupporting analysis for the national energy strategy: U.S. 

Department of Energy Report SR/NES/90-05, 56 p. 

U.S. Geological Survey, 1993, Gas (methane) hydrates-A new 

frontier: U.S. Geological Survey, Public Issues in Energy 

and Marine Geology, March, 1993, 2 p. 

USSR Ministry of Geology, 1991, Statement that a hole drilled 

on the Kola Peninsula had reached a depth of 40,226 ft.: Oil 

and Gas Journal, v, 89, no. 40, p. 34. 

World Oil, 1992, World trend-Operators abandon the U.S.: 

World Oil, v. 213, no. 8, p. 23-28. 

Yergin, D., 1991, The prize: New York, Simon and Schuster, 885 p. 
NEW THINKING ABOUT NATURAL GAS 829 

APPENDIX A. CALCULATION OF NATURAL GAS RESOURCES, ANADARKO BASIN, 

TEXAS AND OKLAHOMA. 

[Bg, formation volume factor; Sw, water saturation; OGIP, oil and gas in place; Scf, standard cubic feet; pet, percent; Tcf, trillion cubic feet] 

Depth Pressure 1 Temp2 Pressure Bg4 Porosity Sw OGJP5 Volume OGJp6 OGJP 

(ft) (psi) (OF) gradient Z factor3 

(Scf/ft3) (pet) (pet) (Scf/ft3) (ft3) (Scf) (Tcf) (psilft) 

10,000 4,600 160 0.46 0.970 270.52 4 90 1.08 1.3x1015 1.4x1015 1,407 

11,000 5,800 170 0.53 1.062 306.79 4 90 1.23 1.3x1015 1.6x 1015 1,595 

12,000 7,000 180 0.58 1.158 334.11 4 90 1.34 1.3x1015 1.7x!Ot5 1,737 

13,000 8,200 190 0.63 1.255 355.53 4 90 1.42 1.3xl015 1.8xl015 1,849 

14,000 9,400 200 0.67 1.351 372.93 4 90 1.49 1.3x1015 1.9xlots 1,939 

15,000 10,600 210 0.71 1.444 387.45 4 ~90 1.55 1.3xl015 2.0x1015 2,015 

16,000 11,800 222 0.74 1.534 398.97 4 90 1.60 1.3x1015 2.1xi015 2,075 

17,000 13,000 234 0.76 1.620 408.95 4 90 1.64 1.3xl015 2.lxl015 2,127 

18,000 14,200 246 0.79 1.703 417.73 4 90 1.67 1.3x1015 2.2xl015 2,172 

19,000 15,400 258 0.81 1.783 425.54 4 90 1.70 1.3x1015 2.2x1015 2,213 

20,000 16,600 270 0.83 1.860 432.56 4 90 1.73 1.3x1015 2.2xl015 2,249 

21,000 17,800 282 0.85 1.933 438.93 4 90 1.76 1.3x1015 2.3x1015 2,282 

22,000 19,000 294 0.86 2.004 444.75 4 90 1.78 1.3x1015 2.3xi015 2,313 

23,000 20,200 306 0.88 2.073 450.09 4 90 1.80 1.3x1015 2.314xl015 2,340 

24,000 21,400 318 0.89 2.138 455.04 4 90 1.82 1.3x1015 2.4xl015 2,366 

1

To 10,000 ft, 0.46 psi/ft; for depth >10,000 ft. 

2

To 15,000 ft, O.OI°F/ft; for depth >15,000 ft, 1.2 psi/ft plus 60 psi for ambient temperature. 

3

Calculated based on Z-factor correlation, gas gravity=0.59, N2=0 percent, C02=0 percent, H2S=O percent. 4

Bg=35.374 x (psi/Z factor) X (°F+460). 

5Bg x porosity x (1-Sw). 

60GIP(Scf/ft3

) x volume. 

APPENDIX B. CALCULATION OF THE AMOUNT OF RECOVERABLE NATURAL GAS 

AS A FACTOR OF KNOWN RECOVERABLE OIL. 

Note: This appendix is a very general calculation 

presented to provide some substantiation of the statement 

that the amount of recoverable natural gas should equal 1 

to 4 times the amount of recoverable oil. It is a highly 

simplified analysis of a process that is still not well 

known. Though it may well raise some questions, I provide it as an example of the ideas on which the statement 

is based. 

Assume 50 percent of kerogen is converted to oil, 30 

percent of oil migrates into reservoir, and 30 percent of 

migrated oil is produced from well bore; therefore, 4.5 

percent of original kerogen is produced as oil. This is a 

high estimate; 1 percent or 2 percent is the generally accepted figure. 

It follows, first, that 50 percent of original kerogen is 

available in some form, probably hydrogen deficient, for 

con-version to natural gas and, second, that 70 percent of 

oil generated does not migrate and remains in or near the 

source rock (in other words, 0.7 of original 50 percent kerogen converted), giving 0. 7x0.50=0.35 of original kerogen 

in place. 

Add H20, increasing temperature and pressure, and 

time, then 50 percent of original kerogen plus 35 percent 

of original kerogen now in form of oil or bitumen is available for conversion to natural gas. Assuming 50 percent is 

converted to natural gas, then 0.85x0.5=0.425 of original 

kerogen is converted to natural gas. 

Assume 60 percent migrates and 80 percent is produced from reservoir, then 0.425x0.6x0.8=0.2 or 20 percent of original kerogen is available for production as 

natural gas, or nearly 5 times the amount of oil available 

(4.5 percent of original kerogen). 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Natural-Gas Resources of North America 

By John A. Masters 1 

CONTENTS 

Abstract ....... ...... ... .. ................................... ..... ............... 831 

Discussion .. ............ .... ......... ............. ... ....... ..... .............. 831 

Conclusion .................................................................... 833 

ABSTRACT 

A natural gas shortage in the United States is anticipated during the 1990's because of declining reserves in 

the Gulf of Mexico. These cannot be replaced from the 

gulf. Western Canada and the Arctic contain enough reserves, augmented by U.S. reserves, to see us through the 

next 50 years but at increasing prices. A large amount of 

unconventional gas is recognized in the United States. 

Largely unrecognized is an enormous potential for stratigraphically trapped, conventional gas, which can be found 

by careful evaluation of the United States' national treasure of 3 million wells; no other country in the world has a 

comparable subsurface data base. In the farther future, hydrogen is a potential energy source. Our science can locate 

natural-gas resources and provide the technology for development. However, the tax and price policies of the U.S. 

Federal Government can either encourage natural-gas development or completely stifle it. 

DISCUSSION 

Natural gas is used in great quantities only in the 

United States, Russia, and Europe and is supplied from 

•canadian Hunter Exploration Ltd., 2000, 605-Sth Ave., SW, Calgary, Alberta, Canada T2P 3H5. 

nearby sources because it cannot be transported economically by water. Thus, Russia and Europe are supplied by 

pipeline from the vast gas reserves of Russia and from the 

North Sea. There is plenty available for a long time, and 

huge reserves in the Middle East can backup the whole 

supply system. However, the United States is supplied 

only from domestic and Canadian production, and the 

known reserves are not nearly so large as those in Russia 

and surrounding areas. There is a looming supply problem 

in the United States. The reserve-to-production ratio in the 

United States has fallen from 38 years in 1946 to 9 years 

in 1990. It will take considerable luck and a giant effort to 

reverse this trend. 

A near-term natural-gas shortage in the United States 

appears to be inevitable because of the abrupt decline in 

offshore Louisiana reserves, which supply one-third of the 

entire U.S. market. These high permeability reservoirs will 

be completely drained in about six years. For the last six 

years very little drilling to replace reserves has been done 

in the Gulf of Mexico because of low gas prices; thus, the 

fields presently producing are about depleted. For 40 years 

we have been able to treat the Gulf of Mexico as an endless source of new gas fields. We have innocently believed 

that as soon as the present supply disappeared prices 

would go up, the rigs would start drilling again, and the 

gas would continue to flow. However, the whole gulf has 

been covered with 3-dimensional seismic-every large 

company has it-and they agree there are no more large 

structures on the shelf in water depths less than 600 feet. 

Beyond this depth, the water gets deep fast, and we must 

deal with radically different economics and long lead 

times before production begins. Also, the deep-water production so far has been oil, and information is not available to determine how much gas will be present. 

We will soon experience some sharp price rises, which 

will put the rigs back to work around the country. However, vastly improved reflection-seismic data gives us an 

831 
832 THE FUTURE OF ENERGY GASES 

uncharacteristically precise answer that there are little 

more significant reserves of economic gas in the Gulf of 

Mexico, and we know there is no basin or group of basins 

in the United States that can replace such a large supply of 

natural gas in the next decade. 

Mexico probably has large natural-gas reserves, which 

have been overlooked and bypassed in its concentrated 

search for big oil fields. It would take many years and large 

investments, however, before Mexico could begin sending 

gas north. In fact, Mexico is now importing gas from southern Texas. The Western Canadian basin has excess reserves, 

which can flow south, and so does Arctic Canada and the 

North Slope of Alaska. Environmental barriers, Native land 

claims, new pipelines, and Canadian internal supply and 

demand will all have to be considered, but it is from the 

north that the United States will get its natural gas. 

I have a general idea that these current and future 

northern gas supplies could compensate for most or all of 

the decline in Gulf Coast production of natural gas for the 

next 20 years. Someone with more data should be able to 

model this scenario better than I. The United States can 

supply the balance from its conventional and nonconventional sources of natural gas for several decades. Likely, 

we will have exhausted all our $1 per Mcf (thousand cubic 

feet) natural gas before that time, but there will be plenty 

of gas for 50 years or more at progressively higher prices. 

After 50 years there will be a range of options, which we 

can only guess at today. 

Assuming that the U.S. gas shortage causes a substantial price rise, before northern gas can be brought down to 

the United States in quantity, the shortage will encourage 

enormous efforts in the United States to extract more gas 

from tight sands, coal beds, fractured shales, and very deep 

reservoirs in the Gulf of Mexico, and the Anadarko, the 

Delaware, and a few Rocky Mountain basins. These basins 

are the only ones in the United States with ultradeep sediments that are known to carry gas. I do not expect deep 

drilling to contribute more gas than can normally be estimated from the additional volume of sediments penetrated, 

making allowance for the higher pressures. 

Pressures and pressure cells must be an integral part 

of deep-gas exploration. Careful petrographic description 

of samples and cores must be calibrated with well logs. 

Well logs alone are very confusing at great depths. Careful 

selection of drilling muds and optimum reservoir fracturing techniques will be needed. Primary and secondary porosity at depth are closely related to overpressure and the 

history of overpressure. Remember, pressures that you observe today are not necessarily indicative of pressures that 

the rock has been subjected to during its long history. 

Despite periodic "locker room" talks by Levorsen, 

Halbouty, and others, the petroleum industry has never seriously explored for stratigraphic traps, probably because 

we are so intellectually dependent on the seismic exploration technology. A vast amount of subsurface data is available to evaluate nearly 20,000 miles of porous rock wedge 

outs in the United States, the same kind of wedge outs that 

produced the East Texas, Lima-Indiana, Appalachian trend, 

Southwest San Joaquin, Golden Trend, and other prolific 

oil and gas fields. It's unfortunate that the geological community has not provided regional zero-edge porosity maps 

of the entire geologic section integrated with structure, 

shows, source rocks, hydrodynamics, land availability, and 

drilling recommendations. 

There is no way to anticipate how much gas and oil can 

still be found in the United States by looking for the kind of 

traps that we have ignored in the 75 years since Frank 

Buttram showed that Cushing was on an anticline. We have 

known all this time that oil and gas occur primarily in anticlines and updip wedge outs of porosity. We developed an 

effective seismic tool to find anticlines and have used it 

until we have run out of anticlines. In the process we inadvertently found a number of large stratigraphic traps. Despite the obvious existence of stratigraphic traps, the whole 

U.S. petroleum industry acts as if the United States offers 

no more exploration opportunities and therefore focuses 

most of its exploration efforts overseas. Wallace Pratt told 

us we would run out of oil when we ran out of ideas. 

The U.S. petroleum industry is ultimately responsible 

for two of the Nation's vital resources-oil and natural gas. 

If economic evaluation dictates a decision to conduct seismic 

surveys overseas to look for easily found anticlinal oil fields, 

I cannot dispute that. However, for equally compelling economic reasons, we need to find our gas in North America. 

I believe there is a lot of oil and gas to be found in 

stratigraphic traps in the United States, both updip from 

water and downdip from water. We should continue to 

apply seismic technology as effectively as possible but 

should not try to push it past its level of competence. More 

importantly, we have a huge amount of subsurface evaluation technology and data available that we have not really 

learned to use. The United States is the only country in the 

world with 3,000,000 wells. 

We will always need research and development into 

better methods of well log and core evaluation and completion techniques; most importantly, we need to understand 

and apply the techniques and data we already have. Too 

many companies are technologically 20 years behind the 

times. Of course, everyone would love to have a new geophysical tool, but short of that, the most important advance 

for stratigraphic exploration would be cheaper drilling. 

Other potential gas sources are deep coal-bed gas 

from wells, coal gasification, biomass conversion, abiogenic gas under permafrost seals in the Arctic, hydrates, 

gas dissolved in high-pressure water, and perhaps most favorable, hydrogen; these sources are all expensive to ex-
NATURAL-GAS RESOURCES OF NORTH AMERICA 833 

ploit. When we ultimately run out of hydrocarbons, the 

only remaining fuel source is hydrogen. It is clean and 

renewable, will bum in our car engines, heat our boilers, 

and flow through our existing pipelines. At first hydrogen 

will be extracted from methane, but its long-term source is 

water. It can be separated from water by electrolysis supplied by hydroelectric power, in part; however, hydrogen 

could eventually be separated by solar or nuclear energy. 

We would trade electrical energy, which cannot be transported long distances or stored effectively, for hydrogen, 

which can flow through pipelines. It will be expensive, but 

our energy-dependent society may have no choice. 

One of the many problems with the prediction of energy-utilization patterns is unforeseen technological changes. 

These changes are very hard to predict. Improvements in 

electrical transmission and battery storage could virtually 

eliminate the need for hydrogen. Another change looming 

on the horizon is cost reduction for gas liquefaction, shipping, and storage. Alternatively, if the delivered price of 

natural gas in New York City increased to approximately 

$4.00 per Mcf, then large shipments of liquefied natural 

gas from some of the enormous overseas reserves in the 

Middle East or Southeast Asia might become economically 

competitive. The cost of gas in New York City today is 

$2.50 per Mcf and going up. If an increase to $4.00 per 

Mcf would cover the production and transportation costs of 

liquefied gas, then such an increase should not impose an 

impossible economic burden on consumers and would 

quickly be accepted in preference to "freezing in the dark." 

CONCLUSION 

The rush to explore for oil overseas overlooks our 

need to develop greater gas resources located here in the 

United States and the vast potential for stratigraphic traps 

in the United States. Deregulation allowed the decline of 

gas prices to near-disastrous levels. If the U.S. Government 

does not panic now as gas prices recover, the petroleum 

industry will have a chance to see if adequate supplies of 

natural gas can be found. If consumers dictate price controls again, they will create the fuel shortage they fear. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

The Future of Methane and How We Get There 

By Michael Roberts 1 

CONTENTS 

Abstract . .. .. .... .. .... .. . ............. ............ .. .. .. ..... .. .. ........ .... .. . 835 

Perspective .................................................................... 835 

Resource Curves .. . ....... .. . ... ...... ... . ..... .. ... .... ... .. ... . . ......... 836 

A Better Method-The Method of Attribution ............ 837 

The Best Method-The Resource Pyramid ................. 839 

How We Get There From Here-Policy ...................... 840 

Conclusion .................................................................... 841 

References Cited ... ....... .. ... ....... .. ....... .. ... .... ... .. ...... ........ 841 

ABSTRACT 

The future of methane is in our own hands. Recognition of previous resource analyses enlightens our current 

perspective of the supply of natural gas in the United 

States. Learning from the lessons of the past, we can adopt 

and advance the still-working hypotheses of previous studies and abandon any misguided policies that were based on 

the no-longer-working hypotheses. The natural-gas resource base is sufficient not only for long-range supply 

needs of existing uses but also for the needs of a greatly 

expanded market of new uses as well. Technology advancement is the key to lower costs and improved productivity. 

We can order the "march of technology" into double time. 

The cadence can be increased by government policies supporting research and providing incentives. We can get there 

from here. 

PERSPECTIVE 

When addressing a topic such as "The Future of Methane," one must first acknowledge the thinking of past re1

Enron Corp., P.O. Box 1188, Houston, TX 77251-1188. 

searchers. This acknowledgment, however, does not 

necessarily require one to be constrained by previous 

thought processes or concepts. Also, in the context of scientific inquiry, one should not criticize predecessors for not 

being beneficiaries of knowledge that was not available to 

them in their own time but is common today. Isaac Newton, a mathematical visionary, said that he had been able to 

see farther than others because he had "stood on the shoulders of giants." In the field of natural gas resource analysis, 

there are numerous "giants" who have preceded us. Among 

these giants were Wallace Pratt and M. King Hubbert. 

They happened to be contemporaries, and each an expert in 

a different discipline (geology and physics, respectively). 

Each also was a visionary in the field of resource analysis, 

but each was a prisoner to the generation in which he participated and subject to the limitations of the accumulated 

knowledge base with which that generation was endowed. 

Each of these giants, however, thought beyond the constraints of his existing information base, each to a different 

extent. Wallace Pratt encouraged exploratioriists to explore 

the depths of their own minds to find new resources. M. 

King Hubbert anticipated the full implementation of existing and developing production technology (but not the onslaught of unforeseen technology). The giant leap we can 

make today is to stand on their shoulders and embrace the 

notion that unforeseeable technology gains can and must 

be incorporated into our long-range resource planning. Unless this anticipation is not only acknowledged but quantified as well, we will see that our resource estimates will be 

periodically, and inevitably, revised upward as time passes. 

Another notion that should be understood is that of the 

reserve-life index. This notion is an accounting fiction 

based on the Security and Exchange Commission's need 

for standardized measures. Reserves are those volumes of 

oil and gas that have satisfied the Security and Exchange 

Commission's requirements to be included in the supplemental disclosure sections of annual financial reports. 

They are more or less an inventory item. Resources, on 

835 
836 THE FUTURE OF ENERGY GASES 

the other hand, include these proven reserves and (1) probable reserves, (2) possible reserves, (3) undiscovered reserves, and (4) any substance from which petroleum can 

be derived (with improved technology or more favorable 

economics) (Levorsen, 1967). For long-range planning 

purposes, a reserve-life index is irrelevant. The correct 

index would be based on resource life. 

In 1952 Wallace Pratt issued a challenge to the new 

breed of explorationists (Pratt, 1952). Their adopted battle 

cry was one of Pratt's most famous themes-"Oil is found 

in the minds of men." Their conceptual tools included old 

ideas in new areas, new ideas in old areas, and most importantly, new ideas in new areas. 

RESOURCE CURVES 

In 1956, M. King Hubbert, now recognized as one of 

this nation's most pragmatic resource analysts, completed 

his classic article on the future of fossil fuels (Hubbert, 

1956). Hubbert's basic premise was that all natural resources could be characterized by a production curve similar to a bell curve. "Two points are known at the outset," 

he observed, "that at t=O and again at t=infinity. Production at both these points is zero." Hubbert then invoked 

the fundamental theorem of integral calculus to characterize and quantify the area under the curve as being equal to 

the volume of production ultimately produced. Basically, 

rate times time equals volume. Tacit in Hubbert's resource 

curves were the maturity of exploration and learning-curve 

concepts of exploration geologists. In the very early exploration stages of any region, the resource is large and untapped but the learning curve is steep. Success rates are 

low and costs are high. In the intermediate stages of exploration, the accumulated knowledge about stratigraphy 

and the applicability of geophysical devices combine with 

large and prolific traps to yield highly profitable and productive ventures. Finally, in the end stages of exploration 

of any particular play or region, the remaining unfound 

fields are small and it is up to technological progress to 

offset declining target sizes with reduced finding costs to 

yield profitable exploration results. 

To demonstrate that the production of exhaustible reserves actually does behave in this manner, Hubbert cited 

actual oil production curves of two of the older producing 

areas-Illinois and Ohio (Hubbert, 1956). The data available 

to Hubbert at that time covered a period up to the summer of 

1955. The Illinois data available to Hubbert (augmented by 

data available to us in 1993) are shown in figure 1. Oil 

production was seen to peak in 1910. It underwent a slow but 

steady decline until 1936, and then increased dramatically to 

a new peak in 1940. Hubbert correctly identified this new 

peak as being due to a new cycle of exploration (using the 

seismograph). Hubbert also correctly predicted that there 

were still more as yet undiscovered resources. With the 

benefit of almost 40 years of additional data, Hubbert's 

estimate of 4 billion barrels of ultimate oil production for 

Illinois seems remarkably accurate. 

The undiscovered resource in Illinois, however, was 

not really so unknown as to be considered mysterious in 

any way. Hubbert knew that the Middle Ordovician formations below the St. Peter Sandstone were likely to be of 

reservoir quality and hydrocarbon bearing. This undiscovered resource was not really a mystery resource requiring 

a technological breakthrough, in that it could be approximately identified and measured. It could be readily appreciated by engineers and geologists alike. 

An update of the Ohio production, however, shows 

more startling consequences of the lack of acknowledgment and quantification of the unexpected (fig. 2). Hubbert 

had described the Ohio data (as much of it as he had) as 

reaching a maximum between 1890 and 1900, and thereafter undergoing a "slow, steady decline" (Hubbert, 1956). 

Had Hubbert made some provision for unidentified but potential new productive formations, he may have come 

closer to what we now (with the benefit of 40 years of 

additional production history and exploratory data) predict 

as the ultimate oil production for Ohio. Had Hubbert gone 

one level of abstraction farther than that, he might have 

attributed additional recoverable resources to the development of new technology rather than to the mere application and advancement of existing technology. 

Hubbert was well aware of the potential of water 

flooding and accounted for it in his more optimistic estimates (Hubbert, 1956). He could not, however, have anticipated specifically the production efficiency gains to be 

later realized by miscible flooding (C02 and propane), 

caustic and polymer flooding, and thermal recovery methods such as steam flooding and in-situ combustion. These 

160~----------------------------------· 

a:: 

~ 140 

>-

0::: 120 

LU 

a. 100 C/) 

...J 

~ 80 

a:: 

~ 60 

~ 40 

:::::i 

~ 20 

Data available 

in 1956 

0

1880 1900 1920 1940 1960 1980 2000 2020 2040 

YEAR 

Figure 1. Oil production in Illinois. Solid line, actual production; 

dashed line, future production predicted on basis of data available in 1993; dotted lines, three cases foreseen by Hubbert 

(1956). Data available in 1956 are from Hubbert (1956); data 

available in 1993 are from Department of Energy, Energy Information Administration ( 1992). 
THE FUTURE OF METHANE AND HOW WE GET THERE 837 

techniques had not yet been discovered, nor had the physical and chemical principles on which they depend. As 

Wallace Pratt so eloquently put it, "The tendency of the 

human mind is to discount or ignore the significance of 

what remains unknown to it" (Pratt, 1952). 

The brilliant thinking of M. King Hubbert was unfortunately dimmed by his own pragmatic thought processes. 

His forecasts for oil production in the total lo\\;'er 48 States 

(fig. 3) (Hubbert, 1956) were ultimately seen to be unreasonably conservative. They did not account for the march 

30r------------------------------------, 

0::: 

<( 

~ 25 

0::: 

~ 20 Cl) 

....J 

~ 15 

0::: 

<( 

IXl 10 

z 

0 

3 5 

:::!: 

Data available in 1956 

/ Data available in 1993 

-.!993 

' Proje •.. ..?_956 Pro· .......... Cfion 

··-......... J.f!:~.~~?-'!. ........ _- - 0~--~~~--~-.....1--~---L---L-=~~ 

1880 1900 1920 1940 1960 1980 2000 2020 2040 

YEAR 

Figure 2. Oil production in Ohio. Solid line, actual production; 

dashed line, future production predicted on basis of data available in 1993; dotted line, production predicted on basis of data 

available in 1956. Data available in 1956 are from Hubbert 

( 1956); data available in 1993 are from Department of Energy, 

Energy Information Administration ( 1992). 

4 .---~~----~--------~--~----~ 

0::: 

~ 

>- 3 0::: 

w 

a.. 

Cl) 

....J 

w 2 

0::: 

0::: 

~ 

z 

0 

:J 

....J 

Data available in 

1956 

" Data available 

r . ..A in 1993 

•• '¥ 

• 

CD 

ou__.-. .. ~-L--~--L-~~~~~ 

1~1~1~1~1~1~~0~5~0 

YEAR 

Figure 3. Forecasts for crude-oil production in lower 48 States. 

Diamonds, data available in 1956; stars, additional data available 

in 1993; heavy solid line, production predicted on basis of data 

available in 1993; intermediate line, production predicted on 

basis of data available in 1960; light line, production predicted 

on basis of data available in 1956. Data available in 1956 are 

from Hubbert (1956); data available in 1993 are from Department of Energy, Energy Information Administration (1992). 

of technology. Is there a better way? Can the unforeseeable be quantified? 

In the early days of petroleum exploration, natural gas 

was thought of not only as having a bleak future, but also 

as having an unpromising present. Insurmountable problems of transportation, storage, and marketing precluded 

any long-range consideration of this clean-burning fuel as 

being of any significance. Many oil exploration wells were 

plugged with the simple epithet: "just gas found-plugged 

well." By M. King Hubbert's time, gas was recognized as 

being a legitimate fuel source, but it was still in its infancy 

of understanding. As shown in figure 4, Hubbert saw the 

Texas gas production peak at less than 7 trillion cubic feet 

(Tcf) per year, and the total domestic peak (fig. 5) at less 

than 15 Tcf per year (Hubbert, 1956). In 1972, Texas actually produced more than 8.5 Tcf, and the Nation produced 

more than 22.5 Tcf. The natural-gas industry was in need 

of a better way of evaluating its potential. 

A BETTER METHODTHE METHOD OF ATTRIBUTION 

The Potential Gas Committee (PGC) has the longest 

standing resource estimation-reporting history. This committee has prepared and published analyses biennially 

since 1964 (with the exception of 1974). The PGC is 

made up of representatives from all segments of the U.S. 

gas industry as well as representatives from academic institutions and government agencies. Its resource estimates 

0::: 10,000 r-------------------------------, 

<( 

w 

~ 8,000 

w 

a.. 

ti:i 6,000 w 

u. 

u 

CD 4,000 

:::::l 

u 

z 

0 2,000 

:J 

....J 

CD ·······-' ......... _ 0

1900 1920 1940 1960 1980 2000 2020 2040 2060 

YEAR 

Figure 4. Natural-gas production in Texas. Solid line, actual production; dotted line, production predicted on basis of data available in 1956; dashed lines, production predicted on basis of data 

available in 1993. Upper dashed line ~epresents prediction based 

·on stabilized deliverability; lower dashed line represents prediction based on no replacement of reserves. Area between the two 

dashed lines represents the "gas gap" (see Howell, Wiese, and 

Swinchatt, this volume). Data available in 1956 are from Hubbert (1956); data available in 1993 are from Department of Energy, Energy Information Administration ( 1992). 
838 THE FUTURE OF ENERGY GASES 

have recently been on the low end of the spectrum of 

other forecasts, and an analysis of the PGC's methodology 

yields an explanation for its apparent conservatism. The 

PGC has adopted the "method of attribution" as their analytical procedure. In this method, reservoir attributes are 

identified in currently producing reservoirs in known fields 

and statistically attributed to undrilled areas. 

While this method seems logical and rigorous enough 

and is performed by competent and experienced personnel, 

some amount of resource will of necessity always be unaccounted for because of the absence of existing reservoirs 

using not-yet-available technology and (or) existing technology not being applied to unanticipated reservoirs (new 

ideas in old areas and old ideas in new areas). 

Examples of the impact of not anticipating the unknown abound in our domestic exploration and production 

history. In the 1940's, prior to the invention of the hydraulic fracturing technique, there were no low-permeability 

producing formations under existing production from 

which to project attributes to other, similar, not-yetproducing low-permeability formations. In the 1950's, 

prior to the development of relative-amplitude anomaly 

(bright spot) technique and semisubmersible drilling rigs, 

there were no offshore fields from which to project attributes. In the 1960's, prior to the understanding of gas 

transport and storage mechanisms in coal, there were no 

coalbed methane fields from which to project attributes. In 

the 1970's, prior to the development of the massive hydraulic fracturing technique, there were no fields in tight 

(low-permeability) sands from which to project attributes. 

In the 1980's, prior to the understanding of reservoir appreciation, amplitude-versus-offset (AVO), and cross-well 

tomography, there were no reserves attributed to bypassed 

Data 

... 

•• 

.... 

iy' 

: available : 

in 1956 r 

\ lsso Tcf 

• ultimate 

Data 

available 

in 1993 

Figure 5. Natural-gas production in lower 48 States. Diamonds, 

data available in 1956; stars, additional data available in 1993; 

solid line, production (ultimately totalling 850 trillion cubic 

feet) predicted on basis of data available in 1956. Data available 

in 1956 are from Hubbert ( 1956); data available in 1993 are 

from Department of Energy, Energy Information Administration 

(1992). 

or nonconnected in-fill pockets. What is to be said of the 

1990's in retrospect is unknown to us at this time, but it 

would be myopic to assume that we have uncovered all of 

nature's secrets and exhausted the inventiveness of the 

human mind. 

The PGC's estimate of the ultimate recoverable resource base must of necessity increase with time using the 

method of attribution. The slow but upward growth of this 

resource estimation methodology is depicted in figure 6. 

Because of the PGC's biennial estimation cycle,. some 

measure of technological growth is captured every other 

year, but resources specific to unforeseen long-term technological growth will appear to be discounted relative to 

estimates which attempt to quantify that which cannot be 

specifically described. 

A good example of the need to either anticipate the 

introduction of new technology or commit to periodic increases in a resource estimate can be found in the coalbeds 

of northwestern New Mexico. In 1977, the Energy Information Administration (EIA) took over the responsibility 

of oil- and gas-reserve reporting and stated that the "New 

Mexico-West" region held gas reserves of 8,044 billion 

cubic feet (Bcf) as of the beginning of the year. As there is 

no production in southwestern New Mexico, this estimate 

essentially represented reserves in northwestern New Mexico. Thus, the New Mexico portion of the geologic region 

known as the San Juan Basin was estimated to contain 5.5 

percent of the lower 48 States' nonassociated gas-reserve 

base. Since that time, production from the basin has been 

5,555 Bcf. In its most recent report (U.S. Department of 

Energy, Energy Information Administration, 1992), the 

EIA recognizes 16, 131 Bcf of nonassociated gas reserves. 

1,800 ...------------------. 1,800 

1- 1 ,600 1 ,600 

ltl1 ,400 1 ,400 u.. 

() 1 ,200 1 ,200 

m 

::::J 1 ,000 1 ,000 

() 

z 800 800 

0 

:J 600 600 .J 

0:: 400 400 

1-

200 200 

0 0 

66 68 70 72 74 76 78 80 82 84 86 88 90 

YEAR OF 19XX 

Figure 6. Natural-gas resources in lower 48 States as estimated 

by Potential Gas Committee (1966-1990). Dotted lines at 1,400 

and 1,600 trillion cubic feet are shown to help readers recognize 

the slow but upward growth of potential-resource estimates made 

using the method of attribution (see text for explanation). Estimates of potential coalbed methane are shown separately because 

the Potential Gas Committee added a new group to evaluate this 

technology-dependent resource. 
THE FUTURE OF METHANE AND HOW WE GET THERE 839 

The basin is now estimated to contain 11.5 percent of the 

lower 48 States' nonassociated gas-reserve base. In a 15-

year time period, the industry appears to have produced 

almost 70 percent of the reserves once estimated, but in 

reality, over the same time period, has more than doubled 

them! This procedure of converting resources to reserves 

is highly dependent on the development of new technology. In this case it was critical to understand the storage 

and release mechanisms of methane in relation to solid 

coal and to develop new drilling techniques to take advantage of naturally occurring cleat systems coupled with new 

techniques for completion (all downhole activities subsequent to evaluation but prior to actual production) such as 

cavitation (see Rice, this volume). 

THE BEST METHODTHE RESOURCE PYRAMID 

The "resource pyramid" concept is shown in figure 7. 

Many people think of the natural-gas resource base as a 

finite volume, measurable with existing analytical yardsticks using current technology. An alternative view of the 

resource base is the resource pyramid, a more dynamic 

method of mineral-resource analysis. The resource grows 

with advancing knowledge and technology. Much has been 

written in economics literature concerning nonrenewableresource extraction programs. Deposits may be thought of 

as a series of layers of homogeneous quality, for which perunit extraction costs increase with depth. Alternatively, the 

deposit may be of constant accessibility but of a heterogeneous nature. In either case, as quality (or accessibility) deteriorates, the marginal extraction costs increase. Also in either 

case, the resource becomes unprofitable before it is physiConventional Low grade 

Non-conventional 

* Tight gas 

Devonian shales 

Deep gas 

Gas hydrates 

' O(fd 

• 

Figure 7. The resource pyramid, a method for estimating naturalgas resources that assumes the resource base will increase with 

advancing knowledge and technology. Drawings at right show 

that per-unit extraction costs increase with depth in pyramid. 

Conventional resources are in sandstones and limestones in conventional traps; nonconventional resources are more technologydependent resources. 

cally exhausted. The effect of technological improvement is 

to either lower extraction costs or improve accessibility. The 

Fifth World Congress of the International Economic AssoCiation (Tokyo, 1979) addressed concerns about perceived 

limitations on economic growth imposed by expected scarcities of natural resources. One key question was: "Are 

there really depletable resources?" The answer is "yes" if 

and only if there is an associated "cessation, once and for 

all, of technological progress" (Boserup, 1979). This is 

clearly not the case. Technological progress is alive and 

well, and technology is the most powerful nonprice determinant of supply. Applying this concept to natural gas as 

shown in figure 8, the high-grade portion would be what is 

generally referred to as conventional resources (those that 

can be recovered from traditional reservoir types using traditional production practices), 760 Tcf of which has already 

been produced. The major portion of the 160 Tcf of gas in 

inventory (reserves) is conventional. As we explore deeper 

into and extract deeper from the pyramid, the resource becomes lower and lower in grade and more and more expensive to recover. According to the National Petroleum 

Council (1992), approximately 825 Tcf of the estimated 

1,135 Tcf of higher cost undiscovered gas lies in this region 

of the pyramid at recovery costs below about $3.50 per 

million British thermal unit (MMBtu). Approximately 600 

Tcf can be recovered at below $2.50 per MMBtu. One will 

exploit the resource pyramid as deeply as economics will 

permit. Coalbed methane, gas from tight sands, and Devonian shale gas were recent beneficiaries of a governmental 

tax-incentive program (Section 29 of the Internal Revenue 

Tax Code). With this support, technology was developed 

and transferred to the field, which resulted in tremendous 

conversion of resources to reserves, as seen in the San Juan 

Basin example. 

The U.S. Geological Survey estimates that there are 

5,000 Tcf of gas in place in the greater Green River Basin 

Inventory 160 

NPC appraised 

1,135 

Figure 8. Resource pyramid showing natural-gas resources in 

lower 48 States as estimated by National Petroleum Council 

(1992). Values are in trillion cubic feet. Dollar figures at right 

show estimated recovery costs per million British thermal units. 

NPC, National Petroleum Council. 
840 THE FUTURE OF ENERGY GASES 

of Wyoming alone (see Law and Spencer, this volume). 

Although only a small fraction of this resource is now 

considered economically recoverable, new technology may 

someday permit increased recovery. The USGS also reports enormous volumes of gas hydrate off our shores (see 

Kvenvolden, this volume). This is gas captured in the lattice structure of water under certain conditions of temperature and pressure. At some later date, as with the diffuse 

Green River gas, these hydrates may become economically recoverable. The resource pyramid concept is a better reflection of the dynamic nature of the natural-gas 

resource base than is the finite volume model. 

HOW WE GET THERE FROM HEREPOLICY 

There is a continuing misconception that since the 

United States has only 9.5 years' worth of gas reserves, 

we are in danger of running out of gas and therefore 

should hesitate to make any long-term capital investments 

requiring the use of gas. This idea however, could not be 

farther from the truth. As stated in the 1992 National Petroleum Council report, "the gas resource base itself is not 

(and should not be viewed as) a limit to expanded gas 

usage" (National Petroleum Council, 1992). Nine and a 

half years ago we only had 9.5 years' worth of reserves. 

Today's just-in-time economics would preclude a cost-conscious, market-oriented, competitively driven exploration 

organization from placing in working inventory more gas 

than it can tum over before its reorder point. 

Studies indicate that with this Nation's current mix of 

reserves, from the high-porosity, high-permeability formations of the offshore, to the low-porosity, low-permeability 

rocks of the Rocky Mountains, we could sustain current 

needs for deliverability (the rate at which existing reserves 

can be produced from existing completions in existing 

wells) with a reserve-life index of only 7.5 years. In accordance with this concept, Canada has recently dropped 

its R/P-15 test, which required producers to demonstrate a 

15-year reserve, in favor of a more market-based procedure to obtain export licenses. Canadian gas is extremely 

price competitive during this inventory-reduction period. 

Thus it is the resource number, not the reserve number, 

that should be used in long-range planning for the supply 

of fossil fuels. The correct RIP (resource/production) ratio 

for the lower 48 States is at least 71 years, not 9.5 years, 

on the basis of current rates of consumption .. 

The transfer of technological advances into the field 

has enhanced deliverability from the lower 48 States' natural-gas resource base. Reduced drilling times, lower well 

costs, higher success ratios, better formation evaluation, 

and more effective completions have reduced the number 

of drilling rigs needed and the time required to replace 

deliverability. Advances range from exploration through 

exploitation to production. 

Improvements in well siting continue to increase success ratios, despite offsetting issues related to the maturing 

of domestic exploration. Building on the geophysical bright 

spot and ESP (extraction of seismic properties) techniques 

of the 1960's and 1970's, modem computer workstations 

are allowing newer computation-intensive seismic interpretations. For example, amplitude-versus-offset (AVO) and 

cross-well tomography allow direct detection with unprecedented precision of gas in undrilled prospects and bypassed 

compartments. By eliminating a significant percentage of 

avoidable dry holes, the industry is able to achieve record 

numbers of gas completions per rigs running. 

Once the wells have been drilled, new and improving methods of borehole evaluation are permitting more 

complete and efficient recoveries of natural gas. Fewer 

potentially productive zones are bypassed. Particularly 

significant methods have included advanced permeabilitymeasurement tools and through-casing evaluation devices. 

Advances in onshore horizontal drilling and guidance 

mechanisms show early promise of large returns in both 

shallow formations and those that have linearly oriented 

fractures. With horizontal drilling, many areas have already 

shown three-fold increases in productivity for only oneand-one-half-fold increases in cost. The progress made onshore in horizontal drilling also has tremendous potential 

for the shallow, low-pressure gas-bearing formations offshore (perhaps even the gas hydrates). Continuing development of slim-hole drilling techniques and evaluation tools 

will allow wells to be drilled with smaller diameter bits and 

casing strings. By reducing both drilling time and overall 

well cost, the industry can drill more wells per year per rig 

at less capital per well. Having drilled and evaluated wells, 

new completion techniques and fluids are continually yielding higher production rates per completion foot. Hydraulic 

fracturing techniques in particular have demonstrated continuous refinement over the years and are expected to continue to improve over the next two decades. Work on 

fracture-length extension, fracture orientation, and verticalfracture containment is being done by the industry and by 

the Gas Research Institute. The Gas Research Institute's 

plans for a Hydraulic Fracture Test Site and a Fracture Fluids Characterization Facility are still preliminary, but once 

implemented, are expected to reduce ·gas-well completion 

costs and enhance deliverability. 

Different geological provinces exhibit different deliverability characteristics. The characteristics of each region, 

however, are consistent over time. The basic unit of measurement of deliverability is thousand cubic feet per day 

(Mcf/d) per billion cubic feet (Bcf) of reserve. Young, uncompacted, and highly porous formations of Pleistocene 

age that are found in the Gulf of Mexico exhibit high deliverabilities-close to 1 million cubic feet per day 

(MMcf/d) per each Bcf of reserve. Older, consolidated, 
THE FUTURE OF METHANE AND HOW WE GET THERE 841 

and lower porosity rocks of Permian age in the Rocky 

Mountains deliver only about 250 Mcf/d per each Bcf of 

reserve. Coalbeds in the San Juan Basin demonstrate even 

lower deliverabilities. Each region has been found responsive to different technological approaches, so the industry 

has tailored its technology for each region. Significantly, 

an otherwise highly competitive industry is sharing its research results. The Gas Research Institute has an aggressive technology-transfer program in which all operators 

are allowed to participate. The free flow of information 

related to successful technology advances disseminates 

rapidly in the field and is adopted by major companies and 

independent producers alike. 

CONCLUSION 

To paraphrase the famous quote from Wallace Pratt 

( 1952), the future of methane is in our own hands. Not only 

must we roll up our sleeves and work to develop new technology, we must cast our ballots for elected representatives 

who will pass laws favoring domestic energy production. 

And we must publish our views of the energy situation. 

From time to time throughout history, pessimistic appraisals of our Nation's resource base have Jed our Government, and indeed the energy industry, to adopt what were 

later seen to be misguided policies, such as the Fuel Use 

Act of 1976, which prohibited the use of our "limited natural gas resources" (as they were perceived at the time) as a 

boiler fuel. Alternatively, the Natural Gas Policy Act of 

1978 provided incentives for the production of what at that 

time were seen to be high-cost, high-risk sources of natural 

gas. While the prohibition failed and was later repealed, the 

incentives worked, but were allowed to expire. The lack of 

a cogent and consistent energy policy has disrupted the 

energy industry for the major part of this century. 

In the final analysis then, the "Future of Energy 

Gases" is in our own hands-it is up to academic institutions, industry associations, and governmental agencies to 

study this abundant natural resource and make informed 

recommendations regarding its development and use. It is 

up to the government leadership to heed these recommendations, to provide incentives, and to allow access to this 

Nation's most environmentally benign fuel. And it is up to 

the industry to interact with all of the above to insure a 

future in which energy gases can meet their full potential. 

REFERENCES CITED 

Boserup, M., 1979, Are there really depletable resources?, in 

Bliss, C., ed., Economic growth and resources: New York, 

St. Martins Press. 

Hubbert, M. King, 1956, Nuclear energy and the fossil fuels: 

American Petroleum Institute, Drilling and Production Practices (1956), p. 7-25. 

Levorsen, A.I., 1967, Geology of petroleum (2d ed.): San Francisco, W.H. Freeman and Company, 924 p. 

National Petroleum Council, 1992, The potential for natural gas 

in the United States: National Petroleum Council, December 

1992, six volumes. 

Potential Gas Committee, 1966-1990, Potential supply of natural 

gas in the United States: Golden, Colo., Potential Gas Agency, Colorado School of Mines. 

Pratt, W.E., 1952, Toward a philosophy of oil finding: American 

Association of Petroleum Geologists Bulletin, v .. 36, no. 12, 

p. 2231-2236. 

U.S. Department of Energy, Energy Information Administration, 

1992, U.S. crude oil, natural gas, and natural gas liquids reserves, 1991 Annual Report: DOE/EIA 0216(91). 
What proportion of the energy mix will energy gases 

make up in the future? Reports in this section explore the 

issues and uncertainties involving pricing, technology, 

environment, and resource potential, all of which play a 

role in determining how energy will be supplied and used 

in the future. Aside from issues of fuel choice, future 

energy systems will incorporate more efficient methods 

of energy consumption, which will effectively provide 

society with a resource by limiting the amount of energy 

needed. 

As our energy mix continues to evolve, it is important 

that internal and external costs as well as long-term 

sustainability be incorporated into the design of future 

energy systems. With regard to the future use of natural 

gas, predictions of consumption rates cover a broad 

range; in fact, many forecasts predict rates of consumption that greatly exceed published resource estimates. 

This discrepancy has created a perception of a gap 

between the amount of gas that exists and the amount of 

gas that will be used. As geologists, economists, and 

engineers, we see this gap as both an opportunity and a 

need for further research. In the final analysis, the potential for natural gas will be determined in the marketplace 

and by the imagination and perspicacity of explorers. 

THE FUTURE 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

Sustainable Operation-Natural-Gas Contribution 

By Rex T. Ellington1 and Mark Meo1 

CONTENTS 

Abstract ......................................................................... 843 

Introduction ...... ..... .................. .. .. . .. ..................... .... ... ... 843 

Sustainable Development ....... : ..................................... 844 

Industrial Ecology as an Organizing 

Framework .......... ... .. .. ................. ....... .......... .......... 845 

Sustainable Energy Futures ................................... 845 

Outlook for Natural Gas ........................................ 846 

Elements of Systems Perspective .......................... 846 

Analysis of Integrated Energy Systems ................ 846 

Conclusions ................................................................... 847 

References Cited ........................................................... 847 

ABSTRACT 

The need to guide economic development in a sustainable manner is based on the growing belief that humanity's propensity to exceed environmental thresholds could 

severely hinder efforts to improve worldwide living conditions. In view of the rapid pace of population growth in 

industrializing nations and the globalization of many commercial markets, cumulative environmental damages have 

heightened the responsibility of industrialized nations to 

use science and technology to help other nations achieve 

desirable levels of economic prosperity and environmental 

quality. For all nations, the challenge of sustainable development will be to use natural resources in an economic 

and equitable manner that results in minimum environmental impact over time. 

1

University of Oklahoma, Norman, OK 73019. 

For these reasons, the expanded use of natural gas will 

continue to be prominent ·in the debate about policy alternatives for advancing sustainable development. As the 

cleanest burning fossil fuel, natural gas and its attendant 

supply and distribution infrastructure are characterized as 

important for many reasons including: reducing greenhouse gas emissions; generating minimal solid and liquid 

wastes during production, transportation, and consumption; serving as a transition fuel to a future with greater 

reliance on renewable energy sources; and for providing 

an industrial base for developing more environmentally 

conscious technologies. Other arguments for its expanded 

use have emphasized the opportunity to induce technological innovations and behavioral changes that are more compatible with sustainable development. The criteria by 

which society can design sustainable development strategies and determine whether environmental quality goals 

have been met will be key to the effective implementation 

of clean-fuel programs and expansion of natural-gas uses. 

This issue is timely, particularly with regard to how clean 

fuels can be nested within conceptual policy and planning 

frameworks that address sustainable industrial development more broadly. 

INTRODUCTION 

Because the interactions of material and energy flows 

within the total environment are implicit in discussions of 

sustainability, assessment of natural-gas applications should 

include the complete technical system. Recognition of this 

perspective is echoed by the recent adoption of the fuel 

cycle by the U.S. Department of Energy as an analytic 

framework for technical systems assessment (U.S. Department of Energy, 1992). Yet for purposes of assessing sustainability more generally, the complete life cycle of the 

natural-gas system should be addressed to provide vital 

843 
844 THE FUTURE OF ENERGY GASES 

information for making informed decisions regarding energy use, environmental quality and economic performance 

over time (Ellington and others, 1992; Ellington and Meo, 

1993). Herein, we build upon the systemwide, intertemporal perspective to examine the potential of natural-gas systems for fostering sustainability with several criteria that 

should prove helpful for making planning and management 

decisions. Such criteria should prove valuable for analysts 

who wish to quantify more completely the specific performance measures of natural-gas systems that may experience wider application in the future. 

SUSTAINABLE DEVELOPMENT 

Sustainable development, defined as development that 

meets the needs of the present without compromising the 

ability of future generations to meet their needs, is now an 

accepted international objective. The 47th Assembly of the 

United Nations has assumed the· task of implementing· 

Agenda 21, a key product of over 150 nations at the U.N. 

Conference on Environment and Development held in Rio 

de Janeiro in June of 1992. Agenda 21 is the first global 

acknowledgment that environmental quality and economic 

health are tightly linked. Agenda 21 espouses a more bar-

. monious combination of environment and economics to 

achieve sustainability (United Nations, 1992). 

Because the well-being of all peoples will depend directly on the continued health of the Earth's natural resources, Train (1992) suggested that the natural resources, 

economy, and way of life of the United States will all deteriorate if the nation should continue merely to react to 

environmental damages as they occur. With the expectation that, over the next five decades, the level of economic 

activity of the country will quadruple, and global population double, economically and environmentally disastrous 

results are presumed to ensue if practices, processes and 

methods of this century are not changed. Therefore, it appears that general agreement exists that the world has now 

moved beyond economic interdependence to ecological interdependence (MacNeill, 1989, 1991). Awareness of this 

issue in the United States is reflected by formation of a 

25-member President's Council on Sustainable Development to create new approaches for combining economic 

development with environmental protection. 

One of the key areas covered in Agenda 21 is energy 

(Section I, Chapter 7 and Section II, Chapter 9), which has 

a greater impact on the environment than almost any other 

resource or activity (United Nations, 1992). Fundamental 

changes must be made in the way the country produces and 

uses energy. While progressive energy companies and industries that further the cause of sustainable development 

will likely become more valuable and more highly regarded 

in the marketplace (Popoff, 1992), the reverse could also be 

true. For energy systems to achieve increased environmental compatibility in such a setting, a number of guides for 

examining development options in the planning and management process must be developed. These include a fairly 

complete conceptual framework that can facilitate productive institutional and technological interaction, key performance measures by which progress can be quantified, and 

decision rules that will enable complex technical and environmental conditions to be accommodated. 

To better appreciate why the need for an analysis 

framework arises, several characteristics of the sustainable 

development concept need to be clarified. Although consensus has been reached about the general goal of sustainability, little agreement exists about the optimal paths by 

which society can pursue it (Costanza, 1991). Solow 

( 1992) suggested that sustainable development exists as 

long as society expressly concerns itself with its total capital, taking into account substitution possibilities between -

"natural capital" (extractive resources and the natural environment) and other forms of capital. In an intergenerational sense, Solow ( 1992) argued that flawed indicators such 

as the Gross National Product less the depreciation on 

physical and natural capital is a measure of sustainable income for future years. He noted that the level of sustainable income could rise from one generation to another if 

the earlier generation protected its environmental assets, 

consumed less nonrenewable resources, and invested aggressively in new productive capacity. This prescription 

would include gains in energy efficiency and advances in 

clean fuel use and environmentally conscious technology. 

With the current absence of operational definitions and 

key data to guide public policy more effectively, definitions of sustainability are largely contextual. Accordingly, 

these definitions are different for individual companies, 

communities of companies, or communities of people and 

metropolitan areas. Furthermore, the environmental and 

energy policy impediments that constrain public sector 

leadership suggest that individual businesses may be able 

to move far more rapidly in meeting their most immediate 

challenges of sustainable development. National policy for 

the near future will likely follow from the influence of 

thousands of individual business decisions undertaken in 

response to changing markets and rising public demand 

for environmental quality. 

In such a decentralized decisionmaking context, the 

detailed definition of sustainable development for individual companies or industries will depend on how corporate 

leadership weighs the time value of Solow's total capital 

(including natural capital), short-term economics, ultimate 

environmental impact, and approval of customers (actual 

customers, stockholders, and general public). One such 

trend that bodes well for these concerns is dematerialization, which seeks continuous reduction in material and energy use to achieve given results (Ausubel and others, 

1989). Each of these points underscores the notion that, to 

attain sustainability, everything affects everything else. 
SUSTAINABLE OPERATION-NATURAL-GAS CONTRIBUTION 845 

INDUSTRIAL ECOLOGY AS AN 

ORGANIZING FRAMEWORK 

Industrial ecology is rapidly gaining recognition because it provides a framework within which ideas from 

different communities of knowledge and human experience 

are combined for action on the problems associated with 

sustainability. Industrial ecology has been defined as the 

totality or patterns of relations between various industrial 

activities, their products, and the environment (Patel, 1992), 

and as a new approach to the industrial design of products 

and processes and the implementation of sustainable manufacturing strategies (Jelinski and others, 1992). It has been 

called the best candidate to date for the needed conceptual 

framework and involves designing industrial infrastructures 

as if they were a series of interlocking manmade ecosystems 

interfacing with the natural global ecosystem (Ayers, 1989; 

Tibbs, 1991 ). This perspective represents a marked departure from the mindset of "conquering nature" to cooperating 

with it. In broad terms, industrial ecology recognizes that as 

society embraces a more industrialized world, its industrial 

systems will continue to grow larger with outputs reaching 

such a magnitude that, when compared to the assimilative 

capacity of the natural environment, the systems will not be 

sustainable as they exist. By linking outputs of one system 

as inputs to another, industrial ecology design seeks to reduce society's waste burden on the environment and extend 

the useful life of the combined system. 

It should be noted, however, that owing to changes in 

energy and material flows among and between elements of 

the natural and built environment, both the industrial and 

natural systems will be in an unsteady state at all times. 

Planners who choose to use equilibrium-oriented frameworks must recognize this. 

SUSTAINABLE ENERGY FUTURES 

Strategy development for sustainable energy production and utilization demands a long-term future-oriented 

focus. Although recent fuel-use trends reflect movement 

toward fuels with lower carbon to hydrogen ratios, a focus 

on sustainability may well recast the role of depletable hydrocarbon resources (Ausubel and others, 1989; Freedman, 

1991; Johansson and others, 1993; Williams, 1992). Some 

fuels may be too "dirty" to permit use for large-scale energy production. Others fuels may be too precious to future 

generations to advocate them for general use. With a sustainable development planning goal to move away from 

depletable resources over the long term, the use of fossil 

fuels is coming under increased s·crutiny with regard to 

their environmental impact. Long-recognized attributes of 

natural gas are attracting renewed attention. Accordingly, 

many experts advocate its use during the transition period, 

however long. 

The synfuels experience of the 1970's, which evolved 

around the single public policy goal of energy independence, provides a rich history of difficulties that should 

not be repeated, particularly if sustainability objectives are 

sought. In contrast to the concepts embraced by industrial 

ecology, synthetic fuels were developed under the auspices 

of a well-meaning Government, which failed to acknowledge a variety of issues central to meeting any sustainability objective. The synfuels initiative was fundamentally 

flawed in that it was defined as a single-issue program 

when the realities of modem industrial activities with their 

interrelated problems suggested otherwise. The program 

started as a national emergency effort to provide a shortterm answer to the potential interruption of foreign-oil 

supply. It was basically insensitive to external environmental and market conditions, which rendered it irrelevant 

within just a few years. Technologies, developed decades 

earlier, were improved and accommodated to prevailing 

environmental regulations. Massive, complex plant installations were planned with the objective of using economies of scale to compete with projected escalated prices of 

foreign oil. Philosophically, the effort was inflexible and 

maladaptive. Consequently, it was far removed from industrial ecology. Any effort to revive technical processes 

from this era must be examined with care and an entirely 

new set of design criteria adopted before they are proposed for sustainable development. 

Fundamental limits to the use of different fossil fuels 

may become apparent in the amount of gaseous, liquid, 

and solid wastes that natural processes can absorb. Therefore, humanity should plan for the time when the sustainability of industry, agriculture, population centers, and 

nations must ultimately depend upon energy sources that 

are truly renewable. Society will have to depend in one 

way or another on the Sun, or on reactions deep within the 

Earth (Johansson and others, 1993; Tester and others, 

1991 ). Renewable energy systems include primary or di- · 

rect use of solar inflow such as solar-thermal and photovoltaic systems, and those depending on secondary or 

delayed use such as hydropower, wind energy, ocean energy, biomass, and anaerobic digestion of organic molecules. 

Although the characteristics of individual processes are 

thoroughly documented, analyses often examine them as 

unit processes rather than in the context of complete systems with mandatory infrastructure and external energy or 

material subsidies. Only when such detailed analyses are 

executed so generic systems containing specific processes 

can be rank-ordered will the true potential of each be evident (DeLuchi, 1991; Ellington and others, 1993). 

The role natural gas can play in achieving a sustainable future has been examined by many energy specialists. 

The context of many of these analyses is resource availability (potential, economically proven and addition rate), 

cleanliness, safety, and ease of application (for example, 

Lee, 1989; McCormick, 1990; Sperling, 1991). Depending 
846 THE FUTURE OF ENERGY GASES 

on specific societal goals, natural-gas use is influenced by 

market penetration rates, natural-gas resource additions 

and gas-application advantages (Tabors and Monroe, 

1991 ). The context of such. analyses merits reconsideration 

in light of the requirements of sustainability and industrial 

ecology to elucidate the merits of natural gas. 

OUTLOOK FOR NATURAL GAS 

Within the industrial ecology framework, policy issues 

exist that must be addressed before the concept of harmonizing with the environment can be applied widely. These 

include such issues as the selection of areas for research 

expenditure, ways to combine technologies, and, especially, the need to articulate the proper criteria for making 

decisions. For example, an assessment of transportationresearch needs for overall policy development would reevaluate gross system questions such as rail versus trucks, 

the potential for telecommunications to reduce travel 

needs, improving efficiency and (or) emissions of individual services, and improving energy efficiency of systems 

supplying energy to transportation units (Weiss and Heywood, 1991 ). 

Whereas such studies are important for guiding public 

sector energy policy, we believe there is a comparable 

need to provide, for the private sector, logical detail to the 

framework for merging the technology and engineering aspects with the managerial aspects of strategy and policy 

development. This integration is necessary to facilitate the 

large number of individual business decisions that will be 

made in efforts to optimize the factors related to sustainable operations and corporate life (Ellington and others, 

1992; Ellington and Meo, 1993). 

ELEMENTS OF SYSTEMS PERSPECTIVE 

We propose a method of analysis, which addresses industrial ecology objectives, that starts with careful definition of all of the physical and corporate components 

pertinent to the problem. This framework requires first the 

proper systems perspective to identify all the technical infrastructure related to a given primary process or operation 

of interest and all the energy and material imports from 

the outside. 

Determination of system boundaries is a matter of perspective, that is, the identification of related entities to 

ensure that important components are not omitted from 

analysis. For example, definition of the greenhouse gas 

emissions resulting from selection of a given process or 

operation requires the identification of all infrastructure elements on which a primary process depends. The identification must go backward to raw resources and forward to 

the final treatment and disposal of wastes, and it must encompass all consumables and energy subsidies related to 

every element (Ellington and Meo, 1990-91). The primary 

process/operation could not function should this infrastructure not exist. Elements that are separated from the primary process in distance or time are still necessary for a 

complete analysis. This system definition must ensure that 

it also includes all solid and liquid wastes and their effects. In an environmental sense, the boundaries should 

circumscribe the entire impact of the system on the environment. In an economic sense, the system boundaries 

should reflect the entire cost the consumer or taxpayer 

pays, which determines whether a product, service, industry, or economy is competitive (Drucker, 1992). If the system is inherently uneconomic, a process of interest nested 

within the system should have a poor outlook. 

The time interval to be used in analyzing the effects of 

a system and its products has a variety of interpretations. 

Our position is that it should be of sufficient length to include all of the significant intertemporal effects of the system (for example, emissions, energy and economic 

elements). In many instances, it will begin with system 

construction and raw material recovery, and extend 

through all operations, salvage, final waste disposal, and, 

perhaps, long-term storage, of all products. Other lifecycle assessments include different sets of factors (Keoleian and Menerey, 1993). Yet, as impacts are regarded more 

seriously, more inclusive life cycles must be used. The life 

of the physical plant may be some 30 years. The life of 

environmental impacts from wastes may range from a few 

years beyond plant life for liquids, a few decades for solids, to a century or two for greenhouse gases, to a thousand years for nuclear wastes. These elements must all be 

considered in examining systems to assess the degree to 

which they admit to sustainability. 

ANALYSIS OF INTEGRATED ENERGY SYSTEMS 

As developed in the 1980's, the Integrated Energy 

Systems Program had the objective of evaluating innovative combinations of existing and emerging technical processes to provide new sources of clean energy and 

chemicals without incurring additional environmental controls. This effort involved an international consortium including the University of Oklahoma, Massachusetts 

Institute of Technology Energy Lab, and groups from Canada, Japan, Sweden, Taiwan, and West Germany (Ball, 

1986; Lee and others, 1990). The concept appeared deceptively similar to industrial ecology. However, the total systems perspective, life cycle, energy usage, and other costs 

per unit output inherent in sustainability objectives were 

absent. These systems tended to be very complex ( occasionally involving full nuclear heat plants), very costly, 

and had low energy efficiency like those in the synfuels 

era. 
SUSTAINABLE OPERATION-NATURAL-GAS CONTRIBUTION 847 

To develop concepts that were more compatible with 

the industrial ecology approach, we conducted a number of 

studies of natural-gas systems. Primary interest was afforded studies of energy efficiency, overall economic performance, and systemwide emissions of greenhouse gases. 

With a net energy analysis of a natural-gas well to gas-fired 

boiler study (Melcher and others, 1976) as a starting point, 

substitution of a natural gas-fired combined-cycle (NGCC) 

unit for power generation was examined because efficiencies of about 45 percent were being obtained with grounddesigned gas turbine units. With all other losses in the well 

through NGCC unit taken into account, a system energy 

efficiency of about 37 percent seemed practical (Ellington 

and others, 1989). Similar results were reported by Lee 

(1989). For reference, coal-fired boilers with stack-gas 

scrubbing had efficiencies of about 30 percent for the unit 

alone. Consideration of the rest of the coal system would 

certainly decrease this energy efficiency value. Other comparisons showed that the coal system would cost more and 

produce much greater amounts of greenhouse gases and 

solid as well as liquid wastes. This is the kind of comparison that should be carried out in detail quantitatively for 

systems proposed as alternatives for natural-gas systems. 

Further studies of NGCC systems involved analysis of 

the dual modification of C02 recovery from system tail gas 

and use of the C02 for enhanced oil recovery. This combination would seem to enhance sustainability by sequestering C02 equal to a fraction of the pore volume of the 

reservoir at reservoir conditions for geologic time, after 

breakthrough gas recycling and (or) export to other projects 

is ended. The actual cost of sequestering would be the total 

cost of C02 recovery and compression minus the cost of 

competitive natural C02 from natural reservoirs. Furthermore, replacement of natural-reservoir C02 by power-system C02 could reduce net greenhouse warming forcing (the 

quantitative measure of atmospheric warming tendency) 

that results from separate power generation and enhanced 

oil recovery. The NGCC case was also used in an examination of the earlier conventional wisdom that large plants 

should be constructed all at once. The NGCC system is 

ideal for staged construction because of short lead times on 

the types of equipment used as well as short construction 

times (Boyd." 1988). Then, subsequent units can be installed 

as load building requires, using project financing, that is, 

revenue from the e(jilier unit(s). Although time to final payout changes little, capital demands on the financing unit are 

decreased by approximately one-half. One or more combinations of the above configurations might well be the 

benchmark against which others are measured on the way 

to true sustainability. 

Under a full set of sustainability oriented industrial 

ecology requirements, the basic characteristics of alternatives to current energy systems or natural-gas systems 

should be scrutinized carefully. For example, we analyzed 

the total woody biomass to methanol system as an alternate 

transportation fuel to the gasoline system. The results suggest that intersectoral transfer of pollution and increase of 

greenhouse warming forcing would result (Ellington and 

others, 1993 ). Any system that utilizes gasification of a 

heavier fossil fuel to obtain a synthesis gas rejects a significant portion of the energy in the raw resource as heat in the 

gasification and rejects a corresponding quantity of C02. 

Thus, for a given quantity of useful energy at the output of 

the system, total wastes and total costs are likely to be 

greater and energy use efficiency is likely to be substantially lower. Gasification of hydrocarbons to produce synthesis 

gas or hydrogen for fuel-cell use would provide substantial 

penalty against the apparent attributes of fuel-cell power 

generation. Gasification as an integral process to development of a "hydrogen economy" would carry the same burden. Even hydrogen made by use of photovoltaic _power is 

at the end of a complex, energy-consuming system characterized by significant investments, energy and chemicals 

consumption, and frequent replacements for sound operating lives. 

CONCLUSIONS 

Use of a total physical system perspective and a generalized life-cycle analysis to evaluate energy gas processes 

can be used to guide strategy directed toward long-term 

sustainability. The application of the systems perspective 

can be used to determine whether seemingly clean, single 

processes may exist in systems that do not meet sustainability objectives. With systematic application of our method, 

natural-gas systems can provide significant energy and environmental advantages as economic, energy-use, efficiency, and environmental impact considerations of sustainable 

development become more important to society. 

REFERENCES CITED 

Ausubel, J.H., Frosch, R.A., and Herman, R., 1989, Technology 

and environment-An overview: Washington, D.C., National 

Academy of Engineering, p. 1-20. 

Ayers, R.U., 1989, Industrial metabolism, in Ausubel, J.H., and 

Sladovich, H.E., eds., Technology and Environment: Washington, D.C., National Academy Press. 

Ball, B.C., 1986, Integrated energy systems meeting summary: 

Cambridge, Mass., Massachusetts Institute of Technology. 

Boyd, J.A., 1988, Analysis of the staged construction of an integrated gasification combined cycle plant with methanol synthesis and C02 recovery: Norman, Okla., University of 

Oklahoma, M.S. thesis. 

Costanza, R., ed., 1991, Ecological economics: The science and 

management of sustainability: New York, Columbia University Press. 

DeLuchi, M.A., 1991, Emissions of greenhouse gases from the 

use of transportation fuels and electricity: Argonne, Ill., 
848 THE FUTURE OF ENERGY GASES 

Center for Transportation Research, Argonne National Laboratory, (AN/ESDMffM-22). 

Drucker, P.F., 1992, The new society of organizations: Harvard 

Business Review, September-October. 

Ellington, R.T., Boyd, J.A., and Floyd, R.A., 1989, New opportunities for gas liquids in the electric power industry and other 

energy production, Proceedings of Gas Processors Association, San Antonio, Texas, 68th Annual Convention. 

Ellington, R.T., Meo, M., and Mannan, M., 1991, Energy efficiency of a natural gas-fired combined cycle power plant, in 

Hydrogen energy and power generation, Proceedings of the 

International Congress on Energy and Environment, 9th: 

New York, Nova Science Publishers. 

Ellington, R.T., and Meo, M., 1990-91, Calculating the net 

greenhouse warming effect of renewable energy resourcesMethanol from biomass: Journal of Environmental Systems, 

v. 20, no. 4, p. 287-301. 

Ellington, R.T., Meo, M., and Baugh, D., 1992, The total greenhouse warming potential of technical systems-Analysis for 

decision making: Journal of the Air and Waste Management 

Association, v. 42, no. 4, p. 422-428. 

EIIington, R.T., and Meo, M., 1993, Total environmental quality-Integrating engineering and management for sustainable 

development: Address to American Institute of Chemical 

Engineering, 1993 Summer National Meeting, Seattle, 

Wash., August 15-18. 

Ellington, R.T., Meo, M., and El-Sayed, D.A., 1993, The net 

greenhouse warming forcing of methanol produced from 

biomass, in Biomass and Bioenergy: New York, Pergamon 

Press. 

Freedman, SJ., 1991, The role of natural gas in electric power 

generation, 1990 to 2020, in Tester, J.W., Wood, D.O., and 

Ferrari, N.A., eds., Energy and the Environment in the 21st 

Century: Cambridge, Mass, MIT Press. 

Jelinski, L.W., Graedel, T.E., Laudise, R.A., McCall, D.W., and 

Patel, C.K.N., 1992, Proceedings of the National Academy 

of Science, v. 89, p. 793-797, February. 

Johansson, T.B., Kelly, H., Reddy, A.K., and Williams, R.H., 

1993, Renewable fuels and electricity for a growing world 

economy-Defining and achieving the potential, in Johansson, T.B., Kelly, H., Reddy, A.K., and Williams, R.H., eds., 

Renewable Energy-Sources for Fuels and Electricity: 

Washington, D.C., Island Press. 

Keoleian, G.A., and Menerey, D., 1993, Life cycle design guidance manual-Environmental requirements and the product 

system, EPA600/R-92/226: Washington, D.C., EPA Office of 

Research and Development, January. 

Lee, T.H., 1989, Advanced fossil fuel systems and beyond, in 

Ausubel, J.H., and Sladovich, H.E., eds., Technology and 

Environment: Washington, D.C., National Academy Press. 

Lee, T.H., Ball, B.C., and Tabors, R.D., 1990, Energy aftermath-How we can learn from the blunders of the past to 

create a hopeful energy future: Boston, Mass., Harvard Business School Press. 

· McCormick, W.T., Jr., 1990, The uncertain future role of natural 

gas, in Energy-Production, consumption, and consequences: Washington, D.C., National Academy Press, p. 165-172. 

MacNeill, J., 1989, Strategies for sustainable development: Scientific American, v. 261, no. 3, p. 155-165. 

MacNeill, J., 1991, Sustainable development and the earth summit: Journal of the Air and Waste Management Association, 

v. 41, no. 12, p. 1554-58 and 1672-74. 

Melcher, A.V., Maddox, K., Prien, D., Nevens, T., Yesavage, V., 

Dickson, P., Fuller, J., Loehr, W., Baldwin, R., and Bain, R., 

1976, Net energy analysis-An energy balance study of fossil fuel resources: Golden, Colo., Colorado Energy Research 

Institute. 

Patel, C.K.N., 1992, Industrial Ecology, Proceedings of the National Academy of Science, v. 89, p. 798-799, February. 

Popoff, F., 1992, September-October, Companies change course, 

progressive companies will merge economics and environment: Washington, D.C., Environmental Protection Agency 

Journal, p. 26-28. 

Solow, R.M., 1992, An almost practical step toward sustainability: Washington, D.C., Resources for the Future. 

Sperling, D., 1991, An incentive-based transition to alternative 

transportation fuels, in Tester, J.W., Wood, D.O., and Ferrari, 

N.A., eds., Energy and the Environment in the 21st Century: 

Cambridge, Mass., MIT Press, p. 2151-264. 

Tabors, R.D., and Monroe, B.L. 1991, Transitional strategies for 

emission reduction in electric power generation, in Tester, 

J.W., Wood, D.O., and Ferrari, N.A., eds., Energy and the 

Environment in the 21st Century: Cambridge, Mass., MIT 

Press. 

Tester, J.W., Wood, D.O., and Ferrari, N.A., eds., 1991, Energy 

and the environment in the 21st Century: Cambridge, Mass., 

MIT Press. 

Tibbs, H., 1991, Industrial ecology-An environmental agenda 

for industry: Cambridge, Mass., Arthur D. Little, Inc. 

Train, R.E., 1992, A Call for Sustainabi1ity, Environmental Protection Agency Journal, v. 18, no. 4, p. 7-13. 

United Nations, 1992, Earth Summit-Press Summary of Agenda 

21, Final Text, United Nations Conference on Environment 

and Development: New York, United Nations. 

U.S. Department of Energy, 1992, National· energy strategy: 

Washington D.C., Government Printing Office. 

Weiss, M.A., and Heywood, J.B., 1991, Energy and the environment-A framework for evaluating research needs in the 

transportation sector, in Tester, J.W., Wood, D.O., and Ferrari, N.A., eds., Energy and the Environment in the 21st Century: Cambridge, Mass., MIT Press. 

Williams, R.H, 1992, Powering the future-Efficient use and renewable supplies are key: Environmental Protection Agency 

Journal, v. 18, no. 4., p. ·15-19. 
THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

The New Downstream: Increased End-Use Efficiency and 

Renewable Forms of Energy as Competitive Energy Resources 

By Evan Mills 1 

CONTENTS 

Abstract ......................................................................... 849 

The Context .................................................................. 850 

The New Downstream: A Return to Least-Cost 

Energy Services .. ..... ... .... ...... .... .... ... ... . .. .. ... ...... ....... .... . 851 

Trends in End-Use Energy Efficiency ................... 852 

Powerful Analogies: Energy Efficiency as a 

Demand-Side Energy Resource ............................. 855 

The Energy-Environment Connection ................... 856 

Identifying and Recovering Demand-Side 

Resources .. . . .. .... . . .. .... . . .... . .. ... .. . ... .. . . ..... ... . . . .... .. . .... . 857 

Making Markets for Energy Services .......................... 859 

Perfect Markets .... ....... .. .. . ....... ....... ... . .. ... .. .. .. . .. . . . ... 859 

Barriers to Least-Cost Energy ............................... 859 

Policy Solutions for Improving Energy 

Markets .................................................................. · 859 

Implications for Energy Suppliers ............................... 860 

Changing Roles for Modem Utilities .................... 861 

Electricity Production: One-Quarter of the 

World's Gas Use .................................................... 862 

Renewable Energy ....... ... .. .... . ..... . . ... ........ .. ........ .... 863 

Issues for Developing Countries and 

Economies in Transition .. .. ... . ...... .. .. .. ... .. ....... .... .. .... . ... . 864 

The Setting ... .. ........ .. ... . ... .. ... .. .... .. .... ... . .... .. ..... ... . ... 864 

Natural Gas in Developing Countries ................... 865 

Toward a New Synthesis: Integrated Resource 

Planning . ... ......... ........... ............. ... .. . ... ..... .... ... .. . ... ... .. ... 865 

Acknowledgments ........................................................ 866 

References Cited ........................................................... 866 

1

Center for Building Science, Lawrence Berkeley Laboratory, I Cyclotron.Rd. MS 90-3058, Berkeley, CA 94720. 

ABSTRACT 

The upstream. (supply) extractive energy industries are 

being taken unawares by sweeping changes in the downstream (demand) realm beyond the flame tip. The future of 

energy gases (natural gas, hydrogen, gasified biomass, and 

so on) is inexorably linked to final energy demand, which, 

in tum, depends on trends in end-use energy efficiency and 

fuel substitution toward or away from gas. From economic 

and technical standpoints, increased energy efficiency is directly analogous to increased energy supply. In the years 

since the energy crises of the 1970's, increased energy efficiency has been the largest and least expensive source of 

new energy services and has achieved more substantial reductions in energy-related pollution than offered by end-ofthe-pipe strategies. A new generation of government and 

utility policies aimed at overcoming market failures-coupled with ongoing technological developments-promises 

continued dramatic expansion of the energy-efficiency 

marketplace. Another factor influencing the future of energy gases is increasing "midstream" competition on the supply side, including improved thermal efficiencies of 

electric power production and increased opportunities for 

substitution in the direct use of fuels. Renewable forms of 

energy (some of which are energy gases) are emerging as 

potentially important contributors to future electricity and 

fuel supply, and as formidable competitors with natural gas 

and other fossil fuels. The current direction of energy policy suggests a future energy system increasingly based 

upon a balanced mixture of investment in end-use efficiency, in renewable supply technologies, and in natural gas. 

Such a new system is usefully characterized by the unifying technical, economic, and policy-making paradigm 

known as integrated resource planning. 

849 
850 THE FUTURE OF ENERGY GASES 

THE CONTEXT 

Although one of the darkest moments in the history of 

gas, the invention of the electric lighting system in 1880 

marked a watershed in the evolution of energy planning, 

economics, and entrepreneurship. The unification of efficient end-use equipment and new technologies for energy 

supply was the cornerstone of Thomas Edison's lighting 

revolution. 

Energy resources have traditionally been thought of as 

existing in the upstream (or supply) region of the energy 

system. Certainly, advances in supply technologies and 

geological methods are revealing new energy resources, as 

exemplified by the case of natural gas (Burnett and Ban, 

1989). However, the new paradigm foreshadowed by Edison's ideas reveals that the largest and least expensive energy resources are located far downstream from the point 

of production; in fact they are found not at the wellhead 

,, OJ ( c.' , .\ · 

but rather in the conversion of primary energy to electricity and-more importantly-in improved energy efficiency 

at and beyond the flame tip. 

The conceptual foundation of Edison's breakthrough 

was the goal of providing energy services at least cost. His 

competition was gas lighting, and his solution was an integrated system of electricity production, transmission, and 

conversion to a useful service: illumination. As evidenced 

by the presence of "bulbs" on one of Edison's ledger 

sheets (fig. 1), the economics of end-use technologies 

were an integral part of his utility's cost (and profit) structure. A century later, this service-oriented approach is 

characterized by a paradigm known as integrated resource 

planning. This paradigm's dimensions are technical, economic, and environmental, and the prospective implications for energy gases are profound. 

Not coincidentally, the return to least-cost energy services comes during an era in which more use of energy no 

c; v; TilriJ l u jtt, ·v ({l._ • ~ J /; ~I. VI> " )/: ,;•1· 

(\..".(- ,t. ~ /t r.J.,. /r-(.._ 1:. If' I-t (1 :. • .._;;; 

07u.. <:) ./., (p Or.h,dt!..... 11- Att-

.!., ~i/ ,- /) "~ 

a/ .r J/1'.~- tP) . I I 

J tr:rru-v i L s ~ J.. - ; 2 ,) - (.j XtJ 1 f/ a {: ..ffi fN-V/.1 ... 

I a, u t_A- , 

8 

Figure 1. Thomas Edison's lighting revolution combined efficient end-use equipment with new technologies for energy supply. A, A 

handwritten electricity investment profile from Edison's notebooks (from "Edison's Electric Light," by Robert Friedel and Paul Israel 

with Bernard S. Finn. Copyright I 986 by Rutgers, The State University). Note "Bulbs" on sixth line of list. B, An illustration of 

Edison's carbon arc lamp in early 1880, as pictured in Scientific American (Jan. 10, 1880, p. 19). 
INCREASED EFFICIENCY AND RENEWABLE FORMS OF ENERGY AS COMPETITIVE ENERGY RESOURCES 851 

longer leads unambiguously to a commensurate increase in 

well-being (Holdren, 1992). On the contrary, the beneficial 

services provided by energy must be weighed in the context of the many modem worries exacerbated by energy 

use: urban smog, oil spills, damming of wild rivers, wars 

over energy resources, deforestation, strip mining, nuclear 

accidents, nuclear weapons proliferation, heavy-metal pollution, acid rain, global warming, and the high economic 

cost of new energy supply systems, especially in the developing world. 

The extent to which changes in the energy system are 

realized depends on the policy effort applied towards 

achieving the goal. There are various barriers that impede 

progress as well as innovative policy mechanisms that can 

be used to overcome those barriers. 

In this chapter, the opportunities and competitive realities facing world gas markets are examined in light of the 

new paradigm, integrated resource planning. Central to the 

discussion is the comparative economics of supply-side 

versus demand-side investments and their corresponding 

environmental impacts. Specific technical analogies are 

drawn to relate supply-side and demand-side resources, 

and examples are given of how to systematically classify 

and recover these resources. The discussion continues with 

the problem of making markets for demand-side resources, 

presenting both the barriers arising from imperfections in 

the existing marketplace and the corresponding policy remedies. The role of electric and gas utilities (both as users 

and sellers of gas) is critical, and the structure and character of these companies-and the regulatory environment in 

which they operate-is changing rapidly. Lastly, the future 

of gas is tightly linked to new trends on the supply side in 

which renewable energy for fuels and electricity is emerging as an important competitive force. Some of these 

trends point toward a potential near-term conversion from 

oil and coal to natural gas and biomass-based energy gases 

in the power sector. The preceding elements are united by 

the emerging framework of integrated resource planning, 

already in advanced stages of application in North America 

and quickly spreading around the world. 

PRIMARY 

ENERGY 

DELIVERED 

ENERGY 

THE NEW DOWNSTREAM: A RETURN 

TO LEAST-COST ENERGY SERVICES 

The concept of energy efficiency as a demand-side energy resource rests on the underlying idea that the demand 

for energy commodities (for example, coal, oil, or gas) is 

merely derived from the demand for energy services (for 

example, warmth, illumination, transport of people or 

goods, shaft power in an industrial process, or information 

management) (fig. 2). Where improvements in energy efficiency (in heating systems, lighting, cars, motors, or computers) provide the same end-use service at a lower level 

of energy consumption and cost, they can be considered as 

much a part of the future resource mix as investments in 

new energy supply. 

The convergence of many factors has accelerated the 

application of demand-side management and the diversification of supply-side options. Perhaps above all else, environmental concerns, both regional (as in the case of acid 

rain) and global (as in the case of climate change) have 

become a formal part of the rationale for making energy 

choices. With the exception of the United States, all major 

western industrialized nations have now articulated goals 

for carbon-dioxide stabilization or reduction. In addition, 

increasing regulatory scrutiny of the prudence of supplyside investments made by energy industries has formalized 

the process of comparing prospective supply-side and demand-side investments (National Association of Regulatory Utility Commissioners, 1988). Regulators are now also 

beginning to include the cost ("adders") of various. environmental effects in the energy price, thus further favoring 

energy efficiency (Wiel, 1991 ). 

In tandem with changes in energy policy, structural and 

economic changes have also tended to lower energy intensities (measured as energy use per unit of economic output). 

Technological trends such as miniaturization and reduced 

materials use give rise to what is sometimes termed "natural" efficiency improvements. A case in point is the laptop 

computer: it uses about 5 percent as much energy as the 

desktop computer it replaces, and is constructed with only a 

USEFUL 

ENERGY 

SERVICE 

RENDERED 

w--?~ -7.~~~---7 __ 

OIL REFINERY AND MOTOR ~ ---7 -----?~ MOTIVE DISTANCE 

CRUDE OIL DISTRIBUTION SYSTEM GASOLINE AUTOMOBILE 

I II 

•• • 

II II I 

•• 

COAL 

----?~--7~---7 CJ 

POWER STATION ELECTRICITY 

AND GRID LAMP 

POWER TRAVELED 

I; 

~f: ... RADIANT 

·v . ·(;

:~~~ 

> ~ ~ fiii~l~!':J~(;!q;(~ ILLUMINATION 

Figure 2. Energy supply versus energy services. Energy is transformed through a chain of events. Primary energy exists in a crude 

form, say, a fossil fuel, that is extracted from a sedimentary repository. After undergoing transformation, it becomes delivered energy, 

which is made available to the consumer, who then converts it into useful forms and then finally into energy services, which are the 

desired end. From Davis ( 1990). 
852 THE FUTURE OF ENERGY GASES 

fraction (embodied energy) of the metal and plastic. The 

increasing shift away from goods and toward services in 

industrial economies is also a significant structural factor. 

Such changes are responsible for approximately one-third 

of the total decrease in aggregate national energy intensities 

observed in many industrialized countries in recent decades 

(Schipper and others, 1992). 

In addition to the downstream trends in end-use energy efficiency, industry and government have been developing "midstream" renewable energy supply systems that are 

consistent with much of the policy orientation that now 

favors efficiency over traditional fossil-based supply systems. The emergence of these new midstream resources is 

driven by many of the same economic, technical, and environmental factors that have contributed to increased interest in improved end-use efficiency. Legislation such as 

the Public Utilities Regulatory Policies Act of 1978 

(PURPA) has created markets in which utilities must buy 

competitively priced power from small non-utility suppliers. In California, for example, this law has given rise to 

$2 billion total investment in the wind-energy industry 

(Grubb and Meyer, 1993). The total cost of electricity 

from new wind systems in California is approximately 7 

cents per kilowatthour-competitive with the cost of electricity produced with fossil fuels. 

TRENDS IN END-USE ENERGY EFFICIENCY 

Prior to the energy crises of the 1970's, conventional 

wisdom held that energy use would increase as fast as economic growth (measured as gross national product, or 

GNP), which, in turn, depended on an ever-expanding 

supply of energy. In other words, the intensity of energy 

use per dollar of real GNP was considered unalterable. 

The heavy solid lines in figures 3A and 3B represent the 

trends in United States' consumption (fig. 3A) and the Organization for Economic Cooperation and Development 

(OECD) countries' consumption (fig. 3B) of primary energy based on actual consumption from 1965 to 1985. (The 

OECD includes all of North America, Western Europe, 

Japan, Australia, and New Zealand.) The lighter solid lines 

on figures 3A and 3B represent energy use predicted as a 

linear function of real GNP, based on energy use per dollar 

of GNP (that is, energy intensity) in 1973. We see that 

energy use and GNP tracked each other well when e.xtrapolated back to 1965, but that the two trends diverged 

sharply after 1973. In the United States, real GNP had 

risen by more than 30 percent by 1985, while actual energy use had leveled off. The OECD countries have 

achieved an impressive reduction of energy intensity and 

are together saving about $400 billion/year in avoided energy costs compared to trends prior to 1973. 

Despite the steady growth in GNP, use of oil and gas 

has declined. In fact, as figure 3A shows, U.S. oil and gas 

consumption has dropped by more than the total U.S. oil 

and gas production (also declining). In comparison to oil 

and gas consumption as forecasted by the 1973 ratio of 

fuel use to GNP, actual consumption has been much lower, 

leading to oil and gas savings in the U.S. now equal to 

one-half of OPEC's (Organization of Petroleum Exporting 

Countries) estimated 1986 total production capacity of 29 

million barrels of oil per day. Savings in the OECD as a 

whole are equivalent to five-sixths of OPEC's capacity. 

These large-scale trends stem from a multitude of specific changes at the energy end-use level. For example, 

during the efficiency era of the 1970's and 1980's, fuel 

required for heating U.S. buildings decreased by the equivalent of 1.2 million barrels of oil per day-an amount 

equal to two-thirds the daily output of the Alaskan pipeline-despite the fact that the number of households grew 

by 30 percent and commercial floor space increased by 40 

percent. Efficiency improvements in insulation levels, windows, and heating equipment have reduced space-heating 

intensity by about 50 percent compared to 1973 levels in 

new homes and commercial buildings (U.S. Department of 

Energy, 1989). New state-of-the-art office buildings and 

superinsulated homes, such as those constructed by Bigelow Homes outside Chicago, have reduced space-heating 

intensities to a small fraction of their 1973 levels. 

As suggested by the preceding discussion, the end-use 

perspective on energy demand helps explain important historic evolutionary trends. As an illustration, overall energy 

intensity for space heating in homes has plunged in major 

industrialized countries (fig. 4). Similar trends can be seen 

for energy-using devices located within buildings. An examination of trends in the heating fuel used in OECD coun-

...,. Figure 3. Trends in energy and economic activity. In both 

graphs, projected energy (light solid lines) is calculated on the 

basis of the gross national product (GNP) in constant dollars, 

with both forecast and "back-cast" values from 1973. Note that 

the GNP back-cast generally follows the actual consumption 

curve (heavy solid lines) before 1973. The "Primary Energy" on 

the left-hand scales includes fuel burned at power plants, in units 

of quads per year. A quad (also abbreviated on fig. 3 as q) is a 

quadrillion (1015) British thermal units. The energy savings were 

converted from quads to fractions of OPEC (Organization of Petroleum Exporting Countries) capacity using an estimated 1986 

total OPEC production capacity of 29 million barrels of oil per 

day (58 quads). For the right-hand scales, quads were converted 

to 1984 dollars using the 1984 U.S. cost of energy (about $440 

billion). A, Energy use in the United States, actual and projected 

by GNP. B, Energy use in the entire Organization for Economic 

Cooperation and Development (OECD), actual and projected by 

GNP. The OECD includes all of North America, Western Europe, 

Japan, Australia, and New Zealand, and consumes about twice as 

much total resource energy as the United States alone. Oil and 

gas savings for the OECD in 1985 were five-sixths of total 

OPEC capacity. 
INCREASED EFFICIENCY AND RENEWABLE FORMS OF ENERGY AS COMPETITIVE ENERGY RESOURCES 853 

tries shows the rapid rate of fuel substitution that can occur 

in response to changes in energy prices and policies directed toward influencing the fuel choice in buildings (fig. 5). 

thing but pre-ordained. In fact, projections of world energy 

demand over the next 50 years vary by more than a factor 

of two (U.S. Department of Energy, 1991/1992) (fig. 6). 

These differences stem primarily from assumptions about 

energy-efficiency trends. 

Given possible developments on the demand side, the 

future of energy demand (and thus energy gases) is any-

> 

0> 

..... 

Q) 

c 

w 

> ..... 

co 

E 

·;:: 

(L 

A 

....::-

co 

Q) 

> -

en 

""0 

co 

::::J 

CJ 

> 

~ Q) 

c 

w 

> 

L.. 

co 

E 

L.. 

0... 

100 

90 

80 

70 

60 

50 

40 

1965 

200 

180 

160 

140 

120 

100 

80 

TOTAL PRIMARY ENERGY 

GNP-Projected ~ 

Actual\ ~ 

Back-cast by GNP 

L 

OECD 

1970 1975 

Year 

TOTAL PRIMARY ENERGY 

GNP-Projected ---....________ 

Actual----. ~ 

-- -

1980 

-- "'--- ----.... .... 

--- _.....,. .... _ _, 

/

by GNP .... _ _,,.,...,. 

-_, .,. 

.,. 

.... OIL & GAS!/ 

GNP-Projected 

Actual .,. 

I 

25 q 

Primary 

Energy 

Saved 

___ ·1 i 

Gas and Oil 

Saved = 1/2 of OPEC 

Capacity 

--. l 

1985 

-

'T 

42.5 q 

Primary 

Energy 

Saved 

l 

T 

Gas and Oil 

Saved = 5/6 of OPEC 

Capacity 

1 

60 

40 

..................... 7 .................................... .. ...... ··········~~·~·~··~il & Gas Production · 

.;::::- ..;::::-

·~~~~~~--~~~~~~--~~~~ 

1965 1970 1975 1980 1985 

B Year 

600-en 

Q) 

(.) 

550 ·;:: 

a. 

-.;:t 

co 

500 0) 

.... 

co 

450 w 

c 

0 

400 := 

CIJ 

-.... 350 ~ 

u 

300 ~ 

c 

c 

250 <( 

1200 

1100 

Ul 

1000 ~ 

·;:: 

0. 

900 -.:t 

CX) 

0) 

soo m 

Eo~) 

700 g 

600 (]J 

.... 

en 

0 

500 u 

co 

::::l 

400 § 

<1:: 

300 
854 THE FUTURE OF ENERGY GASES 

500 ,KJ_I_d_e_g-_d_a_y-_a_q_m ______________ ___ 

us 

France 

300 Germany 

---*- Denmark 

Canada 

--+- Sweden 

200 

100 L__L __ ~ __ L__J __ _L __ J_ __ L__j 

197219741976197819801982198419861988 

Figure 4. Oil-heating intensity (measured as energy use per unit 

of floor area, normalized for differences in weather from country 

to country) in countries of the Organization for Economic Cooperation and Development (OECD; includes all of North America, 

Western Europe, Japan, Australia, and New Zealand). Data are 

for single-family homes with central heat. KJ, kilojoules; deg, 

degree-day Celsius; sq m, square meter. From Schipper and others (1992). 

1200 

1000 

800 

::::J 

as 

c 

~ 600 

~ !1l 

::::J 

a 

400 

200 

0 

A Energy lnfonnation Administration (EIA), Annual 

Energy Outlook, 1990 (low growth case). 

B EIA, 1990 (base case). 

C EIA, 1990 (high grCM'lh case). 

D Commission of the European Communities, 1989 

("Where We Are Headed" case). 

E Edmonds & ReiUy, G/oba/ Energy Future, 1985. 

F J. Goldemberg et al., Energy for a Sustainable World, 

1988 (low). 

G World Energy Conference (WEC), 1963 (low). 

H WEC, 1983 (high). 

1960 

IIIIIIOil 

D Gas 

• Coal ~ Nuclear 

D Hydro 

rn Other 

1970 1980 1990 

US GER FAA ITA UK SWE DK NOR 

DolL, LPG EJ GAS OcoAL, coKE 

53wooo 0 ELECTRICITY 13 DISTRICT HEATING 

Figure 5. Principal space-heating fuel, 1973-1990, in some 

countries of the Organization for Economic Cooperation and Development (OECD; includes all of North America, Western Europe, Japan, Australia, and New Zealand). US, United States; 

GER, former West Germany; FRA, France; ITA, Italy; UK, United Kingdom; SWE, Sweden; OK, Denmark; NOR, Norway; 

LPG, liquefied petroleum gas. District heating is centrally produced steam or hot water. Source: Lawrence Berkeley Laboratory, International Energy Studies. 

International lnstitu~ for Applied Systems Analysis 

(IIASA), 1981 (low). 

J IIASA, 1981 (high). 

K Oak Ridge National Laboratory (ORNL), Energy 

Technology R&D, 1989 (high efficiency). 

L ORNL, 1989 (low efficiency). 

2000 2010 2020 2030 

Figure 6. Historical (1960-1988) and projected (1990-2030) world energy consumption. Differences in projections are caused, in 

part, by varying assumptions concerning energy efficiency, energy prices, economic growth, consumer and producer behavior, and 

rates of technological change, including replacement of capital stock. The shaded area at right represents an envelope bracketing 

these differences. Btu, British thermal unit. From U.S. Department of Energy (1991/1992). 
INCREASED EFFICIENCY AND RENEWABLE FORMS OF ENERGY AS COMPETITIVE ENERGY RESOURCES 855 

POWERFUL ANALOGIES: ENERGY EFFICIENCY 

AS A DEMAND-SIDE ENERGY RESOURCE 

Throughout the energy-supply arena, one can identify 

concepts analogous to demand-side resources (table 1). For 

example, exploring for new energy supplies can be likened 

to performing energy audits in buildings or industries to 

identify the specific opportunities for applying efficient 

technologies. Some examples of these opportunities are indicated in table 2, where energy savings by several end-use 

technologies are quantified in terms of avoided gas use. 

At a large scale, seemingly insignificant energy-efficient technologies (for lamps, ballasts, fixtures, and lighting controls) can displace sizable amounts of energy. A 

recent assessment of the prospects for improving the efficiency of residential and commercial lighting energy use 

in the United States-beyond improvements anticipated 

from existing utility and government programs targeting 

lighting-found that primary savings equivalent to 95 trillion cubic feet of natural gas could be achieved between 

1995 and 2030 (Atkinson and others, 1992). Moreover, 

these savings could be achieved with a net economic benefit (value of energy saved minus the extra investment for 

the efficient technologies) of over $100 billion. 

As an illustration of options to reduce demand for 

heating fuels, the windows produced over 10 years by a 

single $20-million factory for coating low-emissivity glass 

will save as much heating gas (21 0 billion cubic feet, 

equivalent to 36,000,000 barrels of oil) as produced by a 

$300-million offshore oil platform (fig. 7). More than two 

times this quantity of primary energy would be saved if 

heating were instead provided with electricity derived 

from fossil fuels. 

These low-emissivity window coatings are rapidly penetrating the market and-in combination with low-conductivity gas fillings-have doubled the thermal resistance 

(measured by the "R-value") of old-fashioned "thermopane" 

windows from R-2 to R-4. Many major U.S. window manufacturers such as Andersen, Pella, and Marvin, now offer 

low-E (low-emissivity) windows exclusively. During the 

past five years, 50 million low-E windows were sold in the 

United States. A 33-percent market share for new residential 

Table 1. Analogies between supply-side and demand-side energy-planning paradigms. 

[Btu, British thermal unit] 

Concept Supply-side paradigm Demand-side paradigm 

Services---------------- More energy supply and use------------------- More efficient use of energy. 

Exploration------------ Drilling, mining, and so on-------------------- Energy auditing, and so on. 

Resource base -------- Existing energy resources---------------------- Technically avoidable energy use. 

Reserves--------------- Economically recoverable energy------------- Economically reducible demand. 

Unit cost--------------- $/Btu supplied ----------------------------------- $/Btu saved. 

Environment---------- Emissions----------------------------------------- Avoided emissions. 

Planning--------------- Forecasts: Supply and demand weakly Scenarios: Supply and demand linked expliclinked, usually only by modest incorporation itly via technology assessments of both proof price impacts. ducers and consumers. 

Table 2. Some examples of end-use efficiency as an energy resource. 

[Economic benefits assume a price of $7 per thousand cubic feet of natural gas. For electricity production, a thermal efficiency of 11,500 British thermal units 

per kilowatthour (including transmission losses) and natural-gas input fuel are assumed] 

End-use technology 

Efficient compact fluorescent lamp ------------------------------------

Low-emissivity window coatings: 

-gas used directly as space-heating fuel -------------------------

or 

-gas used to produce electricity for space heating -------------

Low-flow showerhead: 

-gas used directly as water-heating fuel -------------------------

or 

-gas used to produce electricity for water heating -------------

Approximate natural-gas savings 

4,000 cubic feet ($28) over 10,000-hour lifetime of lamp. 

I ,000 cubic feet ($7) per square foot of window area over 10-

year lifetime of window. 

2,500 cubic feet ($17) per square foot of window area over 10-

year lifetime of window. 

7,000 cubic feet ($50) per year. 

20,000 cubic feet ($140) per year. 
856 THE FUTURE OF ENERGY GASES 

Capital outlay: $20 million 

20,000,000 tt2 insulated glass per year 

1 0 years production 

20-year window lifetime 

36,000,000 

barrels oil 

equivalent 

Capital outlay: $300 million 

10,000 barrels per day 

1 0 years production 

Figure 7. The windows produced over 10 years by a single $20-million factory for coating low-emissivity glass (left) will save the 

equivalent of as much oil (36,000,000 barrels) as would be produced over 10 years by a $300-million offshore oil platform (right). 

Source: Lawrence Berkeley Laboratory. 

construction has already been reached and is expected to 

grow to as much as 80 percent by the end of the decade (fig. 

8). In the limiting case of full market saturation (I 00 percent 

of windows), 70 million low-E windows would be sold 

annually with corresponding yearly net savings of $4 billion. 

This savings would displace the equivalent of 300,000 barrels of oil per day, or 620 billion cubic feet of natural gas 

per year, also equivalent to the production of 30 typical 

offshore oil platforms. 

THE ENERGY-ENVIRONMENT CONNECTION 

Increased awareness of environmental problems associated with energy production and consumption, especially 

concerning emissions of greenhouse gases that contribute 

to global climate change, has led to a growing emphasis 

on improved energy efficiency. The purposes for which 

energy is used can be correlated with the resultant environmental impacts. For example, total U.S. energy-related 

carbon dioxide emissions are allocated to the various associated end uses in figure 9 (U.S. Office of Technology Assessment, 1991 ). From this vantage point, U.S. emissions 

can be attributed to buildings, transportation, and industry 

% Sales 

100 

90 

70 

60 

so-l- -1--i-+-f-·-·-1--+-b-4-e''· 

40-l -1--+-+-+-+-:::;;&~~"'F'--t- b~ 

20 

1987 

Year 

Natural Gas Saved 

in Mbod 

0.2 

Figure 8. Market penetration data for low-emissivity windows. 

Data, plotted separately for residential and commercial markets, 

are historical values (1987-1991) and projected ranges (1992-

2000). Projections were made for new and existing buildings. 

Right-hand scale shows natural gas saved by use of low-emissivity windows instead of traditional double-glazed windows, calculated in million barrels of oil per day (Mbod) equivalent. For 

comparison, Alaska's Prudhoe Bay has produced an average of 

about 1.8 Mbod, and it is estimated that the Arctic National 

Wildlife Refuge (ANWR) could produce about 0.3 Mbod. 

Source: Lawrence Berkeley Laboratory Building Technologies 

Program, based on industry sources. 
INCREASED EFFICIENCY AND RENEWABLE FORMS OF ENERGY AS COMPETITIVE ENERGY RESOURCES 857 

Buildings: 

Water heat 9% 

Lights 14% 

Cooling 14% 

Appliances 20% 

Space heat 43% 

Transportation: 

_ ..... ._ Nonoil-based 2% 

Rail, marine 7% 

Aircraft 14% 

Heavy trucks 14% 

Light trucks 20% 

Automobiles 43% 

Steam 27% 

Machine drive and 

electrolytic 32% 

Figure 9. 1987 U.S. C02 emissions by sector. Total carbon emissions from all three sectors 

equaled about 1.3 billion metric tons in 1987. Emissions have continued to increase since 

then. HVAC, heating, ventilating, and air-conditioning. From U.S. Office of Technology Assessment (1991). 

in approximately equal proportions. Space heating, personal automobiles, and machine drives and electrolytic processes are the most significant end uses within each sector. 

Given this information, various end uses can be 

looked to for opportunities to reduce C02 emissions, and 

the costs of efficiency improvements can be associated 

with given reductions in emissions. If costs of efficiency 

improvements are greater than the cost of the energy 

avoided, then a net cost (for example, $/tonne) can be assigned to the emissions avoided. Alternatively, if the costs 

are less, then a negative cost (or benefit) can be assigned. 

Many beneficial "negative-cost" options exist for all sectors, with typical benefits on the order of $I 00/tonne of 

carbon avoided, that is, $IOO net savings for every tonne 

of emissions avoided (Mills and others, I99I). 

As an example of nationwide prospects for energy 

savings via improved energy efficiency, the U.S. National 

Academy of Sciences estimated that U.S. COz-equivalent 

emissions could be reduced by I billion tonnes annually 

(I8 percent of current national emissions from all sources) 

through implementation of energy-efficiency options in existing buildings (National Academy of Sciences, I992). 

Because the study was restricted to energy-saving options 

that were less expensive than producing or buying energy, 

these savings bring with them a net economic benefit of 

$62 saved per tonne of reduced emissions. 

IDENTIFYING AND RECOVERING 

DEMAND-SIDE ·RESOURCES 

There exists a diversity of energy sources and associated costs. Supply curves, like the one shown in figure I 0, 

have been a useful tool for characterizing energy resources 

in terms of technical and economic constraints. On the 

horizontal axis of these staircase-style curves is the total 

energy resource available. On the vertical axis is the cost 

of recovering each unit of energy. As an illustration, the 

Canadian gas supply curve shown in figure IO indicates a 

total resource of almost 200 trillion cubic feet, with increments recoverable at progressively increasing costs. 

Analogous supply curves have been derived for demand-side resources (fig. II). In this case, the horizontal 

axis is the energy potentially conserved and the vertical 

axis is the cost per unit of energy conserved. The cost of 

conserved energy is defined as the annualized incremental 

. cost of the efficient technology, compared to the standard 

technology otherwise used, divided by the annual energy 

savings. The cost of conserved energy is thus in the units 

of $/unit of energy and can be easily compared to the prevailing costs of energy otherwise consumed. Figure II presents a comprehensive curve prepared for natural gas use 

in the residential sector of a New York gas utility (National 

Fuel Gas) (Nadel and others, I993). Each step corresponds 
858 THE FUTURE OF ENERGY GASES 

to a different technology, for example, increased insulation, 

more-efficient gas water heaters, more-efficient furnaces. 

The curve shows that reductions of 80 percent of residential gas consumption would be achieved at a marginal cost 

of conserved energy of about $6/decatherrn ( 1 decatherrn=106 British thermal units), comparable to the prevailing retail price of delivered gas. A sensitivity analysis 

for 50-percent higher and 25-percent lower costs of con50 100 150 200 

GAS RESERVES, IN TRILLION CUBIC FEET 

Figure 10. Supply curve showing cost of recovering natural gas versus total estimated 

natural-gas reserves in western Canada. ~ 

15 ~------------------------------------------, 

~ 10 

Q 

e 

., 

C) "' 

il 

~ en 

.... 6 0 

~ 5 

4 

2.5 

0 

0 10 20 30 40 50 60 70 80 90 

Cumulative Savings as a Percent of Residential Consumption 

Figure 11. Comprehensive supply curve (labeled Prime) of natural gas conserved 

in residential sector of a New York gas utility (National Fuel Gas). Curves labeled 

+50%, +25%, and -25% show how the supply curve would shift if actual costs of 

conserved energy were higher or lower (by the percentages shown) than the costs 

calculated in the study. Horizontal lines drawn across graph indicate retail prices 

($6/DTh) and the range of marginal costs ($2.50/DTh to $4.00/DTh). These are 

reference points against which to compare costs of conservation. If the cost of 

conserving energy is below the retail price line, then the efficiency investment is 

cost effective-it is cheaper than new supply investments. DTh, decatherm, or ten 

therms, where one therm is 100,000 British thermal units. From Nadel and others 

(1993). 
INCREASED EFFICIENCY AND RENEWABLE FORMS OF ENERGY AS COMPETITIVE ENERGY RESOURCES 859 

served energy yielded a corresponding t:ange of savings of 

50 to 85 percent. Marginal gas costs range from $2.50/ 

decatherm to $4.00/decatherm for this utility, corresponding to a range of savings of about 30 percent to about 50 

percent for the above-mentioned sensitivity assumptions. 

In practice, the extent to which an energy-savings potential is realized depends on the policy effort applied toward 

achieving the goal. As discussed below, various barriers impede progress; nonetheless, innovative policy mechanisms can 

be used to overcome those barriers. 

MAKING MARKETS FOR 

ENERGY SERVICES 

PERFECT MARKETS 

The question is often raised that "if energy efficiency 

is so cheap, then why are the resources not already fully 

utilized?" The answer lies in the disparity between economic theory and the actual functioning of energy markets. In theory, if markets were perfect, all cost-effective 

efficiency options would be acquired. In this context, a 

"perfect" market means one in which there is full competition, consumers have accurate and complete information, 

customers have access to capital and a full spectrum of 

technical options, energy prices reflect direct costs, and 

external costs (for example, environmental degradation) 

are internalized in energy prices. In reality, energy markets 

are rarely perfectly competitive; market "barriers" or "failures" are said to exist. 

BARRIERS TO LEAST-COST ENERGY 

A least-cost energy future (in terms of both economic 

and environmental costs) will not come about under the 

current market situation, primarily because households, 

businesses, manufacturers, and governments do not fully 

recognize and exploit societally cost-effective opportunities for energy efficiency. The result is a significant gap 

between current and optimum levels of energy efficiency 

(Hirst and Brown, 1989). 

Energy prices are often the main (if not only) factor 

discussed with respect to consumer interest in energy efficiency. Indeed, distortions in energy prices (for example, 

subsidies, tariffs not reflective of increasing marginal 

costs, and neglect of environmental and other external 

costs) can impede energy savings behavior. In this respect, 

energy taxes have been discussed recently in the United 

States. Prices certainly play a role, but often not as large 

as economic theory predicts (Mills, 1991 ). There are many 

specific groups that influence energy use but are insulated 

in one manner or another from energy prices (examples 

include builders, landlords, and occupants of nonresidential buildings). Furthermore, energy pricing offers a much 

less certain degree of energy impact than many other policy mechanisms. 

Important market barriers (and corresponding policy 

opportunities) exist aside from energy pricing issues. As 

evidence of the barriers, consumers in all sectors implicitly 

require very fast payback times when making tradeoffs between increased initial costs and reduced operating (energy) 

costs. The resulting problem is often referred to as the "payback gap." Electric utilities, for example, commonly accept 

10- to 15-year payback times on their investments, but studies of end-use efficiency choices made by energy consumers 

reveal implicit payback times ranging from a few years to a 

few months. The following factors can contribute to the 

payback gap: (1) inadequate information and limited consumer awareness of efficiency options; (2) restricted access 

to capital and financing; (3) split incentives (for example, 

between landlords paying for equipment and tenants paying 

for energy); (4) inadequate product availability and skill 

base, naive marketing of efficiency options; (5) loss of revenues to energy suppliers that might otherwise promote efficiency (linked to price); and (6) imbalanced levels of 

subsidies and research-and-development funding between 

efficiency technologies and supply technologies. 

POLICY SOLUTIONS FOR IMPROVING 

ENERGY MARKETS 

Policy mechanisms exist that address each of the barriers just described. The following list encompasses broad 

categories of policies that have been used at the national 

or local level, alone or in combination, to foster changes 

in the energy system. 

Getting prices right. Examples include time-of-use tariffs, marginal cost pricing, and addition of environmental 

costs to the unit prices of energy. 

Improved information for energy decision-makers. Examples include energy rating labels, such as those found 

today on all major appliances and on automobiles. 

Standards and other legislative measures. Examples 

include mandatory and voluntary thermal efficiency_ standards for buildings, and appliance standards (National Appliance Energy Conservation Act, NAECA). Mandatory 

thermal standards for buildings can now be found in many 

parts of the world (Busch and Janda, 1992). 

Utility regulatory reform. The prospect of lost revenues 

associated with conservation programs that would successfully lower energy demand is a formidable disincentive to 

energy vendors, primarily utilities. In several regions of the 

U.S., profit rules have been re-defined such that program 

costs are recovered, revenues are decoupled from sales volumes, and net financial benefits of conservation programs 

are shared between utility shareholders and consumers. Similar trends are underway in Europe (Mills and Borg, 1991 ). 
860 THE FUTURE OF ENERGY GASES 

Financial incentives to consumers. Utilities in the 

United States and Europe have offered a variety of rebates 

to residential, commercial, and industrial buyers of energyefficient products such as lighting, space heating and cooling equipment, motors, and appliances (Nadel, 1990; Mills, 

1993). These incentives are often calibrated to equal most 

or all of the extra costs associated with implementation of 

the more efficient technology. 

Market transformation (catalyst or temporary incentives 

to change an energy-services marketplace). One example is 

a "Golden Carrot" program directed at U.S. refrigeratorfreezer manufacturers which has recently been developed by 

a consortium of utilities, government agencies, refrigerator 

manufacturers, and other interested parties. The utilities 

have pooled $30 million to be paid to the manufacturer{s) 

of units that beat the 1993 National Appliance Standards by 

between 30 and 50 percent (Nadel, 1992). Similar activities 

are underway in Sweden (Nilsson, 1992). In another example, the U.S. Environmental Protection Agency's "Green" 

programs have succeeded in recruiting the largest corporations in the country to adopt a policy of implementing highly 

efficient technologies in their buildings. Their "Green 

Lights" program has already captured approximately 8 percent of U.S. commercial building floor area. 

Revenue-neutral fee/rebate ("feebate") systems. Examples include sliding-scale hookup fees for new automobiles or buildings-those achieving less efficiency than a 

pre-set goal must pay a fee; the fees are in turn distributed 

as rebates to those exceeding the target (Koomey and 

Rosenfeld, 1990). 

Government-sponsored research, development, and 

demonstration. Government research has resulted in important advancements and commercialization of new lowemissivity windows, efficient flame-retention head burners, 

and electronic ballasts (Geller and others, 1987). 

Most of the aforementioned policies have been implemented only at a local level. As an illustration of the cumulative national potential for a comprehensive application of 

the kinds of policy strategies outlined above, Geller and 

others (1991) constructed a high-efficiency energy-demand 

scenario for the United States and compared it to a business-as-usual forecast. The result indicates that U.S. primary energy demand could actually be held constant in 

absolute terms between the years 1990 and 2010, even 

with a 2.2-percentlyear real increase in GNP. The conventional forecast, in contrast, indicates a 13-percent increase 

in energy demand by 2010. 

IMPLICATIONS FOR 

ENERGY SUPPLIERS 

Three important factors-end-use efficiency, fuel 

switching, and supply efficiency-affect the amounts of 

natural gas and other forms of primary energy that will be 

demanded in the future. 

The current baseline forecast by the Gas Research Institute highlights some of the important trends affecting 

natural gas (Holtberg and others, 1993). The institute's 

findings reflect a keen awareness of the distinction between 

energy services and energy itself and the importance of 

taking an end-use perspective in evaluating future demand: 

[A]t moderate energy prices and with continued improvements in 

energy efficiency, limited growth in demand will be the primary constraint on any expanded role that natural gas can play in the energy mix. 

Any significant increase in the use of gas will have to be associated with 

investment in new gas-using equipment-turbines, methane vehicles, appliances, space-conditioning devices, or industrial facilities * * *. New 

gas demand, therefore, depends first upon growth in the need for energy 

services [and] upon the customer having a choice of new, competitive 

gas-using equipment to serve those needs. 

As shown in table 3, the Gas Research Institute (1993) 

predicts that between 1991 and 2010 the most important 

areas of growth in natural-gas demand will be the industriTable 3. Summary of 1993 baseline natural-gas forecast by Gas Research Institute. 

[Residential, commercial, industrial, and transport statistics include only direct use of fuels, not indirect use of fuels consumed in generation of electricity. quad, 

quadrillion (10 15) British thennal units. Source: Holtberg and others (1993)] 

Natural gas as Change in 

Change in gas Annual growth market share for Total gas demand, of gas demand, a fraction of natural gas, Main end uses responsible Sectors demand in total energy 

2010 (quads) 1991-2010 1991-2010 

demand in 

1991-2010 for change in gas demand 

(quads) (percent/year) 2010 (percent) (percentage 

points) 

Residential ----------------------- 4.7 0.0 0.0 68 -1 Space heating. 

Commercial ---------------------- 3.5 .6 1.0 43 1 Cooling, cogeneration. 

Industrial ------------------------- 11.2 2.3 1.2 36 0 Process steam, cogeneration. 

Transport ------------------------- 1.4 .7 3.7 5 2 Natural-gas vehicles. 

Electricity ------------------------ ~ u 2.0 12 2 Power plants. 

Total or average----------------- 25.0 4.9 1.2 23 All of above. 
INCREASED EFFICIENCY AND RENEWABLE FORMS OF ENERGY AS COMPETITIVE ENERGY RESOURCES 861 

a1 sector (in absolute terms) and the transport and electricity supply sectors (as measured by rates of growth). As 

evidenced by an assumed 1.3 percent/year decline in energy use per unit of GNP, efficiency trends will tend to offset 

potential demand growth. For the power sector, gas demand growth will be moderated by anticipated improvements in power-plant conversion efficiencies. While total 

gas-based electricity production will increase by more than 

50 percent, the average amount of primary energy input 

required to produce electricity will decline by 27 percent in 

new power plants. Although natural-gas vehicles will be a 

growing new end use for gas, they are projected to capture 

only 5 percent of the transport energy market by 2010. 

CHANGING ROLES FOR MODERN UTILITIES 

As consumers and distributors of 17 percent of global 

primary energy, electric and gas utilities are among the most 

important actors in the energy arena. Given their pre-established contact with and information about energy consumers, 

their familiarity with end-use equipment, and their access to 

capital, utilities are logical purveyors of energy efficiency 

(Hirst and others, 1991 ). Under traditional economic regulation, however, the only strong incentive for utilities to pursue 

demand-side resources has been to improve public relations 

and to accommodate the political expectations of their regulators to present an environmentally conscious image. 

Gas utilities in the United States have begun to implement programs in which they provide conservation-related 

information, technical assistance, and financial incentives 

to their consumers (RCG/Hagler, Bailly, Inc., 1991 ). In the 

United States as of 1992, utilities in about half of the States 

had initiated efforts in this area (fig. 12) (Samsa and Hederman, 1992). These programs include energy audits, weatherization assistance, insulation, high-efficiency equipment, 

• Gas IRP or DSM Regulations Established 

~ Gas IRP or DSM Regulations Under Development 

Figure 12. Status of gas-utility integrated resource planning 

(IRP) and demand-side management (DSM) regulations in the 

United States. From Samsa and Hederman (1992). 

and heating-system retrofits, gas cooling, heat recovery, and 

interruptible rates in the residential, commercial, and industrial sectors (figs. 13, 14) (Goldman and Hopkins, 1991). 

These efforts will increase rapidly, given the new national Comprehensive Energy Policy Act legislation passed 

in 1992 (P.L. 102-486). The legislation encourages investment in improved efficiency by ensuring a profit motive 

for gas utilities: 

The rates charged by any State regulated gas utility shall be such 

that the utility's prudent investments in, and expenditures for, energy 

Number of States 

30 ,---------------------------------------------, 

25 

20 

15 

10 

5 

0 

51% D Some Utilities - All Utilities 

3 3% 

Energy 

Audits 

29% 29% 

24% 24% 

Weatherization Envelope 

Asst Improvement 

(Infiltration) (Insulation) 

28% 

High-Eft 

Equipment 

Htg System 

Retrofit 

Figure 13. Energy-efficiency programs offered by gas utilities to 

residential customers. Percent values indicate percentage of all 

50 states. For example, in 51 percent of the states, all of the 

utilities offer energy audits to residential customers, and in 33 

percent of the states, some of the utilities offer energy audits. 

Therefore, in 84 percent of the states, some or all of the utilities 

offer energy audits to residential customers. Asst, assistance; Eff, 

efficiency; Htg, heating. From Goldman and Hopkins (1991). 

Number of States 35 ~--------------------------------------------, 

64% 

D Some Utilities - All Utilities 30 

25 

20 

15 

10 18 16% 

5 

~~L_ __ _J_Ma_ ____ ~ill_----~~----_L~~-----L~~ 

Interruptible Equip. Weatherization Envelope 

Rates Replacement lmprovment 

Gas 

Cooling 

Ind. Ht. 

Recovery 

Figure 14. Energy-efficiency programs offered by gas utilities to 

commercial customers. Percent values indicate percentage of all 

50 states. For example, in 64 percent of the states, all of the 

utilities offer interruptible rates to commercial customers, and in 

18 percent of the states, some of the utilities offer interruptible 

rates. Therefore, in 82 percent of the states, some or all of the 

utilities offer interruptible rates to commercial customers. Equip, 

equipment; Ind Ht, industrial heat. From Goldman and Hopkins 

(1991). 
862 THE FUTURE OF ENERGY GASES 

conservation and load shifting programs and for other demand-side management measures * * * are at least as profitable * * * as prudent investments in the acquisition or construction of supplies and facilities. 

Numerous electric, gas, and dual-fuel utilities have 

also become active in promoting fuel-switching programs. 

Like conservation programs, fuel-switching programs offer 

information and financial incentives to consumers (Hamilton and others, 1992). In two examples, Vermont's Ludlow 

Electric Light Department offers $600 rebates for the removal of electric heating systems and $70 for removal of 

electric water heaters, and Vermont's Burlington Electric 

Department will buy down the incremental cost of such 

rebates to a 3-year payback period. Burlington's customers 

are offered financing for the other costs, in which payments equal 60 percent of the estimated savings in energy 

costs. 

ELECTRICITY PRODUCTION: ONE-QUARTER OF 

THE WORLD'S GAS USE 

Electricity is an important energy carrier, derived 

often from natural gas and potentially from other energy 

gases. Globally, approximately 15 percent of the electricity 

is today made from gas, corresponding to 25 percent of 

the world's total gas use. The great preponderance of gasbased electricity production is in North America (fig. 15). 

The potential for growth in gas demand is substantial, esTWh 

3 000 

2 500 

2 000 

I 500 

I 000 

500 

North 

America 

1960 

Pacific Europe North 

America 

pecially in the North American power sector (Holtberg and 

others, 1993). 

Efficiency trends for electric power plants are dramatic. Average thermal efficiencies of approximately 5 percent 

at the tum of the century grew to 20 percent by the 1940's 

and then to 35 percent by the 1970's. These efficiencies 

now pale in comparison with those of modem advanced 

gas turbines, which offer up to 52-percent efficiencies, and 

cogeneration systems, which produce useful heat and 

power with even higher efficiencies (Williams and Larson, 

1989). Some emerging technologies are represented in figure 16, in which carbon-equivalent emissions per unit of 

useful energy produced are compared. Note that in two instances emissions from natural-gas technologies actually 

exceed those from coal-based systems. 

Increases in electricity end-use efficiency can result in 

upstream gas savings. Electric utilities have a substantially 

longer history of working with energy-efficiency programs 

for their customers than do gas utilities. Today, $3 billion 

to $4 billion is spent annually for conservation programs 

sponsored by electric utilities in North America. The results of these efforts have contributed to a precipitous drop 

in capital investment from a peak of about $45 billion in 

1980 to $20 billion today. The majority of this shift can be 

attributed to efficiency, and half to the growing industry of 

independent power producers. As an indicator of the future, California utilities plan to meet 75 percent of future 

energy-services needs with efficiency. 

1970 

Pacific Europe North 

America 

1980 

Pacific Europe 

Figure 15. Electricity generation, by fuel, in International Energy Agency regions: 1960, 

1970, and 1980. TWh, terawatthour (109 kilowatthours). 
INCREASED EFFICIENCY AND RENEWABLE FORMS OF ENERGY AS COMPETITIVE ENERGY RESOURCES 863 

CJ Natural gas 

.Oil 

D Coal 

0 2 3 4 5 6a 7 ga 

Type of system 

Figure 16. Greenhouse-gas emissions from commercially available power plants. 

Central-station power plants (0-5, 7, 9) are compared with cogeneration plants (6", 

83

, 10"-13") that provide both power and useful heat. Energy requirement for electricity production using cogeneration technologies is taken as total energy supplied 

minus that which would have been required to produce the heat independently (assuming boiler efficiency corresponding to lower-heating-value of 90 percent). All 

power-plant efficiencies (Eft) are based on higher heating values. For the cogeneration systems, power-to-heat ratios are shown as E/H. The greenhouse gases are expressed as an equivalent amount of carbon dioxide per kilowatthours equivalent (g 

C02 equivalent/kWhe). Methane and methane-related fuel-cycle emissions from 

coal, oil, and natural-gas consumption are taken into account. I, Average conventional steam turbine (Eff 34 percent); 2, Best available steam turbine (Eff 39 percent); 3, 

Pressurized fluidized bed combustion (Eff 42 percent); 4, Average conventional 

steam turbine (Eff 38 percent); 5, Best available combined-cycle gas turbine (Eff 48 

percent); 6", Average conventional steam turbine (Eff 78 percent, EIH=0.50); 7, Average combined-cycle gas turbine (Eff 36 percent); 83

, Best available steam turbine 

(Eff 83 percent, EIH=0.60); 9, Best available combined-cycle gas turbine (Eff 45 

percent); 10", Pressurized fluidized bed combustion (Eff 86 percent, E/H=0.65); I I •, 

Best available steam turbine (Eff 81 percent, EIH=0.60); 12", Steam-injected gas 

turbine (Eff 75 percent, EIH=0.80); 13", Best available combined-cycle gas turbine 

(Eff 77 percent, EIH=l.O). From Mills and others (1991). 

RENEWABLE ENERGY 

So-called "renewable" sources of energy (biomass, 

wind, direct solar photovoltaic, direct solar thermal, 

solar-hydrogen, geothermal, hydroelectricity, and so on) 

form another important component of integrated resource 

planning. This arises because ( 1) these new resources are 

now approaching economic competitiveness with fossilbased energy sources (fig. 17), (2) they can be provided 

without net emission of greenhouse gases and other 

pollutants addressed by the integrated-resource-planning 

paradigm, and (3) they are generally domestic and secure. As such, renewable sources of energy pose an increasingly important competitive challenge to fossil-based 

energy gases and an opportunity for nonfossil energy 

gases. 

A recent global assessment found that world C02 reductions of 26 percent from 1985 levels (by the year 

2050) could be brought about through intensive substitution away from coal and oil toward renewable sources, 

combined with significant improvements in energy efficiency (Johansson and others, 1993) (figs. 18, 19). In this 

scenario, the market share of gas would increase, mostly 

in the power sector. Measured in terms of potential resource base, the single most important renewable contributor to electricity production is gasified biomass, produced, 

for example, from the residues of the world's cane sugar 

industries and exported to the national electricity grid. 
864 THE FUTURE OF ENERGY GASES 

1980 1985 1990 1995 2000 2005 2010 

Figure 17. Costs of electricity generated from renewable resources fell sharply in the 1980's and will continue to fall as 

technology improves and experience is gained. Electricity costs 

(vertical axis) are based on actual (solid lines) or projected (broken lines) costs for bulk power generation. Costs are also shown 

for new coal-fired base-load and natural gas-fired peaking plants. 

From Weinberg and Williams (1990). 

..... Figure 18. Scenario for reducing world C02 emissions by 

replacing fossil fuels with renewable energy sources. A, Direct 

fuel use. In this scenario, global use of fuels for purposes other 

than electricity generation will grow by less than one-third, much 

less than the generation of electricity (see figure 18B). The contribution by renewable energy sources could reach nearly one-fourth 

by 2025 and two-fifths by 2050, with most of the contribution 

coming from biomass-derived fuels-methanol, ethanol, hydrogen, and biogas. Methanol and hydrogen may well prove to be the 

biofuels of choice, because they are energy carriers most easily 

used in fuel cells that would power transportation in this scenario. 

B, Electricity generation. In this scenario, the share of renewable 

energy generation will increase from 20 percent in 1985 (mostly 

hydroelectric power) to about 60 percent in 2025, with roughly 

comparable contributions from hydropower, intermittent renewable sources (for example, wind and direct solar power), and biomass. The contribution of intermittent renewable sources could be 

as high as 30 percent by middle of next century. High rate of 

penetration by intermittent renewable sources without electrical 

storage would be facilitated by emphasis on advanced natural-gasfired gas-turbine power-generating systems. Such systems-characterized by low capital cost, high thermodynamic efficiency, and 

the flexibility to vary electrical output quickly in response to 

changes in output of intermittent power-generating systemswould make it possible to "back up" intermittent renewable sources at low cost, with little, if any, need for electrical storage. In this 

scenario, the share of natural gas in power generation will nearly 

double by 2025, from its 12-percent share in 1985. TWh, terawatthour (109 kilowatthours). From Johansson and others (1993). 

ISSUES FOR DEVELOPING COUNTRIES 

AND ECONOMIES IN TRANSITION 

THE SETTING 

Developing countries and economies in trans1t10n are 

faced with escalating demands for energy. Although the 

per-capita GNP and energy consumption of these countries 

are far lower than those of typical industrial countries, 

their energy efficiency is also generally lower and the rate 

of growth in demand for energy services is far higher. Between 1973 and 1988, annual growth in energy consumption averaged 5.4 percent in developing countries and 2.3 

percent in Eastern Europe, compared to an average of 0.9 

percent in OECD countries (Levine and others, 1991). 

The cost of providing energy drains money away from 

efforts to provide food, health services, housing, and other 

basic needs in poor countries, and hence has become a 

serious constraint (rather than aid) to development. Nonetheless, demand for energy services will grow as these coun300 

~ 200 .. "' s ~ - iJ 

.a~ ~~ 

v " 

-~ ~ 0 iJj 100 

0 

1985 2025 2050 

Year 

A • Coal l§j Oil QGas m B1omass 0 PV/Wind H2 

40.000 

c: 30,000 0 

·;o "' ~ -"' ! ~ .. ~ 

"'~ 20, 

:f~ 

~ ;;:; 10, 

1985 2025 2050 

Year 

• Coal !il Oil 0Gas ITJ Nuclear 

B I2J Hydro ~ B1omass ~ Intermittent renewables and geothermal 
INCREASED EFFICIENCY AND RENEWABLE FORMS OF ENERGY AS COMPETITIVE ENERGY RESOURCES 865 

8,000 

;; 

Ql 

>-

Q; 6,000 c. 

c: 

0 

-e 

['] 

0 4,000 

~ 

"' c: 

c: 

B 

c: 2,000 

~ ::!! 

0 

1985 

World 

lnd = industrialrzed countries 

Dev = developing countries 

2025 2050 

Year 

• Coal (i] Oil 0 Gas 

Figure 19. Reductions in global C02 emissions predicted on 

basis of scenario presented in figure 18. In this scenario, global 

C02 emissions will be reduced 12 percent by 2025 and 26 percent by 2050. During this period, C02 emissions from industrialized countries (including former U.S.S.R. and other Eastern 

European countries) would be reduced by nearly one-half by 

2025 and nearly two-thirds by 2050. Industrialized-country share 

of total worldwide emissions would decline from about threefourths in 1985 to about two-fifths in 2025 to about one-third in 

2050. From Johansson and others (1993). 

tries become more affluent; the challenge is to minimize the 

energy needed to meet this rightful demand for energy services (Reddy and others, 1990). Taking these factors together, it seems clear that if end-use efficiency is ignored, the 

cost of providing energy services can become a great problem indeed. 

Experience to date has shown that even with impressive expansion of installed generation capacity, electricity 

demand in developing countries and Eastern Europe continues to exceed power-system capacity. Rapidly escalating 

demand, coupled with deteriorating utility performance, 

has led to persistent unscheduled power outages which result in measurable economic losses (U.S. Agency for International Development, 1988). The present power-system 

expansion plans of developing countries and Eastern Europe will require staggering annual investments of nearly 

$70 billion until 2000, and about $145 billion for the first 

quarter of the next century. In comparison, the current annual World Bank lending for the power sector is less than 

$4 billion; including the lending from all multilateral and 

bilateral sources, total lending is less than $10 billion 

(Moore and Smith, 1990). 

To complicate the situation, much of the energy sold 

worldwide is subsidized by governments, leading to consumer expectations for inexpensive energy and inefficient 

use of energy. Recent attempts to raise energy prices in 

Jamaica, Ecuador, and Guatemala have been met with protests, civil disorder, and changes in governments (Hill, 

1987, 1988). Furthermore, entrenched and powerful bureaucracies in utility companies historically have been exclusively concerned with expanding supply. At the same time, 

inefficient energy use translates into unnecessary emissions 

of greenhouse gases and other environmental risks. Accelerating the pace of increases in energy efficiencies is thus also 

in the global interest (Levine and others, 1991 ). 

Policies are beginning to be implemented to address 

the barriers in developing countries. Import duties (which 

can double the retail price of energy-efficient products) 

have been drastically reduced in Pakistan and Thailand. 

Mandatory efficiency standards for commercial buildings 

are being developed within the Association of Southeast 

Asian Nations (ASEAN). Electric utilities in Thailand, 

Mexico, and Brazil are planning to initiate or have already 

initiated financial incentive programs for efficient lighting 

in households, in businesses, and on streets. As another 

means of gathering capital, Western entrepreneurs have 

entered into joint ventures to produce efficient lighting 

products in developing countries and Eastern Europe. 

NATURAL GAS IN DEVELOPING COUNTRIES 

With respect to natural gas, developing countries demonstrate a distinctly different energy-use profile than industrial countries. While about 70 percent of the world's 

energy is used in industrialized countries, 90 percent of 

the world's natural gas is used in industrialized countries 

(U.S. Office of Technology Assessment, 1992). Furthermore, natural gas is rarely used in electricity production in 

the developing world (fig. 15). At least 52 developing 

countries possess significant natural-gas resources, most of 

which were identified in the search for oil. In 1975, 80 

percent of all natural gas produced in developing countries 

was flared. Today, 97 percent of the gas produced in Nigeria is flared (U.S. Office of Technology Assessment, 1992). 

If natural-gas infrastructure is expanded in developing 

nations, then gas can become a more significant competitor with other fossil fuels there. On the other hand, given 

its relative abundance and labor-intensiveness, biomass energy probably poses a more competitive threat to new uses 

of gas in developing countries than in industrialized countries. A particularly large potential exists in the cane-sugar 

industries, as noted above. 

TOWARD A NEW SYNTHESIS: 

INTEGRATED RESOURCE PLANNING 

The energy sector is returning to a service-based and 

end-use-oriented planning paradigm. Integrated resource 

planning, which is built upon a marriage of economics, 

engineering, and environmental science, recognizes increased end-use efficiency as a significant and robust energy 
866 THE FUTURE OF ENERGY GASES 

resource and uses economic and noneconomic costs to 

weigh supply options. Thus far, integrated resource planning has been focused almost exclusively on the electricity 

sector; it is likely, however, that the concept will find applications in other energy and nonenergy sectors. 

The traditional forecasting approach for defining 

"business-as-usual" energy futures shows an increase in 

energy demand, albeit with a reduction in intensity (the 

ratio of energy use per unit of economic activity). Such 

forecasts tend to represent what will happen if the current 

market (with its embedded barriers and failings) persists 

into the future. In contrast, an emerging scenario approach 

allows the visualization of options that are consistent with 

today's environmentally sustainable and economically efficient energy and environmental planning goals. The scenario approach emphasizes policy change and market 

transformation and allows comparative analysis of various 

classes of energy futures. 

In summary, among the lessons learned from studying 

today's dynamic energy situation is the need to be cautious about predicting the future on the basis of the past. 

Technologies, economic relationships, and planning objectives are changing. Importantly, these trends (both on the 

demand and supply side) imply the loss of market share 

for some existing uses of energy gases and the creation of 

new markets for others. Increased efficiency of gas-based 

electricity supply and end-use technologies are examples 

of the former, and fuel switching from electricity to gas at 

the point of end use and the introduction of gasified biomass cogeneration systems are examples of the latter. 

In contrast to relatively passive forecasting activities, 

a more proactive approach can be taken in which energy 

demand is managed and supply sources are systematically 

chosen to satisfy various technical, economic, and environmental criteria. To the extent that energy planning will 

be directed by goals of minimizing the economic and environmental costs of providing energy services to s9ciety, 

it is critical to note that neither supply-side nor demandside strategies alone can achieve an optimal future. Integrated energy-efficient, renewable, and natural-gas scenarios will likely be the strategy of choice through the next 

century. 

ACKNOWLEDGMENTS 

This work was funded by the Assistant Secretary of 

Conservation and Renewable Energy, Office of Buildings 

and Community Systems, Office of Building Technologies 

of the U.S. Department of Energy, under Contract No. DEAC03-76SF00098. The author thanks Alan Comnes and 

Jonathan Koomey (Lawrence Berkeley Laboratory) and 

Michael Fanelli and David Howell (U.S. Geological Survey) for their comments on an early draft. 

REFERENCES CITED 

Atkinson, B., McMahon, J., Mills, E., Chan, P., Chan, T., Eto, J., 

Jennings, J., Koomey, J., Lo, K., Lecar, M., Price, L., Rubinstein, F., Sezgen, 0., Wenzel, T., 1992, Analysis of federal policy options for improving U.S. lighting energy 

efficiency-Commercial and residential buildings: Lawrence 

Berkeley Laboratory Report No. 31469, Berkeley, Calif. 

Burnett, W.M., and Ban, S.D., 1989, Changing prospects for natural gas in the United States: Science, 21, v. 244, p. 305-

310. 

Busch, J., and Janda, K., 1992, Worldwide status of energy 

standards for buildings, in Proceedings of the ACEEE 1992 

Summer Study on Energy Efficiency in Buildings: Washington, D.C., American Council for an Energy-Efficient Economy, p. 6.103-6.105. 

Davis, G.R., 1990, Energy for planet Earth: Scientific American, 

v. 263, no. 3, p. 54. 

Friedel, R., Israel, P., and Finn, B.S., 1986, Edison's electric 

light-Biography of an invention: New Brunswick, New 

Jersey, Rutgers University Press, p. 121. 

Geller, H.S., Harris, J., Levine, M., and Rosenfeld, A., 1987, The 

role of federal research and development in advancing energy efficiency-A $50 billion contribution to the U.S. economy: Annual Review of Energy, v. 12, p. 357-395. 

Geller, H.S., Hirst, E., Mills, E., Ross, M., and Rosenfeld, A.H., 

1991, Getting America back on the energy-efficiency track: 

Washington, D.C., American Council for an Energy-Efficient 

Technology, 63 p. 

Goldman, C.A., and Hopkins, M.E., 1991, Survey and analysis 

of state regulatory activities on least cost planning for gas 

utilities: Lawrence Berkeley Laboratory and National Association of Regulatory Utility Commissioners, Lawrence Berkeley Laboratory Report No. 30353. 

Grubb, M.J., and Meyer, N.I., 1993, Wind energy-Resources, 

systems, and regional strategies, in Johansson, T.B., and others, eds., Renewable energy-Sources for fuels and electricity: Washington, D.C., Island Press, p. 157-212. 

Hamilton, LB., Milford, L., Parker, S., and Steinhurst, W., 1992, 

Fuel switching programs in Vermont-Issues and experiences, in Proceedings of the ACEEE 1992 Summer Study on 

Energy Efficiency in Buildings; Washington, D.C., American 

Council for Energy-Efficient Economy, p. 8.79-8.87. 

Hill, L.J., 1987, Energy price reform in developing countriesIssues and options: Oak Ridge, Tenn., Oak Ridge National 

Laboratory Report No. 6391. 

---1988, Implementing energy price reform in developing 

countries: Natural Resources Forum, v. 12., no. I, February. 

Hirst, E., and Brown, M., 1989, Closing the efficiency gap-Barriers to the efficient use of energy: Oak Ridge, Tenn., Oak 

Ridge National Laboratory, 17 p. 

Hirst, E., Goldman, C., and Hopkins, M.E., 1991, Integrated resource planning-Electric and gas utilities in the USA: Utilities Policy, v. 1, no. 2, p. 172-186. 

Holdren, J.P., 1992, The transition to costlier energy, in Schipper, 

L., Meyers, S., and others, eds., Energy efficiency and 

human activity-Past trends, future prospects: Cambridge, 

England, Cambridge University Press, 400 p. 

Holtberg, P.D., Woods, T.J., Lihn, M.L., and Koklauner, A.B., 

1993, Baseline projection data book-1993 edition of the 
INCREASED EFFICIENCY AND RENEWABLE FORMS OF ENERGY AS COMPETITIVE ENERGY RESOURCES 867 

GRI baseline projection of U.S. energy supply and demand 

to 2010: Washington, D.C., Gas Research Institute. 

Johansson, T.B., Kelly, H., Reddy, A.K.N., and Williams, R.H., 

1993, Renewable energy-Sources for fuels and electricity: 

Washington, D.C., Island Press, 1160 p. 

Koomey, J.G., and Rosenfeld, A.H., 1990, Revenue-neutral incentives for efficiency and environmental quality: Contemporary Policy Issues, v. 8, p. 142-155. 

Levine, M.D., Gadgil, A., Meyers, S., Sathaye, 1., Stafurik, 1., 

and Wilbanks, T., 1991, Energy efficiency, developing nations, and Eastern Europe-A report to the U.S. working 

group on global energy efficiency: Washington, D.C., International Institute for Energy Conservation, 60 p. 

Mills, E., 1991, Uncertainties in the price-responsiveness of energy" demand-An end-use comparison of Denmark and 

Sweden: Lund, Sweden, Lund University, Department of 

Environmental and Energy Systerris Studies, 42 p. 

---1993, Efficient lighting programs in Europe-Cost-effectiveness, consumer response, and market dynamics: Energy-The International Journal, v. 18, no. 2, p. 131-144. 

Mills, E., and Borg, N., 1991, Short-term financial impacts of 

energy-efficiency programmes on European electric utilities-Case studies for nine utilities in five countries, in 

Mills, E., ed., Proceedings of the 1st European Conference 

on Energy-Efficient Lighting: Stockholm, Sweden, Swedish 

National Board for Industrial and Technical Development, 

p. 305-318. 

Mills, E., Wilson, D., and Johansson, T.B., 1991, Getting started-No regrets strategies of reducing greenhouse-gas emissions: Energy Policy, v. 19, no. 6, p. 526-542. 

Moore, E., and Smith, G., 1990, Capital expenditures for electric 

power in the developing countries in the 1990s: World Bank, 

Industry and Energy Department, Energy Series Paper No. 21. 

Nadel, S., 1990, Lessons learned-A review of utility experience 

with conservation and load management programs for commercial and industrial customers: Washington, D.C., American Council for an Energy-Efficient Economy, 226 p. 

---1992, Stalking the golden carrot-A utility consortium to 

accelerate the introduction of super-efficient, CFC-free refrigerators, in Proceedings of the ACEEE Summer Study on 

Energy-Efficiency in Buildings: Washington, D.C., American 

Council for an Energy-Efficient Economy, p 5.137. 

Nadel, S., Eto, J., Kelly, M., and Jordan, J., 1993, Gas DSM and 

fuel-switching-Opportunities and experiences: Washington, 

D.C., American Council for an Energy-Efficient Economy. 

-'----National Academy of Sciences, 1992, Policy implications of 

'> ~greenhouse warming-Mitigation, adaptation, and the science 

b~se: Washington, D.C.; National Academy Press, 918 p. 

National Association of Regulatory Utility Commissioners 

(NARUC), 1988, Least-cost utility planning handbook for 

public utility commissioners: Washington, D.C., NARUC. 

Nilsson, H., 1992, Market transformation by technology procurement and demonstration, in Proceedings of the ACEEE 1992 

Summer Study on Energy-Efficiency in Buildings: Washington, D.C., American Council for an Energy-Efficient Economy, p. 6.179. 

RCG/Hagler, Bailly, Inc., 1991, Integrated planning, DSM evaluation and cost recovery issues for gas distribution utilities: 

Boulder, Colo., RCG/Hagler, Bailly, Inc. 

Reddy, A.K.N., Sumithra, G.D., Balachandra, P., and d'Sa, A., 

1990, Energy conservation in India-A development-focused end-use oriented energy scenario for Karnataka, 

Part 2-Eiectricity: Bangalore, India, Department of Management Studies, Indian Institute of Science. 

Samsa, M.E., and Hederman, W.F., 1992, Gas utility resource 

planning-How far does the electric analogy go?: Public 

Utilities Fortnightly, October 1, 1992, p. 40-42. 

Schipper, L., Meyers, S., Howarth, R., and Steiner, R., 1992, Energy 

efficiency and human activity-Past trends, future prospects: 

Cambridge, England, Cambridge University Press, 400 p. 

U.S. Agency for International Development, 1988, Power shortages in developing countries-Magnitude, impacts, solutions 

and the role of the private sector: Report to U.S. Congress. 

U.S. Department of Energy, 1989, Energy conservation trendsUnderstanding the factors that affect conservation gains in 

the U.S. economy, (DOE/PE-0092): Washington, D.C., Office of Policy, Planning and Analysis, Office of Conservation 

and Renewable Energy. 

U.S. Department of Energy, 199111992, National energy strategy 

(1st ed.): Washington, D.C., p. A-2. 

U.S. Office of Technology Assessment, I 992, Fueling development-Energy technologies for developing countries: U.S. 

Congress, Office of Technology Assessment. 

U.S. Office of Technology Assessment, 1991, Changing by degrees-Steps to reduce greenhouse gases (OTA-0-482): 

Washington, D.C., U.S. Government Printing Office, 354 p. 

Wiel, S., 1991, The new environmental accounting-A status report: The Electricity Journal, November 1991, p. 46-54. 

Weinberg, C.J ., and Williams, R.H., I 990, Energy from the sun: 

Scientific American, v. 263, no. 3, p. 146. 

Williams, R.H., and· Larson, E.D., I 989, Expanding roles for 

gas turbines in power generation, in Johansson, T.B., Bodlund, B., and Williams, R.H., eds., Electricity-Efficient 

end-use and new generation technologies, and their planning implications: Lund, Sweden, Lund University Press, 

p. 503-553. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

How Ultimate is Ultimate Gas Recovery? 

1 By Thomas J. Woods 

CONTENTS 

Abstract .................................................................. · ..... · 869 

Introduction ................................................................... 869 

Ultimate Gas Recovery ................................................ 870 

Changes in Industry Perceptions .................................. 871 

Potential Gas Committee ....................................... 871 

National Petroleum Council .................................. 872 

Effects of Expanded Industry Perceptions ................... 872 

Resource Base Effects ........................................... 873 

Effects on Production ............................................ 873 

Conclusions ................................................................... 875 

References Cited ........................................................... 875 

ABSTRACT 

Estimates of ultimate gas recovery reflect industry 

perceptions at the time the estimates were made. Industry 

perceptions, however, are dynamic, not static. Over the 

last 20 years, industry perceptions of the recoverable gas 

resources of the lower 48 States have expanded significantly. These expanded perceptions, driven in large part 

by advances in technology and practice, have led to an 

increased optimism about the prospects for gas production 

from the lower 48 States under conditions of low-to-modest prices. Historical experience demonstrates that industry activity expands industry resource perceptions and, 

with it, estimates of ultimate recovery as much or more as 

this activity depletes the resource base estimated under its 

current perceptions. 

1

Gas Research Institute, Strategic Planning and Analysis Division, 

Washington, D.C. 

This paper will review past estimates of the gas resource potential from the lower 48 States in light of expanding industry perceptions and new technology as well 

as their effects on current industry activity and future gas 

production and prices. 

INTRODUCTION 

Projections of long-term trends in gas prices, particularly since the 1970's, generally have been based on the 

concept of ultimate gas recovery (in other words, gas is a 

depletable resource). Under this theory, gas prices rise 

steadily as the resource is depleted. As a result, projections 

of long-term gas supply are accompanied by steadily increasing prices, with limited prospects for stable or increased supply. 

Recent events, however, have called into question the 

applicability of a depletable resource concept in projecting 

long-term trends in gas production and prices for the 

lower 48 States. Current gas prices are less than half of 

their early 1980's peaks, and prospects for increased prices 

in the future have weakened substantially. Nevertheless, 

since the mid-1980's, the industry has replaced reserves 

depleted by growing gas production in the lower 48 States 

with new reserves using levels of drilling activity previously thought to be too low. Continued replacement of gas 

production without increased gas prices appears inconsistent with the concept of ultimate gas recovery. 

Estimates of ultimate gas recovery for the lower 48 

States reflect industry perceptions at the time the estimates 

were made. Industry perceptions, however, are dynamic, 

not static. As industry activity continues, new areas are 

found to be productive that were not productive in previous industry perceptions of the resource. New, less conventional resources are added, and the capability of the 

industry to recover gas from known fields and active plays 

869 
870 THE FUTURE OF ENERGY GASES 

increases. As a result, future industry activity should lead 

to increased estimates of ultimate. gas recovery, just as 

they lead to increased cumulative gas discoveries. 

Over the last 20 years, industry perceptions of the recoverable gas resource base from the lower 48 States 

have expanded significantly. New technology has reduced 

the costs and risks to develop gas reserves. Resources in 

offshore areas with water deeper than 500 meters are now 

economic to develop at modest prices. New areas, which 

were thought to have little or no resource potential in 

1970, such as the deep Norphlet play in the eastern Gulf 

of Mexico (see Lore, this volume), the Arkoma Basin, 

and the Overthrust Belt, are now expected to have substantial resource potential. Less conventional resources 

(for example, tight sands, shales, and coal seams), which 

were often little more than research curiosities, are now 

active~ expanding sources of gas production. Therefore, 

long-term projections of gas supply and price that do not 

recognize the effects of expanding industry perceptions on 

the recoverable gas resource potential will tend to overstate the upward pressures on gas prices and the downward pressures on gas supply. 

This paper will review recent gas resource estimates 

from the lower 48 States to identify the specific changes 

in gas resource perceptions that have occurred over the 

last 20 years. It will also discuss the extent to which 

changed resource perceptions have affected the outlook 

for gas production from the lower.48 States. The gas supply trends in the 1993 edition of the Gas Research Institute (GRI) baseline projection (Woods, 1993) will be used 

as a framework for this latter discussion. 

ULTIMATE GAS RECOVERY 

Beginning with the U.S. Department of Energy (DOE) 

gas study in 1988, estimates of ultimate gas recovery in the 

lower 48 States have become more optimistic (U.S. Department of Energy, Office of Policy, Planning, and Analysis, 

1988). With 1988 technology, the DOE study estimated 

that, including proved reserves, 1 ,059 trillion cubic feet 

(Tcf) of gas remained to be recovered as of the end of 1986. 

As of the end of 1990, the 1988 DOE study would have 

implied that 993 Tcf of recoverable gas remained. 

Table 1 presents five recent resource estimates. The 

resource estimate in the 1993 GRI baseline projection 

(Woods, 1993) is the largest resource estimate, and the Potential Gas Committee (PGC) ( 1990) estimate is the lowest. Compared to the estimates showing a technology 

range, the PGC appears very conservative about the prospects for new technology expanding the gas resource potential for the lower 48 States. 

Table 1. Remaining gas resource potential from the lower 48 States as of December 31, 

1990. 

[GRI 93. estimate used in the 1993 edition of the Gas Research Institute baseline projection; DOE NES, U.S. 

Department of Energy estimate used in the development of the National Energy Strategy; Enron 91, Enron estimate published in 1991; PGC 90, 1990 Potential Gas Committee estimate; NPC 92, resource estimate used in the 

recent National Petroleum Council study. Data from Woods, 1993; U.S. Department of Energy, Energy Informa· 

tion Administration, 1990; Enron, 1991; Potential Gas Committee, 1991; National Petroleum Council, 1992. 

Ranges in the GRI, DOE, and Enron estimates reflect the effects of both current and advanced technology; PGC 

estimate does not· explicitly present technology effects; NPC estimate is only for the advanced technology case. 

Estimates are adjusted to bring them to the same point in time, December 31, 1990; NA, not applicable] 

Category 

GRI 93 DOENES Enron 91 PGC90 NPC 92 1 

(Tcf) (Tcf) (Tcf) (Tcf) (Tcf) 

New fields------------------------ 608-667 263-326 588-6312 421 413 

Reserve appreciation------------ 244 177-265 NA 157 203 

Total------------------------- 852-911 440-591 588-631 577 616 

Unconventional increment----- 329-514 295-503 257-4013 88 519 

Total------------------------- 1117-1425 735-1094 845-1032 665 1135 

Adjustments to 12/31/90------- NA -36 -19 NA NA 

Total-----------"------------- 1117-1425 699-1058 826-1013 665 1135 

1

2010 technology only. 2Enron estimate does not break out new fields and reserve appreciation. 3Includes improved recovery from high-permeability reservoirs. 
HOW ULTIMATE IS ULTIMATE GAS RECOVERY? 871 

The reserve appreciatiOn and unconventional increment resources in the GRI, DOE, Enron, and National Petroleum Council (NPC) estimates in table 1 are relatively 

consistent. The GRI new-fields resource is the reason the 

GRI estimate is the largest. The GRI new-fields resource 

is more optimistic about the relatively unexplored deeper 

sediments in the lower 48 States than are the other 

estimates. 

CHANGES IN INDUSTRY PERCEPTIONS 

A review of industry resource .estimates for the last 20 

years indicates that industry resource perceptions have expanded substantially. Two of the estimates in table 1 span 

this period-the PGC and the NPC estimates. The PGC 

estimates have been made on a regular two-year interval 

over this period, and the NPC has estimated the gas resource potential for the lower 48 States in two studiesone in 1992 and the other in 1972 (National Petroleum 

Council, 1972, 1992). 

POTENTIAL GAS COMMITTEE 

The PGC has estimated the gas resource potential for 

the lower 48 States on a detailed regional basis since 

1966. These resource estimates provide a historical record 

of industry resource perceptions for more than 25 years. 

The PGC estimate of the remaining potential for the 

lower 48 States peaked at 851 Tcf in 1970. By 1986 its 

estimate had declined to 620 Tcf. Since 1988, the PGC 

estimate has increased, reflecting the addition of coalbed 

methane to the PGC resource assessment. 

The PGC perceptions of the gas resource potential for 

the lower 48 States have expanded since 1970. The most 

explicit reflection of this expansion is the inclusion of 

coalbed methane, beginning with the 1988 estimate. PGC 

perceptions, however, have also expanded since 1970 to 

reflect the effects of new areas, new plays, and other less 

conventional resources. New technology and practices 

(exploration and development techniques) developed over 

the last 20 years have been critical to these expanded 

perceptions. 

The 1970 PGC estimate of the ultimate gas recovery 

from the lower 48 States did not include gas resources in 

offshore areas with water depths greater than 1,500 feet. 

Its 1990 estimate includes the offshore resource potential 

of areas with water depths greater than 1,000 meters 

(about 3,300 feet). The 1970 PGC estimate also did not 

expect much, if any, gas r~~pvery from the offshore deep 

Norphlet Formation in the Gulf of Mexico; today the deep 

Norphlet is considered to be one of the largest, if not the 

largest, gas play ever discovered in the lower 48 States 

(see Lore, this volume). 

In the onshore areas, similar \'!Xpansions have taken 

place relative to the 1970 perceptions. Coalbed methane is 

now included in the PGC estimate, as is some low-permeability potential in the Rocky Mountains outside the San 

Juan Basin and in East Texas. The resource potentials in 

the Overthrust Belt and the deeper Arkoma Basin formations have increased as well. 

Finally, for area other than the Texas Gulf Coast, reserve additions between 1971 and 1985 in the fields discovered before 1971 (pre-1971 fields) have exceeded the 

1970 PGC estimate of future reserve additions in these 

fields. Reserve additions in the pre-1971 fields continue to 

be strong, although the 1970 PGC estimate implied that 

reserve additions in these fields would have ended by 

1985 or earlier. As a result, the 1990 PGC estimate includes substantial volumes of reserve additions in pre1971 fields that were not in its 1970 estimate. 

Table 2 allocates the PGC ( 1990) estimate of the remaining resource potential for the lower 48 States to 1970 

perceptions and post -1970 perceptions. The gas resource 

potential is presented for probables (reserve additions in 

known fields) and new fields (possible plus speculative 

fields). The post-1970's resource perceptions is further allocated to areas in the lower 48 States (for example, the 

Green River area) or resource categories (pre-1971 fields, 

coalbed methane). 

The post-1970 perceptions resource (table 2) are mostly in three categories: reserve additions to pre-1971 fields, 

Table 2. Gas resource potential for the lower 48 States-1990 

Potential Gas Committee report. 

[Da!Jl from Potential Gas Committee, 1990) 

Category 

Probables New fields 1 Total 

(TeO (Tel) (Tcf) 

Lower 48 States------------------ 166.1 499.5 665.6 

Post-1970 perceptions: 

Ovef1hrust Belt--------------- 7.3 13.6 20.9 

Green River Bas in ----------- 9.1 20.5 29.6 

Deep Gulf of Mexico 0 47.2 47.2 

Norphlet Trend --------------- 3.6 11.7 15.3 

Deep Atlantic ----------------- 0 .3 .3 

Deep Pacific------------------- 0 4.5 4.5 

Arkoma Basin ---------------- .3 1.9 2.2 

Pre-1971 fields---------------- 60 0 60 

Coal bed methane------------- 9.6 78.6 88.2 

Total---------------------- 89.9 178.3 268.2 

1970 perceptions----------------- 76.2 321.2 397.4 

1

Possible plus speculative gas potential. 
872 THE FUTURE OF ENERGY GASES 

offshore, and coalbed methane. More than half of the PGC 

probable resource potential reflects the effects of expanded 

PGC resource perceptions since 1970. More than 33 percent of the PGC new-fields potential reflects expanded 

PGC resource perceptions since 1970. Overall, 40 percent 

of the remaining resource potential for the lower 48 States 

in the 1990 PGC estimate was not in the PGC perceptions 

of the resource base in 1970. 

The expanded resource perceptions since 1970 have 

also affected proved reserves. As of the end of 1990, 

more than 10 percent of the gas reserves from the lower 

48 States could be assigned to the post-1970 perception 

categories. Therefore, without the expanded industry resource perceptions since 1970, gas reserves from the 

lower 48 States at the end of 1990 would have been closer to 140 Tcf instead of 160 Tcf. While this lower reserve 

level could theoretically support the actual gas production 

from the lower 48 States in 1991, gas prices would have 

been much higher because there would have been no "gas 

bubble." 

NATIONAL PETROLEUM COUNCIL 

In 1972 and 1992, the NPC published energy studies 

in which it estimated the gas resource potential for the 

lower 48 States (National Petroleum Council, 1972, 1992). 

Table 3 compares the resource potential from the 1972 

study with the resource potential in the 1992 study. The 

1972 potential is brought forward to 1990 by subtracting 

gas reserve additions between 1971 and 1990. 

Table 3 shows that the NPC estimated that the gas resource potential for the lower 48 States was 906 Tcf in the 

1972 study. Between 1971 and 1990, the industry added 

272 Tcf of gas reserves, thereby leaving a remaining reTable 3. Gas resource potential for the lower 48 States1972 and 1992 National Petroleum Council studies. 

[Data from National Petroleum Council, 1972, 1992) 

Category 

National Petroleum Council 1972 Study 

Potential 

(Tcf) 

Potential as of 12/31/70---------------------------------- 906 

Reserve additions 1971-90------------------------------ 272 

Potential as of 12/31190---------------------------------- 634 

National Petroleum Council 1992 Study 

Potential as of 12/31/90 based on: 

1990 technology ------------------------------------ 905 

2010 technology ------------------------------------ 1135 

source potential of 634 Tcf. This would have been the remaining resource potential had industry perceptions of the 

gas resource base not expanded over the last 20 years. 

However, the NPC concluded in 1992 that the gas resource potential for the lower 48 States was 905 Tcf as of 

December 31, 1990, essentially unchanged from what the 

NPC estimated as the potential in 1972. Table 2 indicates 

that, as industry activity was depleting the "known" resource potential, expanding industry perceptions were replacing the depleted potential with new resources, just as 

the industry replaces production with new reserves. 

The 1992 NPC study expects that technology and 

practices will continue to improve after 1990, thus further 

increasing the recoverable gas resource potential in the 

producing regions and formations in the lower 48 States. 

The NPC study estimates that, as a result of these continued improvements, the resource potential increases 25 percent to 1,135 Tcf (table 3). Relative to the 1972 study, the 

NPC has increased its expectations of potential resource 

for 2010 as of 1990 by 79 percent. 

The 2010 technology resource potential (table 3), 

however, does not include the effects of expanded industry 

perceptions for new regions or formations. As a result, the 

2010 technology resource potential in the 1992 NPC study 

does not fully reflect the incremental resource potential of 

expanded industry perceptions over the next 20 years. 

Given the industry track record of expanding resource perceptions, it is reasonable to expect that, if the NPC does 

another gas study 20 years in the future, the resource potential could be unchanged or even larger. 

EFFECTS OF EXPANDED INDUSTRY 

PERCEPTIONS 

Projections of gas production from the lower 48 

States have become more optimistic since the mid-1980's. 

In the 1970's and early 1980's, gas production from the 

lower 48 States was projected to decline to as little as 10 

Tcf by 2010. Since the mid-1980's, many projections now 

show gas production from the lower 48 States remaining 

stable or even increasing. The increased optimism reflects 

the effects of expanded industry resource perceptions, 

driven in large part by advances in industry technology 

and practice. 

The 1993 edition of the GRI baseline projection 

(Woods, 1993) is consistent with this optimism. Gas production from the lower 48 States grows steadily in the 

1993 projection, exceeding 20 Tcf by 2010. The major 

share of the resource potential used in the 1993 projection 

reflects the expanded industry resource perceptions since 

1970. As a result, the 1993 edition of the GRI baseline 

projection (Woods, 1993) can provide a reference against 

which the effects of the expanded resource perceptions on 

the gas resource potential for the lower 48 States and the 
HOW ULTIMATE IS ULTIMATE GAS RECOVERY? 873 

outlook for production from the lower 48 States can be 

assessed. 

RESOURCE BASE EFFECTS 

The resource potential for the lower 48 States used in 

the 1993 edition of the GRI baseline projection (Woods, 

1993) can be allocated among 1970, 1970-90, and post1990 resource perceptions. The 1970 perceptions resource 

potential is based on the PGC resource description. Table 

4 presents the results of this allocation. 

Table 4 shows the effects of expanding industry resource perceptions since 1970 on the remaining resource 

potential for the lower 48 States. Only 30 percent of the 

total remaining resource potential in the 1993 GRI baseline projection (Woods, 1993) would be available if industry perceptions of the resource base had remained ·at their 

1970 levels. Forty-three percent of the total remaining potential reflects the effects of advances in industry perceptions from 1970 to 1990, and the continued advance in 

industry perceptions after 1990 accounts for the remaining 

27 percent of the total resource potential. Overall, expanded industry resource perceptions between 1970 and 1990 

and the expected continued expansion of resource perceptions after 1990 account for more than two-thirds of the 

remaining gas resource potential for the lower 48 States in 

the 1993 GRI projection. 

Most of the new-fields potential in the 1993 GRI baseline projection (Woods, 1993) reflects the effects of expanded industry perceptions since 1970 (table 4). Only 

about 40 percent of the new-fields potential would be 

available if industry perceptions had remained at their 

1970 level. The remaining new-fields potential is about 

equally divided between 1970-90 and post-1990 perceptions. The post-1990 perceptions potential is principally 

due to the continued ability of the industry to expand the 

resource potential deeper than 10,000 ft in the gulf coast 

region, both onshore and offshore. These sediments have 

had very little exploration activity to date. 

In table 4 the reserve appreciation potential is about 

equally divided between 1970 and 1970-90 perceptions. 

No potential is included for continued expansion of reserve additions in known fields past 1990, although, on the 

basis of past industry results, some additional gas reserve 

appreciation resource potential should be in the post-1990 

perceptions category. 

Almost all of the less conventional gas resource 

(shale, coal seams, and tight sands) in the 1993 GRI baseline projection (Woods, 1993) reflects the expansion of industry perceptions since 1970 (table 4). The modest 

volumes in the pre-1970's perceptions represent Devonian 

shale and low-permeability gas in the Appalachian Basin 

and some low-permeability gas in the Rocky Mountains 

and the Southwest. 

EFFECTS ON PRODUCTION 

We assessed the effects of expanded industry resource 

perceptions since 1970 on the outlook for gas production 

from the lower 48 States. We assumed that industry resource perceptions did not change after 1970. As a result, 

gas production from the lower 48 States was projected 

from 1991 to 2010 using the remaining gas resource potential of 410 Tcf (table 4). In this sensitivity, we reduced 

proved reserves in 1990 to 142 Tcf to exclude reserves in 

areas or formations for which industry had limited or no 

expectations in 1970 (for example, Norphlet Trend, Overthrust Belt, San Juan Basin Fruitland coals). Table 5 compares the gas production trend for the lower 48 States in 

the resource sensitivity calculation (1970 perceptions) to 

the trend in the 1993 edition of the GRI baseline projection (Woods, 1993), which used a resource potential of 

1425 Tcf and a 1990 gas reserve for the lower 48 States of 

160 Tcf. 

Table 5 shows that if industry resource perceptions 

had not expanded since 1970, gas production from the 

lower 48 States would decline steadily between 1991 and 

2010. The sensitivity does indicate, however, that the 

Table 4. Remaining gas resource potential for the lower 48 States as of 

December 31, 1990-1993 edition of the Gas Research Institute baseline 

projection. Table 5. Gas production from the lower 48 States. 

[Data from Woods, 1993. NA, not applicable] [Data from Woods, 1993. GRI. Gas Research Institute] 

1970 1970-90 Post-1990 Total remaining 

Category perceptions perceptions perceptions potential 

Year 93 GRI perceptions 1970 perceptions 

(Tcf) (Tcf) 

(Tcf) (Tcf) (Tcf) (Tcf) 1991 16.8 16.8 

New fields------------------- 269 198 200 667 1995 17.9 14.7 

Reserve appreciation------- 129 115 NA 244 2000 18.8 12.2 

Less conventional ---------- 28 301 185 514 2005 19.8 11.9 

Total -------------------- 426 614 385 1425 2010 20.4 10.6 
874 THE FUTURE OF ENERGY GASES 

142 Tcf of proved gas reserves in 1990 (discussed 

above) can support the actual production of 16.8 Tcf in 

1991 (table 5). This surprising result reflects the existence of the "gas bubble" and the effects of new technology and practices developed between 1970 and 1990. 

This indicates that even in 1991, most gas production 

and reserves from the lower 48 States came from the 

1970 perceptions resource, although they rely in part on 

post-1970 technology. 

Table 5 shows that the improved outlook for gas production from the lower 48 States since the 1970's relies 

on resources that were not in the industry perceptions in 

1970. Without expanded reso_urce perceptions since I 970, 

gas production from the lower 48 States would decline 

by about one-third between 1991 and 2010 (table 5), a 

decline consistent with the expectations of the 1970's and 

early 1980's. With the expanded resource perceptions, 

however, gas production from the lower 48 States grows 

steadily. By 2010, it is almost double the production that 

could be achieved if industry perceptions had not expanded (table 5). 

Gas production from the lower 48 States can be allocated among five gas-resource categories (table 6). The 

high-permeability and associated gas resource categories 

are generally referred to as conventional, while the other 

three categories (low permeability, Devonian shale, and 

coalbed methane) are referred to as less conventional. 

Table 6 compares gas production from the lower 48 

States by gas resource category in the 1993 GRI baseline 

projection (Woods, 1993) and the projected production 

using only the 1970 perceptions resource potential. 

Table 6 shows that about 87 percent of gas production from the lower 48 States in 1991 came from conventional sources. Conventional sources play a somewhat 

larger role in the sensitivity than they do in the 1993 

GRI baseline projection (Woods, 1993), which offsets the 

absence of coalbed methane production and the smaller 

low-permeability production. By 1995, however, the con-

. ventional gas potential based on 1970 perceptions of the 

gas resource potential cannot maintain gas production 

from conventional sources at its 1991 level, let alone offset the lower production from less conventional sources. 

Without the post-1970 resource, high-permeability production declines 45 percent between 1991 and 2010, 

compared to about a 12 percent increase with the addition of the post-1970 resource in the 1993 GRI projection 

(table 6). This decline in gas production in the sensitivity 

reflects the limited prospects for reserve appreciation in 

known fields and new field discoveries in the deeper sediments of the gulf coast regions and the absence of gas 

production in the Overthrust Belt and the deep Norphlet 

Trend in the eastern Gulf of Mexico. 

Associated gas production declines almost 50 percent 

over the projection period without the post-1970 resource, instead of stabilizing by the mid-1990's as it does 

in the 1993 GRI baseline projection (Woods, 1993). Most 

of the decline in associated gas production in the 1970's 

perception sensitivity occurs in the Southwest. 

The less conventional comparison is quite surprising 

(table 6). Despite the absence of coalbed methane, less 

conventional gas production increases, even under the 

1970 industry resource perceptions and without further 

technology advances. This is mostly due to increased 

shale production. Because of its location in the net importing end-use regions, wellhead prices for gas production from shales are about 40 to 50 cents per MMBtu 

higher than in the Southwest (Woods, 1993). Thus, location can affect the profitability of shale production about 

as much as the advances in technology and practice after 

1990 under conditions of low-to-modest gas prices. 

Table 6. Gas production from the lower 48 States allocated by gas resource category. 

[ --. no data; 93 GRI, 1993 edition of the Gas Research Institute baseline projection (Woods, 1993)] 

1991 2000 2010 

93 GRI 1970 93 GRI 1970 93 GRI 1970 

Category perceptions perceptions perceptions perceptions perceptions perceptions 

(Tel) (Tcf) (Tcf) (Tcf) (Tcf) (Tcf) 

Conventional: 

High penneability -------- 12.1 12.8 12.9 8.9 13.5 7.Q 

Associated ----------------- 2.5 2.5 2.3 1.7 2.6 1.4 

Low penneability --------- 1.7 1.3 1.7 1.2 2.0 1.4 

Unconventional: 

Coalbed methane --------- .3 1.4 1.2 

Devonian shale------------ .2 .2 .5 .4 1.0 .8 

Total ------------------ 16.8 16.8 18.8 12.2 20.4 10.6 
HOW ULTIMATE IS ULTIMATE GAS RECOVERY? 875 

CONCLUSIONS 

Supply projections based on resource depletion should 

be seen as inherently conservative. At best, they may only 

have utility for about a 20-year projection period; over 

that period, they may still overstate the upward pressures 

on gas prices. Extending a resource depletion model past 

20 years, without taking into account the effects of expanding industry resource perceptions, leads to erroneous 

expectations of rapidly declining gas production and rapidly increasing gas prices. 

Removal of post-1970 perceptions. from the resource 

used in the 1993 edition of the GRI baseline projection 

(Woods, 1993) indicates that post- I 970 perceptions have 

their most visible effects on gas supply from the lower 48 

States after 1991. Most gas-reserve additions between 

1970 and 1990 were from resources within the industry's 

I 970 perceptions. The major impact of the expanded perceptions resource since 1970 was to reduce the upward 

pressures on gas prices. After 1990, the post-1970 perceptions resource is critical to both maintaining or increasing 

production from the lower 48 States and reducing the upward pressures on gas prices. Without the post-1970 resource perceptions, the pessimism during the 1970's toward future gas production from the lower 48 States and 

gas prices would still be justifiable. 

Historical experience demonstrates that the industry 

activity expands its resource perceptions and thus estimates of ultimate recovery as much or more as this activity depletes the resource base estimated under its current 

perceptions. Therefore, estimates of ultimate gas recovery 

should be seen as more akin to proved reserves, although 

on a longer time horizon. Just as proved reserves generally 

indicate only the aggregate recovery expected from known 

fields using current industry investment, ultimate gas recovery should be seen only as the aggregate recovery expected in the future using current industry perceptions. As 

more investment is made in known fields, proved reserves 

in these fields increase. Similarly, as industry activity continues, industry perceptions of the resource expand and, 

with it, the expectations of ultimate gas recovery expand. 

Although the dynamic of industry perceptions indicates that estimates of the resource potential made in the 

future will probably exceed current estimates of the resource potential, it should be recognized that the oil and 

gas industry only explores for what it believes to be realistic targets. For example, the industry did not believe 

the Permian Basin or East Texas had much potential 

until discoveries began to be made. Therefore, until sufficient discoveries or convincing arguments were made, 

the industry did not explore these areas. However, the 

experience of the industry demonstrates conclusively 

that someone will go into areas that were classified as 

nonproductive and find new resources. It is reasonable to 

expect that some currently unexplored sediments or regions will be productive in the future, provided they can 

be explored. 

REFERENCES CITED 

Enron, 1991, Enron Corporation's outlook for natural gas, fueling 

the future into the 21st Century: Houston, Texas, Enton Corporation, p. 8. 

National Petroleum Council, 1972, U.S. energy outlook: Washington, D.C., National Petroleum Council, p. 91. 

---1992, The potential for natural gas in the United -States, 

executive summary: Washington, D.C., National Petroleum 

Council, p. 5. 

Potential Gas Committee, 1990, Potential supply of natural gas in 

the United States (December 31, 1990): Colorado School of 

Mines, Golden, Colorado, 169 p. 

U.S. Department of Energy, Energy Information Administration, 

1990, The domestic oil and gas resource base; supporting 

analysis for the National Energy Strategy: Washington, D.C., 

U.S. Department of Energy, Energy Information Administration, SRINES/90-05, p. xii. -

U.S. Department of Energy, Office of Policy, Planning, and Analysis, 1988, An assessment of the natural gas resource base in 

the United States: Washington, D.C., U.S. Department of Energy, DOE/W/31109-H, 126 p. 

Woods, T. J., 1993, The long-term trends in U.S. gas supply and 

prices-1993 edition of the Gas Research Institute baseline 

projection of U.S. energy supply and demand to 2010: Chicago, Gas Research Institute, 92 p. 

THE FUTURE OF ENERGY GASES 

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1570 

The Gas Gap: Uncertainty in the Supply of Natural Gas 

By David G. Howell1

, Katryn Wiese2, and Jonathan Swinchatt3 

CONTENTS 

Abstract ......................................................................... 877 

Introduction ................................................................... 877 

Forecasts ....................................................................... 878 

Peter McCabe ......................................................... 878 

National Petroleum Council (NPC) ....................... 879 

Department Of Energy (DOE) ............................... 879 

Robert A. Hefner III .............................................. 880 

Jesse Ausubel ......................................................... 880 

Bill Dillon .............................................................. 880 

Implications for the Future of Natural Gas .................. 880 

Conclusions .. .... ... .. . ... . ... ... .. ............. .... . ... .... ...... ..... ....... 883 

References Cited ........................................................... 883 

ABSTRACT 

Despite numerous attempts to predict future trends, 

uncertainty exists in the supply of natural gas. Forecasts of 

natural-gas resources have been made by many people, 

from scientists to economists, on the basis of historical 

trends, trade deficits, domestic economies, environmental 

concerns, and the pace of technology. Comparison of past 

forecasts with present trends, however, shows the difficulty in hitting the mark, in properly pinning down the fluctuations inherent in a multifaceted field. Nonetheless, 

optimism prevails in many of the forecasts. A guarded appreciation of what these forecasts. really tell us can help us 

1

U.S. Geological Survey, 345 Middlefield Rd., MS 902, Menlo 

Park, CA 94025. 2u.s. Geological Survey, 345 Middlefield Rd., MS 999, Menlo 

Park, CA 94025. 3Earth Vision, Inc., 52 Cook Hill Rd., Cheshire, CT 06410. 

develop wise energy policies and constructively influence 

the future. of natural gas. 

INTRODUCTION 

In October of 1992, the U.S. Geological Survey (USGS) 

held a conference in Palo Alto, California on The Future of 

Energy Gases. The 75 attendees included petroleum geologists, geochemists, microbiologists, economists, engineers, 

geophysicists, efficiency experts, energy historians, and 

explorationists. Representatives came from institutes, universities, consulting firms, government laboratories, and 

both major and independent oil and gas companies. The 

meeting included presentations and discussions on the origin 

and habitat of energy gases, domestic and world resource 

potential, a brief history of the use of natural gas, the economics of energy systems, the interplay of efficiency and 

demand in energy systems, and the potential role of hydrogen as a fuel for the future. This volume is an outgrowth of 

that conference. 

On the final day of the conference, a group discussion 

focused on forecasting natural-gas consumption for the 

United States through the year 2100 (fig. I). Many forecasts 

project consumption that greatly exceeds the availability of 

natural gas as presently estimated by organizations such as 

the U.S. Geological Survey, the Department of Energy 

(DOE), and the National Petroleum Council (NPC). We call 

this difference between consumption forecasts and estimates of the gas supply the gas gap. 

These energy-use forecasts are only speculations, but 

the higher forecasts represent hunches based on considerable 

experience and insight or extensions of historical trends. 

These trends show a clear pattern of market penetration of 

successively more versatile, more efficient, and cleaner 

fuels-that is, a progression from wood to coal, from coal to 

oil, and now, apparently, from oil to n_atural gas. 

877 
878 THE FUTURE OF ENERGY GASES 

c 

Q 

., 40 s "' 

~ 8 

~ .,. 

e 30 

-; " 

c 

~ 

Q 

c 

~ 20 

~ 

~ 

~ 

:0 

" ~ 

c 

~ 10 

~ 

1900 1925 1950 1975 1990 2000 2025 2050 2075 2100 

Figure 1. Trillion cubic feet (approximately equivalent to 1 QUAD or 1015 British 

thermal units) of natural-gas consumption in the United States per year for 1900 to 

2100. Heavy line denotes historical trend from 1950 to 1990 (ending with vertical 

dashed line at 1990). Lighter lines are various forecasts for consumption to 2100. 

National Petroleum Council (NPC) curves represent total resources available under 

various price scenarios, as labeled. MMBtu, million British Thermal Units; DOE, 

Department of Energy. See text for description of parameters affecting each curve. 

If demand for natural gas rises, and resources remain 

at the level predicted by present estimates, by the lat~er 

half of the next century we would be dependent on imported natural gas just as we now depend on imported oil. 

This scenario would likely entail the arrival on our shores 

each year of some 1,000 liquefied natural gas tankers, with 

the accompanying risks of accidents and potentially catastrophic explosions. However, resource estimates are often 

inaccurate, and the next few decades may bring significant 

growth in the natural-gas resource base that will result 

from new understanding and new technologies. Nevertheless, geologists seem to be reasonably confident concerning the accuracy of forecasts for associated, conventional 

methane resources and the more common types of unconventional sources of natural gas. Guarded optimism for extending the resource base exists only for deep gas 

resources (see Dyman and others; Wyman, this volume) 

and methane hydrates (see Kvenvolden; Collett; Dillon; 

this volume). _ 

Perhaps the clearest statement that we can m~ke now 

about our energy future is that it appears uncertain. Uncertainties exist in choosing the best mix of fuels for today, in 

planning for a long-term sustainable energy mix for the 

future, in estimating fuel supplies, and in determining the 

long-term environmental effects of any choice. Given these 

uncertainties, it seems prudent to examine our alternatives 

as carefully as possible. Therefore, we present several natural-gas consumption forecasts herein. These forecasts 

(shown in fig. 1) and the explanations provided are intended 

to stimulate new thinking and innovative approaches that are 

vital to finding a viable solution to global energy needs. 

FORECASTS 

PETER McCABE 

This forecast is best explained as a predicted reaction 

to technological advances which the future may bring and 

can be des<;;ribed using the following periods of time. Peter 

McCabe works for the U.S. Geological Survey. 

1990-2000: The consumption of natural gas will grow 

steadily because· of lower gas prices and environmental 

concerns. Demand for electricity will increase and interest 

in alternative-fuel (mainly electrical and natural gas) vehicles will grow. Perhaps 10 percent of all vehicles will use 

alternate fuels by the year 2000. Consumption of natural 

gas at the end of the decade may equal the high rates of 

consumption of the mid-1970's. Much of the increase in 

supply needed to satisfy increased consumption in the 

Vnited States will come from Alberta, where huge untapped· resources will allow lower production costs and 

guaranteed long-term supplies. Coal use in power generation will continue to grow but at a slower pace than during 

the past 20 years. Oil consumption will fall somewhat during the decade. 

2000-2010: The introduction of low-cost superconductors will allow efficient transportation of electricity and 

a dramatic drop in fuel consumption by utility companies. 

Electricity will be more widely used for home heating 

leading to a decrease in demand for natural gas. Electrical 

vehicles-cheaper, safer, and cleaner than natural gaswill become common. The net result will be perhaps a 10 
THE GAS GAP: UNCERTAINTY IN THE SUPPLY OF NATURAL GAS 879 

percent per year drop in demand for natural gas, oil, and 

coal throughout much of the decade. 

2010-2020: Demand for electricity will grow substantially, as a result of more homes converting to electric 

heat. Super batteries will allow all vehicles to be electrical 

resulting in a dramatic fall in oil consumption. The increase in demand for electricity will lead an increase in 

demand for natural gas to fuel some reopened gas-fired 

powerplants. Natural gas will remain cheap because of excess supply over demand. There will be little interest in 

re-opening coal-fired plants for environmental reasons, and 

because natural gas is now cheaper than coal on a Btu 

(British thermal unit) basis. A significant percentage of 

new power generation will be from new solar and nuclear 

technologies. 

2020-2030: The beginning of the decade will see legislation restricting the use of petroleum-powered vehicles 

to museums and registered collectors. Old powerplants 

will be replaced gradually by new solar and nuclear 

plants; this gradual replacement will result in a sharp decline in the demand for coal and natural gas. 

2030-2035: The .last coal and natural gas electrical 

plants will close. There will be limited production of oil 

and coal for the manufacture of plastics and lubricants. 

There will be little, if any, use for natural gas. 

NATIONAL PETROLEUM COUNCIL (NPC) 

The NPC forecasts in figure I assume consumption of a 

domestic resource of approximately 1,300 Tcf (trillion cubic 

feet) of natural gas, the most re.cent NPC resource estimate 

for the conterminous United States (Gautier and Brown, this 

volume). Exploitation of this resource assumes price increases ranging from a low of$ I .50 per Mcf (thousand cubic 

feet) to an unspecified cost over $3.50 per Mcf. Of the 

estimated 1,300 Tcf, roughly 600 Tcf come from proved 

reserves and conventional sources, 500 Tcf come from nonconventional sources such as coalbed methane, shales, and 

tight sands, and at least 200 Tcf will result from field growth, 

where ultimate recovery is greater than initial forecasts. 

Field growth results from development of new technologies, 

more closely spaced drilling, and deeper drilling (Oil and 

Gas Journal, I 992; Root and Attanasi, this volume). 

In addition to domestic supplies of natural gas, Canadian imports will increase, reaching 3 Tcf per year or more, 

while liquefied natural gas imports will remain low. Development of the Alaskan North Slope natural-gas resources 

or northern frontier natural gas in Canada will not occur 

prior to 2010 because of inadequate economic incentive. 

The NPC estimates that resources for Canada and Alaska 

are 740 Tcf and 180 Tcf, respectively. "Sound management, operational mechanisms, contract diversity, and use 

of financial markets can work together to manage risk and 

reduce the short-term volatility that is likely to occur as the 

industry moves through transitional phases." Despite 

doubts about natural-gas deliverability during peak demand, NPC recommends "federal, state, and local officials 

allow competitive market forces to continue to develop and 

work, J&racticing restraint, especially during periods of 

price and supply volatility, as the industry adjusts to the 

changing marketplace." (Oil and Gas Journal, 1992). 

DEPARTMENT OF ENERGY (DOE) 

Expectations of the DOE in response to NPC estimate 

and supposed future discoveries are shown in figure 2. The 

NPC total of I ,300 Tcf will be supplemented by Western 

Canada reserves and Algerian liquefied natural gas imports 

50r-------------------------------------------------------. 

0 = 

., 

"" 40 E

~ 

= 8 

~ .. 

~ 30 , 

~ " = 

0 

c 

e 20 -.: 

~ 

v 

:0 

a 

c 

~ 10 

;!: 

1900 1925 

Natural-gas imports 

(conventional sources) 

from Western Canada, 

Mexico, and Algeria 

70Tcf 

IIIIIl 

1950 1975 1990 2000 

Unconventional natural gas from 

tight sand. shale, and coal 

375 Tcf 

2025 

Sustained level of supply 

2050 

"23 Tcf/yr 

Expanded 

impons and ? speculative 

resources and 

symhelic gas 

2015 2100 

Figure 2. Natural-gas supply outlook (modified from Department of Energy, 1991), 

from 1900 to 2100, in trillion cubic feet of gas consumption per year. 
880 THE RJTURE OF ENERGY GASES 

(35 Tcf) plus additional reserves from tight-gas resources 

(70 Tcf). To maintain present rate of use (approximately 23 

Tcf per year), particularly beyond the year 2050, natural gas 

from other sources will be necessary. These other sources 

include deep gas, gas hydrates, and increased imports. 

ROBERT A. HEFNER III 

The future consumption of natural gas is based on the 

assumed benefits that increased use of natural gas will 

have on our economy (see Hefner, this volume), as described by Robert A. Hefner III from The GHK Company. 

Natural gas will provide for energy needs well into the 

21st century when it will be overtaken by a combination of 

solar electricity and synthetic hydrogen gas (see Veziroglu 

and Barbir, this volume). This forecast assumes that all tax 

credits and subsidies are removed. Additionally, Hefner assumes that some form of an energy or carbon tax will be 

emplaced to internalize costs of environmental remediation, that is, make these costs an integral part of the fuel 

price. With these conditions, fuel use will be controlled by 

economic principles. At present, 76 percent of our Nation's 

trade deficit comes from importing oil. To convert this 

huge deficit to a potential asset, Hefner argues that we 

must develop domestic production of natural gas. Once domestic production of natural gas increases, and imports of 

oil decrease, the natural gas industry in the United States 

will boom, much like the oil industry in the 1930's, 1940's, 

and 1950's. New thinking, new technologies, and new 

drilling will lead to increased supplies. 

JESSE AUSUBEL 

The Ausubel forecast (fig. 1) is best explained by the 

necessary reaction to growing environmental concerns, 

combined with a continued growth of the natural gas resource base. Jesse Ausubel is presently employed at Rockefeller University. 

Almost all of the increase in energy consumption in 

the United States over the next 50 years will come from 

natural gas. After that, noncarbon energy sources, whether 

nuclear (fission or fusion) or solar, will substitute for carbon energy sources; this substitution will be driven by environmental concerns and economies the new sources may 

provide. Several authorities, including the NPC and DOE, 

already project remaining natural-gas reserves of the lower 

48 States to be in the range of 1,000 to 1,500 Tcf. Much 

of this is now recoverable at $3 to $4 per Mcf (Woods, 

1992). Better reservoir characterization and improved 

techniques for exploration, development, and well stimulation in conventional sources as well as advances in the 

areas of unconventional sources will further expand the 

U.S. natural-gas resource base. Looking more broadly at 

potential North American supplies, estimates suggest that 

3,000 Tcf deep gas and almost as much gas hydrate might 

be available (Hanneman, 1988). The rate of growth of the 

gas-supply system will be about the same from 2000 to 

2050 as it was between 1945 and 1970. This system will 

provide a reliable, steady domestic supply of at least 4,000 

Tcf (total) for the United States; securing these supplies is 

an attainable goal. This scenario is consistent with global 

energy scenarios in which 25,000 Tcf (or more) of natural 

gas are used eventually (Ausubel and others, 1988). 

BILL DILLON 

This forecast for natural-gas consumption is founded 

primarily on historical trends, which in tum reflect advances in technology. Bill Dillon works for the U.S. Geological Survey. 

History suggests near-term changes probably will be 

small, but long-term changes, controlled by developing 

technologies, probably will be large. History often proves 

to be a good guide. Extremely large amounts of natural gas 

are present in gas hydrates and other unconventional reservoirs, particularly deep-gas and tight-gas reservoirs. Technology will develop to allow use of some of these resources 

at moderate cost. History shows peak and decline patterns 

for other energy sources (fig. 3) and a similar pattern is 

anticipated for natural gas, if unconventional resources are 

developed. The peak and decline pattern reflects the development of new energy sources rather than the disappearance of old ones. We have not run out of wood or coal, but 

we have shifted focus to oil and natural gas. 

IMPLICATIONS FOR THE FUTURE OF 

NATURAL GAS 

These diverse forecasts reveal significant uncertainty 

concerning the future of natural gas. This uncertainty suggests that we do not have enough information yet to predict natural-gas usage with much accuracy, even over 

short periods. Forecasts made in 1985, for instance, based 

on expected prices of oil and the resulting change in demand for natural gas (fig. 4), so far have proved to be far 

lower than actual usage. 

Projections of oil prices from 1990 to 2020 (fig. 5) 

indicate that forecasters tend to base their projections on 

the price of the day and assume a continued rise from that 

point. Yet the curve showing past prices (fig. 5) vividly 

shows the unpredicted dip in oil prices during the 1980's 

that has had such a devastating effect on the U.S. petroleum industry. The evidence suggests that our forecasts of 

energy availability, demand, and use are seriously flawed, 

yet both government and business policies are frequently 

based on these predictions. 
THE GAS GAP: UNCERTAINTY IN THE SUPPLY OF NATURAL GAS 

100 

= 

·~ 

e "' 80 

= 

~ 

e 

;; 

.: 

<li 

;;i 60 

;; 

£ 

'o 

:'. 

s .j{) = 

~ 

!!. 

,., 

.Q 

~ 

= 20 ~ 

] 

"' 

1900 1925 1950 JQ75 1990 2000 2025 2050 2075 2100 

Figure 3. Historical trends for fuel consumption in percentage of total energy consumption per year from 1900 to 2100 (thick lines) compared with actual variations 

(thin lines). Each curve represents consumption for a different type of fuel, as labeled. Modified from Marchetti and Nakicenovic (1979). 

881 

100 -r--------------------------------~ 

.5 

"'C' 22 "'u 

~s 21 

~~ 

= "' 20 'O:C 

g E tfJ 

~.§ 

H 18 cr--

8 17 

16 

15 L---~----~--~L---~----~--~-----L----~ 

1970 l(J7.1 1no 1985 1990 1995 2000 2005 2010 

Figure 4. Consumption of natural gas per year in trillion cubic 

feet from 1970 to 2010. Historical trend (actual variation) is 

compared to various forecast models made under different economic constraints, including the price of oil, the amount of resource available, and the level of demand. Modified from Energy 

Modeling Forum (1989). 

80 -

'E 

a 60-

~ 

.5 

=s 

..... 

0 40 

20 

0 

1970 

July 1983 

January 1985 

1980 1990 2000 2010 2020 

Figure 5. Crude-oil prices in 1990 dollars per barrel from 1970 

to 2020; Historical trend (actual variation) is compared to various forecasts made in succeeding years from 1981 to 1991. 

Copyright by OPEC, 1991. Used with permission. 
882 THE FUTURE OF ENERGY GASES 

The energy-use curves of figure 3 are a group of 

smooth lines that suggest resource estimation should be a 

straightforward task. B~t these long-wavelength curves 

hide significant short-term variations that exists within the 

historical trends. Short-term fluctuations reflect the influence of economic factors, national politics, energy policy, 

international relationships, environmental concerns, and 

. business cycles on the supply and demand of resources. 

Even though the long-term trend may be toward natural gas 

as a primary or dominant energy source, the necessity to 

make choices, devise policy, and reconcile differences 

among various, and sometimes competing, interests result 

in short-term fluctuations. Resource estimates are conditioned by assumptions and beliefs that reflect the mix of 

diverse views that exist at any one time. Lit~le surprise that 

they almost always prove to be inaccurate. 

The historical trends shown in figure 3 may well be 

more consistent predictors of long-term usage than forecasts that inevitably reflect the influences of short-term factors. These curves represent a series of transitions from 

wood to coal to oil and, now, to natural gas. The energy 

substitutions depicted seem to be dependent on market 

forces and societal needs rather than supply; use of natural 

gas, for example, is increasing worldwide even at a time 

when oil, coal, and even locally wood supplies are abundant. These curves smooth out the unpredictable short-term 

fluctuations and reveal longer term, more regular variation. 

So we have long-term trends within which exist shortterm fluctuations-the noise, perhaps, within the smoother 

signals. We live within the noise, and our resource estimates reflect the dissonant input provided by the diverse 

and varied influences that make up that noise. Perhaps we 

should spend less time making estimates and predictions, 

and exert more effort trying to understand the economic, 

political, and psychological factors that underlie short-term 

fluctuations of energy use. Though we will not analyze 

these influences in significant detail here, we will mention 

some that seem particularly important to understanding the 

future of natural gas. 

Potential increase of methane use in the future probably will be concentrated in the energy-use sectors that 

presently show least penetration by natural gas-generation of electricity and transportation. Of these, power generation is the sector that natural gas could penetrate most 

rapidly. 

Natural-gas-powered electrical generation plants are 

less expensive to build, maintain, and operate than alternatives such as coal-fired and nuclear plants. On the basis of 

individual components, natural-gas plants can be built for 

one-third the capital investment needed for nuclear plants 

and one-half the investment needed for coal plants, whereas costs of operation and maintenance are less than onesixth and one-quarter respectively (The Economist, 1992). 

Though the cost of natural gas is greater than coal or 

nuclear fuels, environmental problems are significantly 

less. Natural gas produces less S02, no particulates and no 

trace metals, fewer nitrous oxides, and no radioactive 

waste. Now that the ban on natural-gas use for electrical 

generation has been scrapped, " ... combined cycle gas turbines allow plants to be built in smaller units, at lower 

costs, requiring less maintenance and fewer staff, and generating power at higher levels of efficiency than ever before."(The Economist, 1992) . 

For these reasons, electrical power utilities are interested in the future of natural gas. But utilities are also 

mandated by regulatory guidelines to guarantee a continuous and adequate supply of electricity. To accomplish this 

with natural gas, utilities must be guaranteed a long-term 

(20 year), uninterrupted fuel supply. Many companies 

seem to lack confidence in the long-term supplies of natural gas. This becomes particularly poignant in the light of 

a supply of coal that is projected to last for hundreds of 

years at existing (low) prices. But price comparisons at the 

moment are tenuous, as the impact of an energy tax is 

unclear. A Btu tax, for instance, will increase the price of 

coal disproportionately because the current low price will 

show a greater percentage increase than will occur for natural gas. Coal also has high transportation costs that will 

increase as a result of energy taxes. 

As with all energy use, environmental side effects accompany the increased use of natural gas. One of these 

seldom considered is the need to drill a large number of 

new wells. In 1972, at the peak of domestic natural gas 

production, 5,000 new development and 120,000 production wells were needed to produce 22 Tcf of natural gas. 

At that time, the United States maintained a reserve (proven ready supply) of natural gas of nearly 200 Tcf, about a 

15-year supply. In the ensuing years, this supply began to 

erode. Worry about the dwindling supply, combined with 

rising prices that tracked with oil, resulted in an exploration boom. At the peak of activity, in 1982, nearly 700 

wildcat and 17,000 development wells were drilled, for a 

total of 210,000 production wells in operation. Vigorous 

exploration and restriction of use by government regulation created an oversupply at a time of global recession; 

these events resulted in a phenomenon called the "gas 

bubble." This bubble began deflating, as prices plummeted, and exploration declined dramatically. By 1991, roughly 100 exploration and 7,700 development wells were 

being drilled each year and these numbers will likely fall 

further in 1993 as all the incentives are dropped for unconventional gas resources. To increase supply by 25 percent, as many as 300,000 to 400,000 production wells will 

need to be in operation. This will require 20,000 to 30,000 

new development wells and several thousand wildcat exploration wells each year. Some of these wells will need to 

be located in areas in which development will raise the ire 

of environmentalists. 

One of the potential benefits of a move to natural gas 

would be to create a fuel mix that would be less reliant on 
THE GAS GAP: UNCERTAINTY IN THE SUPPLY OF NATURAL GAS 883 

foreign sources. At the present time, 50 percent or more of 

the U.S. oil supply arrives from overseas-the result is a 

huge flow of capital in the opposite direction. This outflow 

of capital is the largest contributor to U.S. trade imbalances. Our dependence on foreign sources located mainly in 

areas of significant political instability contributes to additional expenses incurred attempting to keep these supplies 

relatively secure. Robert Hefner estimates that 76 percent 

of our trade deficit is associated with the importation of 

oil. If a secure, domestic energy supply is important to the 

economic future of the United States, natural gas is the 

only fuel that could provide a bridge to more benign, nonhydrocarbon energy sources that may well be needed to 

maintain an environment that will provide for long-term 

sustenance of human life. 

Ultimately, domestic natural-gas supplies will decline. 

At present rates of use, conservative estimates suggest that 

this will not occur for at least 75 years. At double the 

present rate of use, and knowing that resource estimates 

are always low, it seems safe to say that domestic naturalgas resources are sufficient for at least 50 years. This 

seems enough time to develop the next energy technology. 

Though some people fear to depend on human ingenuity 

and assumptions of new technology for solutions to problems of the not distant future, others are less pessimistic. 

Buckminster Fuller maintained that the crisis of the 1970's 

was not one of energy, but one of human imagination. 

Teilhard de Chardin (1955) wrote, "One day, though substitutes may be found, we shall have exhausted our mines 

and oilwells. But to all appearances nothing on Earth will 

saturate our desire for knowledge or exhaust our power for 

invention." Perhaps Peter McCabe's predictions will prove 

accurate, and technological advances will reduce the use 

of natural gas in the near future. Conversely, technology 

may decrease the cost of drilling and bring deep gas and 

gas hydrates into production; this scenario would provide 

natural-gas resources for many decades longer than now 

seems possible. 

Though electricity may eventually replace natural-gas 

use in homes, offices, and industry, for some time natural 

gas will provide the fuel to run the electrical generation 

plants. Natural gas will also play an increasing role in the 

transportation industry, especially in air transportation 

where it will pave the way for synthetic gaseous fuels 

(such as hydrogen) in the more distant future. 

CONCLUSIONS 

Western scientific societies tend to believe that the future can be predicted, to some degree, through detailed 

analyses such as the estimation of energy resources and 

prediction of energy usage. We base many decisions on 

our faith in the validity of this process. Yet in the long 

term we see that this process frequently misleads us, and 

provides, at best, an unsure footing and infirm foundation 

for policymaking. Perhaps we need to view our predictions and estimates with less rigidity and recognize that 

they will change drastically over time. A more flexible 

view might lead us to a greater array of options, and it 

might give us greater ability to shift emphasis and focus 

when necessary. 

In forecasting supplies, the difference between the inherent conservatism of science and the intrinsic vision of 

exploration is apparent. In her fascinating book abo~t oil 

exploration, Ruth Sheldon Knowles comments, "The 

doodlebugger expressed no doubts as to his ability to find 

oil. The geologist qualified every belief with "perhaps," 

"might," or "it is logical to believe." Passionate advocates 

and determined mavericks whose faith propels them into 

new ventures provide balance for the thorough analysts 

and innovative researchers who move more slowly. Someday we may accept that neither one nor the other seems to 

have the answers that will prove correct in the long term, 

and that the course of history follows a path that is not 

easily predicted. 

But we do have to make plans and devise policy, invent and innovate, drive our cars, and heat our homes. We 

continue to live within the noise of short-term fluctuations 

and will, no doubt, continue to try to predict the future. 

Though we will probably always be inaccurate, endeavors 

such as these provide the energy, incentive, and motivation 

for solving problems and, hopefully, bettering our world. 

We need to remember, however, that the future is not created by predictions and estimates, it is created by those 

who find the next natural-gas field, invent the next technology, bring forth the new idea that leads to future possibilities. We hope "The Future of Energy Gases" contributes 

to these endeavors. 

REFERENCES CITED 

Oil and Gas Journal, 1992, NPC: Natural gas potential not yet 

fully realized in U.S.: Oil and Gas Journal, December 28, 

p. 106. 

The Economist, 1992, Nuclear Power: The Economist, October 

21, p. 21-24. 

Ausubel., J.H., Gruebler, A., Nakicenovic, N., 1988, Carbon dioxide emissions in a methane economy: Climatic Change, 

v. 12, no. 3,p. 245-264. 

Department of Energy, 1991, Natural gas strategic plan and 

multi-year program crosscut plan, FX 1993-1998: DOE report DOEIFE-0251P, 230 p. 

Energy Modeling Forum (EMF), Stanford University, 1989, 

North American Natural Gas Markets: EMF Report 9, v. 2, 

February, 142 p. 

Hanneman, R.E., 1988, Methane technology: a technical survey, 

in Lee, T.H., Linden, H.R., Dreyfus, D.A., Vasko, T. (eds.), 

The Methane Age, p. 109-119. 
884 THE FUTURE OF ENERGY GASES 

Knowles, R.S., 1959, The greatest gamblers, Norman, Oklahoma, 

University of Oklahoma Press, 376 p. 

Marchetti, C., and Nakicenovic, N., 1979, The dynamics of energy systems and the logistic substitution model: RR-79-13, 

International Institute for Applied Systems Analysis 

(IIASA), Laxenburg, Austria. 

Woods, T.J., 1992, The long-term trends in U.S. gas supply and 

prices: 1991 editions of.the GRI baseline projection of U.S. 

energy supply and demand to 2010. NPC says gas supply 

adequate but report is· challenged: Natural Gas Week, v. 8, 

no. 44, November 2, p. 7-8. 
APPENDIX 
886 

500 

400 

c 

·;: 300 Q; 

"' 200 

., 100 

"iii " 

a; 

0 

· 1 00 

· 200 

· 300 

·460 

100 

a; 10 ~ 

u 

:;; 

" u 

c 

-~ 

~ 

0.1 

1000 

c 

< 100 ::> 

e. 

iii " 

c 

~ ·;: 

"" 10 "' 0 " 

l/ 

· 360 

I/ 

v 

THE FUTURE OF ENERGY GASES 

Temperature Conversions 

·260 ·160 . 60 40 14 0 240 340 440 540 

Fahrenheit 1--- Celsius --o-- Ke lvin 

Volumetric Conversion 

v 

vi 

1.---.Y 

I 

I 'II I i I 

1 0 100 10 00 10000 

Billion cubic meters 

Approximate conversions using average fuel densities 

. 

/ 

v 

i v v v 

v I 

I I II 

l I II 10 100 1000 

Trillion cubic feet (Tel) of natural gas 
100 

"' ~ 10 

Q; 

Cl) 

u. 

:c " 

:I 

0 

c 

< 

::;) 

~ 

:I 

iii 

.!! " 

~ .. 

:I 

0 

0.1 

0.01 

0.001 

0.01 

1000 

100 

10 

0.1 

0.01 

0.001 

0.0001 

/ 

APPENDIX 887 

Approximate conversions using average fuel densities 

• 

0.1 10 100 1000 10000 

Metric tonnes of hard coal 

Approximate conversions using average fuel densities 

v ! 

I v 

I / I 

/ 

v 

0.001 0.01 0.1 10 100 1000 

Billion barrels of crude oil 
888 

.. 

.. 

"' 

~ ::> 

1; 

" 

0 

u 

~ 

a; 

.!! 

:;; "

::> 

" ., 

.. " .. 

::> 

0 

.t: 

.... 

-~ " 

-c 

.. 

::> 

0 

1 00000 

10000 

100 0 

10 0 

/ 1 0 

10 

0.1 

0.01 

0.001 

0.01 

THE FUTURE OF ENERGY GASES 

Approximate conversions using average fuel densities 

I / ' 

I v 

v I 

I I I II 

10 100 1000 10000 100000 

Barrels of crude oil 

Approximate conversions using average fuel densities 

0.1 10 100 1000 10000 

Metric tonnes of hard coal 
APPENDIX 889 

POWER (energy/time) 

watt kilowatt Btu/hour ft·lb/sec horsepower calorie/sec 

1 watt = 1 joule/sec = w-3 3.413 0.7376 1.341 xl0-3 0.2388 

1 kilowatt= 1000 1 3413 737.6 1.341 238.8 

1 Btu/hour= 0.293 2.93x1o-4 1 0.2161 3.929xlo-4 6.998xlo-2 

I ft·lb/sec = 1.356 1.356x1o-3 4.628 I 1.818xl0-3 0.3239 

1 horsepower = 745.7 0.7457 2545 550 1 178.1 

I calorie/sec = 4.187 4.187x10-3 14.29 3.088 5.615x1o-3 

MASS 

gram kilogram ounce pound short ton metric ton long ton 

I gram = w-3 3.527xlo-2 2.205xl0-3 1.102xl0-6 10-6 9.80xi0-7 

1 kilogram= 1000 1 35.27 2.205 1.102x10-3 10-3 9.80xlo-4 

1 ounce= 28.35 2.835x10-2 6.250xl0-2 3.125xl0-5 2.83xl0-5 2.79xl0-5 

I pound= 453.6 0.4536.2 16 I 5x10-4 4.55xl0-4 4.46xl0-4 

1 short ton (American) = 9.07xl05 907 3.2xl04 2000 1 0.907 0.893 

1 metric ton = 106 1000 3.53x104 2.20x103 1.102 1 0.980 

1 long ton (Imperial) = 1.02x106 1020 3.58xl04 2.24xJ03 1.12 1.02 

APPROXIMATE CALORIC EQUIVALENTS (based on average densities for various fuels) 

Mcf gas barrels short tons short tons barrels barrels short tons Btu 

crude oil bit. coal anth. coal gasoline res. fuel oil wood 

1 000 cubic feet (Mcf) natural gas = 1 0.178 0.0431 0.0406 0.196 0.164 0.0617 1.031x106 

I barrel crude oil = 5.618 I 0.243 0.228 1.105 0.923 0.347 5.800x106 

1 short ton bituminous coal and lignite= 23.20 4.115 1 0.941 4.554 3.802 1.43 23.9x106 

I short ton anthracite= 24.631 4.386 1.0627 4.840 4.04 1.52 25.4x106 

1 barrel of gasoline= 5.102 0.905 0.220 0.207 1 0.835 0.314 5.248x106 

I barrel residual fuel oil = 6.098 1.083 0.263 0.2475 1.198 1 0.376 6.287x106 

I short ton wood = 16.21 2.88 0.699 0.658 3.18 2.66 1 1.67x107 

Value Metric Prefix American English 

103 kilo(k) thousand (M) thousand 

106 mega(M) million (MM) million 

109 giga(G) billion (B) thousand million 

1012 tera(T) trillion (T) billion 

1015 peca(P) quadrillion (Q) thousand billion 

1018 exa (E) quintillion trillion 
ENERGY (work, heat) 

Btu QUAD erg joule 

1 Btu = 1 10.15 1.005x1010 1055 

1 QUAD= 1015 I 1.005xi025 1.055x 1018 

1 erg = I dyne/em = 9.481 x10" 11 9.481 x 10·26 I w-7 

* 1 joule= 9.481 x 1 o-4 9.481 xl0" 19 107 1 c 

0 I ft·lb = 1.285x!o·3 1.285 x 10· 18 1.356x107 1.356 

G> 1 horsepower-hour = 2545 2.545x10- 12 2.685x10 13 2.685x106 

0 

< I calorie= 3.969x10·3 3.969xl0- 18 4.187x!07 m 4.187 :Il 1 kilowatthour (kWh) = 3413 3.413x10· 12 3.6x1013 3.6x106 z 

s: 1 electron volt (eV) = 1.519x 10"22 1.519x 10"37 1.602x I o· 12 1.602x!0-19 m 

z 

-l 

-o 

:Il 

z 

-l 

z 

G> 

0 

-n VOLUME -n 

(5 

m 

;;; cubic meter cubic em liter cubic inch <0 

Cf 

.... 

(X) 106 6.102x10 .... 4 I cubic meter = I 1000 "' 0> I cubic centimeter = 10-6 I w-3 6.102x10·2 (X) 

I liter = w-3 1000 1 61.02 

1 cubic inch = 1.639x10·5 I6.39 I.639x!0"2 I 

I cubic foot = 2.82xio·2 2.82xl04 28.2 1728 

I fluid ounce = 2.96x10·5 29.6 0.0296 1.80 

I U.S. gallon = 3.79x10·3 3.79xl03 3.79 231 

1 U.K. imperial gallon = 4.55x10·3 4.55x103 4.55 277.4 

1 U.S. barrel = 0.159 1.59xl05 !59 9.70x103 

ft·lb hp-hour 

777.9 3.929x10·4 

7.779xi0 17 3.929x1011 

7.376x1o·8 3.725x10" 14 

0.7376 3.725x10·7 

I 5.051xl0·7 

1.980xl06 1 

3.088 1.56xl0·6 

2.655xl06 1.341 

1.182x10·19 5.967x I o·26 

cubic foot ounce 

35.3I 3.38xl04 

3.531 x10·5 0.0338 

3.53lxl0·2 33.8 

5.787x10·4 0.552 

1 952 

1.04x10·3 1 

0.134 128 

0.161 154 

5.63 5.38x103 

calorie 

252.0 

2.520xi0 17 

2.388x10"8 

0.2388 

0.3238 

6.413xl05 

I 

8.598x105 

3.826x 1 o·20 

U.S. gallon 

264 

2.64x10·4 

0.264 

4.33x10·3 

7.46 

7.8Ix10·3 

I 

1.20 

42 

kWhour 

2.930x104 

2.930x10 11 

2.778x 10"14 

2.778x1o·7 

3.766x10·7 

0.7457 

1.163x10·6 

1 

4.450x 1 o·26 

U.K. gallon 

220 

220xl0·4 

0.220 

3.60xio·3 

6.21 

6.5lx 10·3 

0.833 

35.0 

eV 

6.585x1021 

6.585x1036 

6.242x1011 

6.242xl018 

8.464x1018 

1.676xl025 

2.614xi019 

2.247xl025 

I 

U.S. barrel 

6.29 

6.29x10·6 

6.29x10·3 

1.03x10·4 

0.178 

1.86x10·4 

2.38xl0·2 

2.86xl0·2 

1 

00 

\0 

0 

>-'l 

iii 

'T1 

c:: 

>-'l 

c:: 

fg 

0 

'T1 

ttl 

z 

ttl 

::>;; 

Cl 

>-<: 

Cl 

> CJl 

m 

CJl