National Energy Resource Issues

Geologic Perspective

and the 

Role of Geologic Information

U.S. GEOLOGICAL SURVEY BULLETIN 18
ABBREVIATIONS

BBO billion barrels of oil

Btu British thermal unit (heat measurement)

EOR enhanced oil recovery

MMS Minerals Management Service

NCRDS National Coal Resources Data System

NSPS new-source performance standards

NURE National Uranium Resource Evaluation

OPEC Organization of Petroleum Exporting Countries

Quad quadrillion Btu

RNSPS revised new-source performance standards

R/P reserve-to-production ratio

TCFG trillions of cubic feet of gas

USGS U.S. Geological Survey

On the Cover: Rocks of the energy-resource-rich 

Mesaverde Group of Cretaceous age. Cliff-forming 

Point Lookout Sandstone is highlighted against a storm 

approaching over the Four Corners region of the Colorado Plateau. (Photograph by Christine TurnerPeterson, U.S. Geological Survey.)
National Energy Resource Issues

Geologic Perspective

and the 

Role of Geologic information

By U.S. GEOLOGICAL SURVEY

U.S. GEOLOGICAL SURVEY BULLETIN 1850
DEPARTMENT OF THE INTERIOR 

DONALD PAUL MODEL, Secretary

U.S. GEOLOGICAL SURVEY 

Dallas L. Peck, Director

UNITED STATES GOVERNMENT PRINTING OFFICE : 1988

For sale by the Books and Open-File Reports Section, U.S. Geological Survey, 

Federal Center, Box 25425, Denver, CO 80225

Library of Congress Cataloging in Publication Data

National energy resource issues.

(U.S. Geological Survey bulletin ; 1850)

Bibliography: p.

Supt. of Docs, no.: I 19.3:1850

1. Power resources United States. 2. Geology, Economic United

States. I. Geological Survey (U.S.) II. Series. 

QE75.B9 no. 1850 557.3s [333.79'11'0973] 87-600368 

[TJ163.25. U6]
CONTENTS

Executive background and overview 1 

Petroleum resources 7 

Global setting 7

Situation and outlook for petroleum resources in the United States 13 

The role of geologic information 17

Focus: Oil and gas resources on wilderness lands, by B.M. Miller 19 

Focus: Frontier petroleum province in the Eastern United States, by

L.M. Pratt 20 

Focus: Magnetic exploration for oil and gas fields, by R.L. Reynolds,

N.S. Fishman, and M.R. Hudson 21

Focus: The Monterey Formation of California, by C.M. Isaacs 23 

Focus: Assessment of petroleum potential in the Arctic National

Wildlife Refuge, Alaska 26 

Coal resources 29

Coal resources and reserves in national perspective 29 

Coal quality as a policy and economic issue 33 

The role of geologic information 34 

National research agenda 35

Focus: Coal resource and reserve characterization in eastern Kentucky,

by J.C. Cobb, Kentucky Geological Survey 36 

Focus: Coal quality and the origins of coals by R.W. Stanton, C.B.

Cecil, P.D. Warwick, and B.S. Pierce 38 

Focus: Coal mine subsidence hazards, by C.R. Dunrud 42 

Focus: Regional availability and economics of coal, by R.L. Bernknopf

and W. D. Watson, Jr. 44 

Focus: Sulfur in coals New insights on the utilization potential of

high-sulfur coals, by Z.S. Altschuler 47 

Higher cost, alternative hydrocarbon resources 50 

Enhanced oil recovery 50

Focus: Geologic studies related to enhanced oil recovery 53 

Heavy oils, by B.L. Crysdale and C.J. Schenk 54 

Tar sands, by B.L. Crysdale and C.J. Schenk 55 

Oil shale, by J.R. Dyni 57

Gas hydrates, by T.S. Collett and K.A. Kvenvolden 62 

Coal-bed methane, by B.E. Law 63 

Tight gas reservoirs 64

Focus: Detailed studies of tight gas reservoirs 66 

Geothermal energy resources, by Marianne Guffanti 67 

Geothermal systems and their distribution 67 

Geothermal energy in the national energy mix 71 

Resource assessment 71 

Geologic research and exploration for hydrothermal resources 71

Focus: Geothermal energy in California 72 

Uranium resources 73

Focus: Surficial uranium deposits, by J.K. Otton 74 

Focus: A new model for uranium mineralization in the San Juan 

basin of New Mexico, by C.E. Turner-Peterson and N.S. 

Fishman 76 

References cited 78

Contents III
J, 
National Energy Resource Issues:

Geologic Perspective and the 

Role of Geologic Information

By U.S. Geological Survey

EXECUTIVE BACKGROUND AND OVERVIEW

Energy resources are a fundamental part of the 

economic strength and stability of the United States, and 

the key resource in today's industrial economy is oil. 

Although several geopolitical and economic factors have 

combined recently to reduce energy prices from their 

former high levels, the world petroleum market for the 

foreseeable future appears likely to be volatile with regard 

to both price and supply. Furthermore, the United States 

is again growing increasingly dependent on imported oil 

and will be strongly affected by swings in the world 

market.

Two-thirds of the energy currently consumed by the 

United States is provided by oil and gas (fig. 1); more than 

one-third of the oil is imported (DeGolyer and MacNaughton, 1986, p. 51). Resource analysts predict that 

domestic oil and gas production will continue to decline 

irreversibly from peak production in the 1970's. Since the 

first quarter of 1986, this decline, driven by falling oil 

prices and the consequent retrenchment of the American 

oil industry, has been quite sharp. Production from existing wells is declining, and stripper wells are being shut in 

and abandoned. New petroleum fields are more difficult 

and expensive to find, and exploration has been seriously 

curtailed. In addition, industry has either slowed or 

stopped research on enhanced oil recovery and the development of alternative higher cost energy resources such 

as oil shale and synthetic liquid fuels from coal. It seems 

inevitable that U.S. dependence on foreign supplies of oil 

will increase.

Long-term prospects for the future supply of oil are 

determined not only by political and economic factors but 

also by geologic realities. The United States is the most 

mature region in the world in terms of exploration for oil 

and cannot reasonably expect to increase oil production 

or even to maintain current levels of production for long.

Many of the so-called frontier areas in Alaska and along 

the Atlantic coast have proved either to be barren or to 

have much less petroleum than first expected. Development of other promising areas in Alaska and offshore 

California is delayed indefinitely because of conflicts with 

environmental restrictions and recreational land use plans.

As a result of the petroleum supply shocks of the 

1970's, many policy planners recommended that the 

United States formulate coherent long-term energy strategies to ensure supply, modulate demand, and avoid 

future crises. A decade later, the world glut of low-priced 

petroleum is fostering the erroneous belief that the United 

States has successfully achieved national energy stability, 

and long-term strategies to ensure a continuing and 

reliable supply of petroleum have not been devised. 

Between the mid-1970's and the present, a combination of 

government policies and energy-commodity price changes 

has resulted in a small but significant shift from oil and 

gas to other fuels (fig. 1). Nevertheless, combined oil and 

gas use in the United States still is twice that of other 

energy sources.

Any supposition of energy stability based on today's 

relatively comfortable situation with regard to oil supply 

and price is undercut by an examination of the national 

and world oil resource picture. Discovery rates of crude 

oil, by region, for the past 60 years are compared in figure 

2 with annual production amounts. Discovery rates have 

decreased from 37 billion barrels of oil (BBO) per year in 

the early 1960's to a present-day level of about 10 BBO 

per year. Production of about 20 BBO per year now 

outpaces discovery by a factor of two. A worldwide 

increase in industrial activity, and hence in energy consumption, would produce an even greater disparity 

between discovery and demand-driven production. A similar gap between discovery and production exists in the

Executive Background and Overview
 Coal

 Nuclear and 

water

 » Natural gas

 Oil 

1945 1950 1955 1960 1965 1970 1975 1980 1985

Figure 1. Sources of energy consumed in the United States, 1945-1985. Modified from DeGolyer and MacNaughton (1986, p. 107).

25

1925- 

1930

I Annual production

i Western Europe, Africa 

and Western Hemisphere

I Eastern Europe. U.S.S.R..

Asia, and Oceania 

i Middle East

1935- 

1940

1945- 

1950

1955- 

1960

1965- 

1970

1975- 

1980

Figure 2. Discovery rate of crude oil by region, averaged over 5-year periods, and annual world production, 1925-1985. 

Modified from Masters and others (1987, fig. 5).

2 National Energy Resource Issues
<LLJ

>

LUtu

u

00

U

u_

o

z 

o

i Annual production

Western Europe, Africa 

and Western Hemisphere

i Eastern Europe. U.S.S.R..

Asia, and Oceania 

i Middle East

1965

1970

1970- 

1975

1975- 

1980

1980- 

1985

Figure 3. Discovery rate of natural gas by region, averaged over 5-year periods, and annual world production, 1950-1985. 

Modified from Masters and others (1987, fig. 7).

United States, despite enormous increases in drilling 

before the current downturn in activity.

Discovery and production data for natural gas are 

shown in figure 3. As the result of enormous gas discoveries in the Middle East and in the U.S.S.R. during the 

late 1960's and early 1970's, these areas now are known 

to have a major portion of the world's gas resources. For 

some years, worldwide gas production has outpaced 

reported discoveries but not yet to the extent seen for oil, 

perhaps because gas production is not economic in many 

areas. In the United States, annual consumption of gas 

currently is about twice the amount discovered annually.

Between 1975 and 1986, important changes were 

made in U.S. sources of oil. Most of our imported oil now 

comes from suppliers outside the Middle East. However, 

the disproportionate share of world oil reserves and 

undiscovered resources enjoyed by nations of the Organization of Petroleum Exporting Countries (OPEC) and the 

less rapid drawdown of these reserves assure OPEC 

producers of an increasingly dominant role in the conventional petroleum market in the not-too-distant future (figs. 

4, 5). The difference between a future situation (predicted 

for the 1990's) and the situation in the 1970's is that, in 

the future, OPEC dominance is expected to be stable and 

long term.

To avoid future U.S. dependence on foreign oil 

supplies, domestic oil supplies must be found and developed, and alternative liquid-hydrocarbon supplies must 

be made competitive by advances in geology and technology. Long-term commitments to these goals currently are 

difficult to maintain because of low prices and the temporary abundance of oil in the world market.

Oil is used primarily for transportation and in the 

petrochemical industry; nuclear power and hydropower 

cannot be substituted for these uses, and coal can be used 

only if it is converted to liquid form, an expensive and not 

yet commercially viable process. Thus, the principal problem in achieving national energy stability is the replacement of an increased proportion of liquid hydrocarbons as 

conventional oil becomes scarcer and more expensive or if 

international supply arrangements are disrupted.

Coal generally has been assumed to be the Nation's 

energy "ace in the hole" because of its abundance, but 

increasing U.S. reliance on coal will not be simply a 

matter of physical availability. Coal deposits in the United 

States are of widely varying qualities; each deposit poses 

a different set of challenges to economic extraction and 

use, and each has different environmental ramifications. 

In addition, much of the enormous U.S. coal resource 

base cannot be utilized because the overlying surface is 

either built upon or restricted by land use regulations. 

Much of the resource will never be economic to use 

because it is too thin, too deep, or too low in quality.

Alternative hydrocarbon resources such as oil shale, 

gas in tight reservoirs, and tar sands are abundant in the 

United States but pose their own sets of challenges to 

economic use. Rates of extraction for these alternative 

resources will be lower than those for conventional hydroExecutive Background and Overview
WORLD TOTAL

692.7 

BILLION BARRELS

China (19.4)

United States 

and Canada (34.8)

Mexico (55.6)

Other (62.6)

Eastern Europe (90.6)

Organization of

Petroleum Exporting

Countries (439.7)

(OPEC)

Figure 4. Estimated reserves of crude oil by major producing area, as of January 1, 

1986. Modified from DeGolyer and MacNaughton (1986, p. 1).

carbons, and costs will be significantly higher. In addition, 

using these resources will involve environmental costs that 

must be factored into decisions about the economic 

feasibility of adding alternative resources to the national 

energy mix.

In considering an evolving national energy mix, it is 

important to understand that energy resources such as oil, 

gas, coal, and uranium are nonrenewable, and, as the 

more readily available deposits are depleted, the remaining resources will be more difficult to find and produce at 

a desirable price or with requisite quality. Moreover, 

meeting tomorrow's national energy needs by shifting 

from one energy source to another or by converting from 

today's energy resources to other less conventional energy 

resources not currently marketable will involve major 

technological and economic shifts. Such transitions require 

planning and lead time in order to avoid major disruptions 

in the Nation's economic fabric.

Meeting future U.S. energy needs requires major 

and timely decisions about resources and their use. Comprehensive, reliable geologic information is a requirement 

for informed decisions, whether at the level of national 

energy policy or at that of corporate exploration strategy. 

Although basic policy will be determined to a large extent 

by economics and politics, geologic information is a 

necessary component in evaluating alternative paths to

national energy security and industrial success. Information on the geologic setting and character of reservoir 

rocks and resource materials is important, whether the 

aim is more effective exploration, improved recovery of 

conventional oil and gas, better technological approaches 

to the extraction and use of unconventional hydrocarbons, 

or solution of problems inherent in increased coal utilization.

The oil reserves of the United States are only about 

nine times annual domestic production (DeGolyer and 

MacNaughton, 1986, p. 1). To increase this ratio, emphasis should be placed on improved exploration efforts, in 

particular the exploration of frontier areas that have 

reasonable prospects of containing large oil fields. Such 

exploration efforts require improved knowledge of the 

regional geologic setting and history of the various exploration areas. In some frontier areas, especially those in 

relatively deep water parts of the continental margins, 

acquisition of the requisite geologic information has only 

just begun.

Another critical approach to making the short-term 

and midterm energy situation of the United States more 

favorable, at relatively low cost, is the improvement of 

conventional and enhanced oil recovery techniques. 

Improved recovery methods will increase the amount of 

usable conventional oil that can be recovered from reserNational Energy Resource Issues
WORLD TOTAL

3,406.6 

TRILLION CUBIC FEET

Mexico (76.5) 

Canada (99.5)

South America (113.5) 

United States (193.4) 

Africa (207.4) 

Western Europe (209.2) 

Other (234.7)

Middle East (858.6)

Eastern Europe 

Including U.S.S.R. 

(1,413.8)

Figure 5. Estimated reserves of gas by major producing area, as of January 1, 1986. 

Modified from DeGolyer and MacNaughton (1986, p. 14).

voirs already in production, although at lower recovery 

rates and higher costs. Better information as to the 

geologic character, setting, and history of the reservoir 

rocks will be necessary to accomplish these advances.

Geologic information also must underlie any planning for a major increase in coal use. The nature of U.S. 

reserves must be defined, especially variations in quality 

and accessibility, and the reserves need to be categorized 

according to their different potentials for a variety of 

extraction techniques and processing requirements and 

their suitability for different ultimate uses. Development 

of economical new technologies for coal cleaning, combustion, and flue gas treatment and waste disposal or for 

coal liquefaction and gasification requires detailed geologic information on the coals to be handled.

Other strategies to reduce reliance on conventional 

petroleum resources involve utilization of oil shale, tar 

sand, gas in tight reservoirs, gas hydrates, and coal-bed 

methane. These resources usually are referred to as 

"unconventional" or "alternative" because they generally 

require more technology or engineering advances, will 

cost more to tap, will yield their hydrocarbons at relatively 

slow rates, and, as a result, will ensure higher costs of the 

ultimate product. Attempts to obtain energy from these 

sources must be based on an understanding of the host 

rock, including a detailed knowledge of its geologic setting

and composition and the geologic processes that have 

affected it and its contained hydrocarbons. In addition, 

these potential resources must be accurately surveyed and 

assessed in regard to location, quantity, and quality.

Systematic studies of the physical character, mineralogy, and chemistry of resource-bearing rocks are 

required in order to understand the limits and possibilities 

of all potential oil and gas resources and the most 

effective approaches to their use. Assessments of resource 

quantity alone are no longer sufficient for the informed 

determination of either national policy or corporate strategies. It is necessary to determine what is accessible and 

its quality and whether current exploration and exploitation techniques are adequate to produce new energy 

supplies at reasonable cost. Such resource characterizations will help build a solid foundation of information 

from which to view the energy future of the United States.

This report offers a perspective on U.S. energy 

resources from the point of view of the geologic realities 

that control or constrain their large-scale use now and in 

the future. A national context is provided for each major 

component of the national energy mix, and some of the 

more evident problems are discussed. The role of geologic 

information in helping to solve these problems is emphasized. Examples throughout the report illustrate how

Executive Background and Overview 5
basic and applied geologic research is producing information to support present and future energy resource directions. The examples are drawn principally from U.S. 

Geological Survey (USGS) work, some of it done in 

cooperation with State or other Federal agencies. 

Although research on energy matters is also being done 

in universities and in other Federal and State agencies, 

USGS research is focused particularly on the geology of 

energy resources, which is the fundamental factor in 

finding and using any resource and is the theme of this 

report.

Many people contributed to the production of this 

volume. Terry W. Offield, Susan Garbini, and Stanley P. 

Schweinfurth gathered material and wrote sections of the 

report. Thomas D. Fouch, Oswald W. Girard, Harold J. 

Gluskoter, and and Kathie R. Fraser reviewed the report 

in its entirety. David H. Root, Charles D. Masters, Emil 

D. Attanasi, L.J.P. Muffler, and M.D. Carter reviewed 

various sections and also contributed material. Judith W. 

Stoeser edited and produced the volume. Nancy K. 

Gardner translated the illustrations to computer graphics. 

Gary W. Hill provided essential technical advice.

6 National Energy Resource Issues
PETROLEUM RESOURCES

Foreign supplies of crude oil were virtually irrelevant to the United States between 1860 and 1950, by 

which time we had produced 39 BBO and the rest of the 

world only 23 BBO (fig. 6/4). During that period, domestic demand was satisfied by domestic production. From 

1945 to 1970, oil production in the United States increased 

at a slow and steady rate, whereas production in the rest 

of the world increased at a much faster rate (fig. 6B). As 

world industrial and transportation needs have grown, 

world demand for oil has risen steadily, and, at the same 

time, the United States has become a major importer of 

petroleum.

Demand for oil has driven production, and, from 

1971 until recently, a seller's market existed on the world 

scene. Both the creation of the seller's market and its 

recent collapse were controlled by policies of OPEC or its 

individual member nations rather than by the United 

States, and this shift in control further indicates our 

changed role in this arena. Numerous buyers compete in 

the world market to purchase oil, and the United States 

has no special position in obtaining the large amounts of 

oil that it imports each year. Competition among buyers 

will intensify as world demand continues to increase.

For many years to come, petroleum will dominate 

the pattern of world energy use as the most convenient 

and versatile energy resource. The price and availability 

of oil will affect the stability and pricing of almost all 

sectors of the world energy economy. It is hard to overstate the importance of accurate world petroleum 

resource assessments and of improved geologic information, both of which will enable the United States to foresee 

future requirements for foreign oil and to improve the 

domestic supply of oil and gas.

GLOBAL SETTING

Most of the world's crude oil resources have been 

discovered, and future discoveries are unlikely to match 

past discoveries. The total crude oil resource comprises 

three components: cumulative production, remaining 

known reserves, and undiscovered recoverable oil. Estimates of world total cumulative crude oil production, 

reserves, and undiscovered resources by the USGS (Masters and others, 1987) have changed significantly since 

they were last made. Between January 1981 and January 

1985, cumulative production of crude oil increased from 

445 to 524 BBO, estimates of reserves increased from 723 

to 795 BBO, and estimates of undiscovered resources 

decreased. The 95-percent likelihood estimate of undiscovered resources decreased from 321 to 262 BBO, the 

5-percent likelihood changed even more dramatically

from 1,417 to 927 BBO, and the most likely value, or 

mode, decreased from 550 to 425 BBO. Changes in 

estimates of undiscovered resources reflect (1) the transfer, following discovery, of undiscovered resources into 

reserves and production; (2) new geologic insights into 

petroleum occurrence and improved information on the 

petroleum geology of the U.S.S.R. and Mexico, both of 

which indicate more limitations on resource potential 

than previously assumed; and (3) major disappointments 

in the exploration of areas in the United States previously 

regarded as highly promising frontiers.

New estimates of the ultimate amount of conventional crude oil that will be produced in the world by 

region suggest that the distribution of undiscovered 

resources is similar to that of discovered resources (Masters and others, 1987) (fig. 7/4). If these estimates are 

reasonable, then the distribution pattern of petroleum 

resources in the world is established and can be used as a 

basis for long-term national planning. It is expected that 

future discoveries will be concentrated in known productive areas and that the best discoveries in those areas have 

already been made. Exploration surprises, both favorable 

and unfavorable, certainly will occur but most likely will 

not materially alter the global resource picture.

Not only do OPEC producers hold the bulk of the 

world's future oil supply (fig. &4), but they also currently 

are drawing down their resources proportionately less 

rapidly than are other areas of the world. This situation is 

illustrated in figure 9, in which the reserve-to-production 

(R/P) ratio of the United States can be contrasted with the 

much larger R/P ratios of many other producing nations. 

The larger the ratio, the longer a nation can continue at its 

current rate of production. The United States currently 

has proved reserves equal to 9 years of production at 

today's rate, whereas Saudi Arabia has reserves equal to 

141 years of production. The inescapable conclusion is 

that, in the future, OPEC producers will be able to 

exercise increasing control over the amount and therefore 

the price of world petroleum supplies.

As a result of limited market interest, the world's 

gas resources are less known and less developed than are 

its crude oil resources, but the geographic distribution and 

the abundance of gas resources appear to be about the 

same as those of oil resources (fig. 85). A partial exception to this linked distribution pattern is the U.S.S.R., 

whose gas resources are much larger than its oil resources 

and larger than the gas resources of the Middle East. The 

large resources of gas in the Middle East, which have 

been located in the course of oil exploration, have not 

been developed at a significant rate because of the absence

Petroleum Resources
600

500

400

300

200

100

World 

United States

1950 1955 1960 1965 1970 1975 1980 1965 

As of January 1

B

1966

30

25

20

15

=! 10 

oo

1950 1955 1960 1965 1970 1975 1960 1965

Figure 6. Cumulative (A) and annual (B) U.S. and world production of crude oil. Modified from 

DeGolyerand MacNaughton (1986, p. 4, 5, 12).

8 National Energy Resource Issues
ULTIMATE RESOURCES 

OF CRUDE OIL

(IN BILLIONS OF BARRELS)

200 400 600 800 1,000 1,200 1,400

795

RESERVES

DISCOVERED RESOURCES

ULTIMATE RESOURCES 

OF NATURAL GAS

(IN TRILLION CUBIC FEET)

2,000 4,000 6,000 8,000 10,000

1,173 3,908

PRODUCED RESERVES

DISCOVERED RESOURCES

Figure 7. Total world resources of crude oil (A) and gas (B), including discovered resources (cumulative production 

and reserves, as of January 1981) and undiscovered resources (as of January 1983). Modified from C.D. Masters, E.D. 

Attanasi, W.D. Dietzman, R.F. Meyer, R.W. Mitchell, and D.H. Root (written communication, 1987).

Petroleum Resources 9
Middle East

North America

L.S.S.R.

Africa

Asia

South America

Europe

Cumulative production 

Identified reserves

Mode of undiscovered 

resources

100 200 300 400 500 600 700 

CRUDE OIU IN BILLIONS OF BARRELS

800

Figure 8. Regional distribution of world resources of crude oil (A) and gas (B), as of 

January 1, 1985. Modified from Masters and others (1987, figs. 3, 4).

of a local market. In the future, Middle Eastern producers probably will be able to export gas (liquid natural gas) 

from the same dominant position that they have held in 

oil.

Available evidence suggests that, during the next 20 

years, non-OPEC production capacity of crude oil will 

decline relative to OPEC capacity. The United States and 

the U.S.S.R. produce more than 38 percent of total world 

crude oil and are the principal non-OPEC oil producers 

(DeGolyer and MacNaughton, 1986, p. 3). Despite 

advances in exploration and production technologies, neither country is likely to increase production in the future. 

Many small, non-OPEC producing countries have 

increased production during the past decade; production 

in many countries will peak during die next decade and 

then slowly decline (National Petroleum Council, 1987, p. 

165). A few countries, such as Norway, Egypt, Colombia, 

Brazil, and Ecuador, are reporting significant new discoveries and may be able to maintain or increase production

capability; however, these increases will not change the 

basic world outlook for oil.

Although no one can truly predict the extent of 

resources not yet tested by drilling, geologic evidence 

from around the world suggests that most future discoveries will be found in only a few regions, regions that for 

the most part have already experienced some exploration. 

New giant discoveries, so disproportionately important in 

terms of resource distribution, probably will be concentrated in just a few basins within these regions. This 

scenario is probable because a large occurrence of any 

natural resource requires that a number of independent

Figure 9. Surplus production capacity is indicated ^- 

by a decline in the production curve through time; 

full capacity is indicated by a steady increase or 

leveling off of the production curve. R/P is reserve-toproduction ratio, determined by using estimated 

reserves as of January 1, 1986 (in parentheses) and 

production for 1985 (daily production times 365). 

Data from DeGolyer and MacNaughton (1986).

10 National Energy Resource Issues
B

U.S.S.R.

Middle East

North America

Europe

Asia

Africa

South America

Figure 8. Continued.

3

UJ

oe

Q i/»

o

10,000

8,000

6,000

4,000

2,000

0

1970

Cumulative production 

Identified reserves

Mode of undiscovered 

resources

500 1,000 1300 2,000 2,500 3,000 3,500 

GAS, IN TRILLIONS OF CUBIC FEET

I Iraq (37.98x109) 

R/P 73.0

I Iran (36.68x109) 

UP 45.0

| Nigeria (1631x109) 

R/P 30.7

I Indonesia (8.69x109 ) 

18.4

1973 1976 1979 1982 1985

Petroleum Resources 11
B 10,000

«/> 8,000

6,000

4,000

2,000

(5.(Kx109)

R/P 16.9 

(22.40x10') 

59.0 

(2930x109)

R/P 46.4 

(72.00X109)

R/P 211 

069.18x109)

R/P 141

Saudi Arabia

1970 1976 1979 1982 1985

§5

Q £

6,000

4,000

- 2,000

China

United Kingdom 

Norway 

Canada 

Mexico 

United Stales

(19.48x10*) 

R/P 21.4 

(5.46X109) 

R/P 6.32 

(10.5X109)

(6.4X109) 

R/P 113

(55.59X109) 

R^> 56.8

G8.42X109) 

R/P 8.68

0

1970 1973 1976 1979 1982 1985

Figure 9. Continued.

12 National Energy Resource Issues
variables combine in an optimum way. In the case of 

petroleum, the critical variables are petroleum source 

rock, reservoir rock, trap, and timing. The optimum 

combination of these variables is rare, and the localized 

concentrations of large accumulations of petroleum 

around the world prove this point. With the possible 

exception of deep-water continental margin areas, it is 

unlikely that a major district remains undiscovered that 

might significantly alter the known distribution of world 

oil.

SITUATION AND OUTLOOK FOR 

PETROLEUM RESOURCES IN THE 

UNITED STATES

In 1950, U.S. consumption of crude oil and refined 

products was 2.5 BBO, of which U.S. imports were only 

11 percent. By 1977, both consumption and imports 

reached a historic high; 6.8 BBO were consumed, of 

which net imports were 44 percent. After a succession of 

supply and price shocks, the United States cut both 

annual consumption and imports; in 1985, 5.7 BBO were 

consumed, of which net imports were 28 percent.

An important aspect of the U.S. import picture has 

been the progressive shifting from one set of suppliers to 

another (figs. 10, 11). Until 1972, at least half of all oil 

imports were from the Western Hemisphere. From 1972

to 1981, at least half were from Africa and the Middle 

East. Since 1981, oil imports have been more evenly 

divided between the major producing areas of the world. 

These shifts reflect both the more limited resources of the 

Western Hemisphere and company exploration strategies. 

The traumatic effects of the OPEC oil embargo in 

1973-1974 and the large price increases in 1979 motivated attempts to decrease U.S. dependence on oil in 

general and on imports from Middle Eastern nations in 

particular. Although the initial goal of energy independence has gradually given way to a recognition of the 

inevitable interdependence of the world oil market, the 

United States has moved to attain more diverse and stable 

supplies of foreign oil.

Approximately 4 billion barrels of petroleum liquids are produced annually in the United States; slightly 

more than 3 billion barrels are liquid crude oil, and about 

0.6 billion barrels are liquids from gas. The outlook for 

continued production at this level is somewhat uncertain 

geologically. One point of uncertainty in the near term is 

the amount of oil being added to reserves by discoveries 

of new fields. Since 1979, the U.S. Government has not 

collected information that allows an accurate accounting 

of exploration finding rates and new-field wildcat-well 

successes, but about one-sixth of annual additions to 

reserves generally can be attributed to wildcat exploration. 

The remainder of the additions to reserves is attributed to 

extensions of known fields, reassessment of reserves in

3,000

2,500

2,000

1,500

 North America

 South America

 Middle East 

Ml Africa

 Others

1950 1955 1960 1965 1970 1975 1980 1985

Figure 10. U.S. imports of crude oil by source region, 1945-1985. Modified from 

DeGolyer and MacNaughton (1986, p. 58).

Petroleum Resources 13
September 1978

Saudi Arabia

Indonesia

Mexico

Canada

Western Europe

Crude oil 

Refined products

0 200 400 600 800 1,000 1,200 1,400

THOUSANDS OF BARRELS PER DAY

Figure 11. Major sources of U.S. imports of crude oil and refined products, 1978 and 1985. 

Modified from Borg (1986, p. 4).

known reservoirs, and discoveries of new reservoirs in old 

fields.

Another point of uncertainty in the relatively near 

term is the outlook for growth in known fields. For each of 

the past few years, about 2.5 BBO have been extracted 

from known conterminous U.S. reserves; yet, until the 

industry decline of 1986, U.S. proven reserves were 

believed to have remained the same or increased slightly. 

If this picture of reserves is true, new reserves are being 

developed in old fields instead of fixed reserves simply 

being drained at a faster rate. In other words, oil contained in a rock reservoir and previously not considered to 

be drainable in normal recovery operations now is being 

brought into production. Some of the addition results 

from enhanced oil recovery, but much more apparently 

comes from in-fill drilling. The important question is how 

long such additions to reserves can continue simply as a 

result of drilling more wells in known fields. A corollary 

question is how much similar growth we can expect in the

few new fields being discovered each year. Other related 

questions are the rate at which we can expect this assumed 

new reserves addition to become available, the cost, and 

whether this field growth has been factored adequately 

into estimates and inferences of undiscovered recoverable 

oil resources. To answer these questions will require 

detailed knowledge of the geologic character of many 

representative reservoirs.

In the longer term, a major uncertainty lies in 

estimates of undiscovered recoverable resources. In 1981, 

the USGS (Dolton and others, 1981) produced an estimate of undiscovered resources that ranged from 64.3 

BBO (95-percent likelihood) to 105.1 BBO (5-percent 

likelihood), the mean being 82.6 BBO. Since that time, 

exploration disappointments have occurred in areas once 

considered to be among the most promising U.S. frontiers. Unproductive drilling in two major prospective areas 

of the Atlantic margin indicates a much lower likelihood 

of significant resources than previous forecasts had sug14 National Energy Resource Issues
August 1985

Mexico

Crude on 

Refined products

0 100200309400500600700800900 1,000

THOUSANDS OF BARRELS PER DAY

Figure 11. Continued.

gested. Results from a few holes drilled in the Navarin 

basin of the Bering Sea continental shelf indicate that the 

sedimentary rocks are much less favorable hosts for large 

occurrences of oil than investigators had previously 

believed. The Mukluk structure off the North Slope of 

Alaska, once believed to resemble in promise the nearby 

structure containing the supergiant Prudhoe Bay oil field, 

was drilled and appears to be barren. Recent noteworthy 

finds in the deep-water parts of the Gulf of Mexico and in 

offshore California are unlikely to compensate for these 

major exploration disappointments. Oil exploration and 

development in an area of major promise on the North 

Slope, the Arctic National "Wildlife Refuge, hinge on the 

outcome of the debate about the relative value to society 

of potential energy resources as opposed to preservation 

of wilderness. Currently, the area is closed to petroleum 

resource development, but the Secretary of the Interior 

recently recommended to Congress that exploration be 

permitted. Highly prospective areas of offshore California also are subjects of controversy and, at this time, are 

closed to exploration.

Estimates of offshore oil potential made in 1985 by 

the Minerals Management Service (MMS) (Cooke, 1985) 

indicate a decrease, by almost 50 percent, in expected 

recoverable resources relative to estimates made by the 

USGS in 1981. Part of this decrease reflects economic 

differences between 1981 and 1985, such as oil price 

expectations and minimum economically exploitable field 

size in areas such as the Arctic, and part is because the 

MMS estimate did not cover deep-water or State-owned 

areas included in the USGS estimates. Much of the 

decrease results, however, from the new and less optimistic geologic information discussed above. Revised estimates of the undiscovered recoverable resources of the 

United States now being prepared by the USGS and the 

MMS may be 25 to 50 percent lower than the 1981 

estimates.

An important factor in evaluating the petroleum 

resource potential of the United States is that it is at a very

Petroleum Resources 15
Figure 12. Oil and gas fields in the United States. Modified from K.L. Varnes (written communication, 1987).

mature stage of exploration. Oil fields are widely distributed (fig. 12), and few undrilled major frontiers remain. 

Moreover, the distribution of oil resources is highly 

skewed toward large fields (greater than 10 million barrels), especially giant fields (greater than 100 million 

barrels). Fields larger than 10 million barrels constitute 

only about 5.5 percent of total U.S. fields, yet they contain 

77.5 percent of U.S. oil reserves. It is unlikely that a 

significant number of giant or supergiant fields remains 

to be found in the exploration frontiers of the United 

States. The lack of new giant fields and the increasing 

difficulty of finding more oil in a well-explored country 

are reasons behind the dramatic decrease since about 

1950 in oil discovery rate per foot drilled (fig. 13). On the 

other hand, results of statistical analysis of oil pool 

distribution suggest that as many as 110,000 additional 

fields remain to be found. Many of these fields will be too 

small to be economic under any circumstances, but many 

others will be productive. Cumulatively, these fields may 

extend U.S. reserves by several years of annual domestic 

production, but they will be hard to find and will not 

necessarily be available when they are most needed.

Although gas is an important energy resource, 

particularly for residential and industrial heating uses, it

cannot readily replace liquid hydrocarbons. The United 

States currently consumes about 17 trillion cubic feet of 

gas (TCFG) per year. In 1981, the USGS (Dolton and 

others, 1981) estimated measured U.S. gas reserves at 

191 TCP and inferred reserves at 177 TCFG. Undiscovered recoverable gas resources were estimated between 

475 and 740 TCFG, the mean being 594 TCFG. As with 

oil estimates, the range and mean reflect statistical probabilities, from high to low confidence, estimated by groups 

of experts that evaluated the petroleum geology and 

exploration history of 137 provinces. The estimates are 

based primarily on publicly available data and conventional technology and economics and do not include gas 

from unconventional sources. The estimates reflect 

assumed economic thresholds, such as minimum field size 

and availability of delivery infrastructure; these threshold 

values could be very important in determining the amount 

of gas that ultimately can be produced from frontier areas 

such as Alaska or deep-water areas of the continental 

slope.

As with oil reserves, a large percentage of the gas 

reserves are in giant (greater than 0.6 TCFG) and 

supergiant fields. The United States has only 2 supergiant 

and 17 giant gas fields, which, along with some large but

16 National Energy Resource Issues
i

Indicated and 

inferred reserves

Past production and 

proven reserves

1,000 1300 2,000

CUMULATIVE EXPLORATORY DRILLING, 

IN THOUSANDS OF FEET

Figure 13. Discovery rate of crude oil in the United States as a function of the cumulative 

amount of exploratory drilling, 1920-1979. Modified from C.D. Masters (written communication, 1986).

not giant fields, are critically important. Of some 9,000 

gas fields in the United States, the largest 100 contain 

about half the estimated U.S. gas reserves; the Prudhoe 

Bay field alone is estimated to contain 26 TCFG. At 

present, however, the gas in the Prudhoe Bay field cannot 

be delivered for lack of a pipeline, a reflection of the 

general logistical and economic problems limiting gas 

production in Arctic and offshore frontiers.

The outlook for U.S. gas exploration and resource 

development is related to oil supply and price. Lower oil 

prices-are likely to delay or change plans by consumers to 

shift from oil to gas and will seriously affect the minimum 

field size necessary to warrant economic development of 

gas, especially in difficult frontier areas. Some important 

potential resources may not be economic to produce.

THE ROLE OF GEOLOGIC INFORMATION

Whether the goal is exploration in frontier areas, 

effective drilling to find new fields in known areas or new 

oil in old fields, or development of improved production 

methods to obtain all the oil possible from a well, it is 

critical to have the best possible geological information 

and insights.

Initial targets in the exploration of frontier basins 

generally are geologic structures interpreted from seismic 

reflection data, such as folds, faults, salt domes, or ancient 

reef complexes. The likelihood that such structures will 

contain petroleum is gauged by using the best possible 

knowledge of the geologic framework and history of the 

basin and comparison with other productive basins. The 

necessary geologic knowledge encompasses (1) the 

regional geology of the target area and how it might 

provide a setting for the occurrence of petroleum; (2) a 

determination of the amount and type of organic matter in 

the rocks, including the extent to which it may have been 

altered by heat into mobile hydrocarbons; (3) the character, volume, and position of various source rock and 

reservoir rock units; (4) the configuration and volumes of 

apparent trap structures; and (5) the likelihood of seals 

above or around traps that would keep oil or gas from 

escaping. Information from rock exposures and samples 

from drill holes must be used to make observations or 

inferences about the extent of porosity and permeability 

and the geologic processes that may have affected these 

reservoir rock characteristics. Frontier exploration, particularly in Arctic or offshore areas, is very difficult and

Petroleum Resources 17
expensive, and each element of geologic information is 

critical.

Detailed geologic information also is required 

before drilling in known areas to find new resources. 

Local geologic settings within an oil basin should be 

deciphered to infer conditions of reservoir sand deposition, the resulting inhomogeneities of these sands, and the 

likely distribution and geometry of potential reservoirs. To 

optimize in-fill drilling or to improve oil and gas recovery 

techniques, detailed information is required on the reservoir rock's pores, how they are interconnected, and by 

what minerals they are enclosed. As new information and 

insights on regional geology and on the occurrence of 

petroleum are obtained, exploration strategies and field

development techniques are improved, and better estimates of the petroleum resources of the United States can 

be made. Studies of petroleum geology by the USGS have 

been designed to meet both short- and long-term needs 

and to provide some continuity of research effort, a 

particularly useful function during times when industrial 

research and exploration efforts are severely curtailed. 

They include basic research on reservoir rock characteristics and the processes that affect them, studies of the 

regional and petroleum geology of selected frontier areas, 

studies of geologic basin processes that give rise to 

petroleum provinces, and resource assessments that offer 

an informed basis for government decisions on land use 

and national energy policies.

18 National Energy Resource Issues
Focus: Oil and Gas Resources on Wilderness Lands

The Federal Government owns approximately 738 

million acres of onshore land in the United States, almost 

one-third of the Nation's entire land area, and it retains 

control over subsurface mineral rights to an additional 66 

million acres.

Approximately 50 percent of these Federal lands is 

in the 11 Western States. In 1981, 31 percent of this land 

was classified as designated and proposed wilderness 

land, and access to exploration and development was 

limited. The Wilderness Act of 1964 stated that, after 

December 31, 1983, these areas were to be off limits to 

energy and mineral exploration and development. In recent 

years, controversy has been generated in regard to the 

probable occurrence of energy and mineral resources on 

Federal lands in general and on wilderness lands in 

particular. A major issue is whether it is in the best 

interests of the United States to allow resource exploration and development on Federal lands, especially those 

having noteworthy environmental values.

Various resource studies on limited segments of 

these Federal lands by government and industry indicate 

that an important part of the future energy and mineral 

resources of the United States may lie beneath federally 

controlled lands. The accuracy of these resource estimates is unknown, however, because only limited data are 

available regarding resources on most Federal lands.

As part of the USGS's responsibility to inventory 

the Nation's resources, in particular those on Federal 

lands, a pilot study was conducted in 1982-1983 to assess 

the potential for oil and gas resources in designated and 

proposed wilderness lands of the Western United States 

(Miller, 1983). The scope of the investigation was limited 

to conventional petroleum resources occurring in wilderness lands administered by the Bureau of Land Management, the Forest Service, the National Park Service, and 

the Fish and Wildlife Service. The area of study included 

almost 74 million acres in Arizona, California, Colorado, 

Idaho, Montana, Nevada, New Mexico, Oregon, Utah, 

Washington, and Wyoming.

This study was the first Federal program of systematic geologic studies of the petroleum resource potential 

on specifically designated Federal lands. The wilderness

areas in each State were identified as to controlling agency, 

and the potential for the occurrence of petroleum 

resources in each area was assessed. At least 34 percent of 

the wilderness lands, or about 25 million acres, was 

determined to have the geologic attributes necessary for 

the occurrence of petroleum resources. An additional 33 

percent is mostly in areas where small amounts of 

sedimentary rocks are mixed within igneous and metamorphic terranes and was determined to have either 

limited or unknown potential for petroleum resources. 

The remaining 33 percent is located in terranes containing predominantly igneous and metamorphic rocks and 

probably has no petroleum resource potential; however, 

these terranes may have potential for various mineral 

resources.

Seventy percent (or 52 million acres) of the wilderness land studied is proposed for withdrawal from exploration; the remainder (22 million acres) has already been 

designated as wilderness land by law. A significant result 

of this study is that, of the 25 million acres believed to 

contain petroleum resources, 21 million acres are wilderness lands proposed for withdrawal, and only 4 million 

acres have already been withdrawn from exploitation.

Estimates of undiscovered conventional recoverable 

crude oil resources on the lands studied are from 600 

(95-percent likelihood) to 1,490 (5-percent likelihood) 

million barrels, the mean estimate being 834 million 

barrels. Estimates of undiscovered conventional and recoverable natural gas resources are from 5.54 to 16.64 

TCFG, the mean estimate being 9.73 TCFG. Most of the 

oil resource is in Wyoming, Idaho, and Utah, and most of 

the gas resource is in Wyoming, Montana, and Idaho.

This pilot study indicates the value of inventorying 

the energy and mineral resources of the United States as 

a basis for informed decisionmaking in the balanced 

management of public lands to maximize use of those 

lands for the public benefit. A similar detailed assessment 

of the petroleum resources of all Federal lands is now 

being prepared as part of the revision of estimates of the 

undiscovered petroleum resources for the entire United 

States.

Petroleum Resources 19
Focus: Frontier Petroleum Province in the Eastern United States

About 180 to 240 million years ago, during the 

Triassic and Jurassic periods, an extensive system of 

fault-bounded sedimentary basins developed along the 

eastern margin of North America as a result of continental rifting and formation of the Atlantic Ocean. Resource 

assessment and exploration for petroleum and minerals in 

these rift basins are hampered by a lack of outcrop in the 

exposed basins and by thick sedimentary cover over buried 

basins on the coastal plain and offshore.

Organic geochemical studies of these basins were 

initiated to evaluate their petroleum resource potential 

and to determine the relationship between organic matter 

and mineralization. Preliminary studies focused on a thick 

sequence of organic-rich shales in the Triassic part of the 

Newark basin, but these shales have an unfavorably high 

temperature history with respect to petroleum generation 

and preservation. Recent systematic sampling of Triassic 

and Jurassic rocks, however, has revealed the presence of 

less thermally altered shales of Early Jurassic age in the 

Hartford (Connecticut and Massachusetts) and Newark 

(New Jersey, New York, and Pennsylvania) basins. A clear 

precursor-product relationship exists between indigenous 

organic matter in the Jurassic shales and migrated organic 

matter (liquid and solid) in overlying hydrocarbonstained sandstones and vein fillings.

Mineralized veins commonly crosscut sedimentary 

and volcanic rocks in the Hartford and Newark basins.

The history of fluid flow in the basins was reconstructed 

through studies of the composition and texture of these 

veins. Results of the studies indicate that multiple generations of mineralizing fluids and petroleum fluids migrated 

through open fractures in the rocks.

In the Hartford and Newark basins, the zone of 

petroleum source rocks is believed to be about a kilometer thick and to encompass the boundary between Triassic 

and Jurassic rocks. A brief episode of high heat flow 

during the earliest Jurassic is proposed to account for the 

narrow, shallow zone believed to have generated oil. 

Extensive Jurassic lava flows probably were associated 

with this time of high heat flow.

In the exposed rift basins, most potential petroleum 

reservoir rocks have been removed by erosion, but, wherever the upper part of the rock section is preserved, 

exploration targets are shallow and relatively inexpensive 

to drill. The presence of thin but widespread organic-rich 

shales having moderate to excellent petroleum source 

potential indicates that reservoir properties rather than 

thermal history or source rock quality limit petroleum 

accumulation. The potential for petroleum accumulation 

is greater in the buried basins than it is in the exposed 

basins because less erosion of possible reservoir rocks has 

occurred. The regional geologic setting, good quality of 

potential source rocks, and presence of migrated petroleum in the exposed basins are cause for optimism about 

resource prospects in the buried basins.

20 National Energy Resource Issues
Focus: Magnetic Exploration for Oil and Gas Fields

The possibility that magnetic methods can be used 

to locate hydrocarbon accumulations was first suggested 

by T.J. Donovan of the USGS in 1979, following the 

identification of anomalous magnetic signals from shallow 

rocks above the Cement oil field of central Oklahoma. 

Upward leakage of hydrocarbons from deep reservoir 

rocks was suggested as the mechanism that generated 

geochemical conditions favorable for the growth of a 

strongly magnetic iron-oxide mineral (magnetite) in nearsurface rocks. More recently, magnetic anomalies were 

recognized over other developed oil fields and over some 

undeveloped areas that have a high potential for hydrocarbons, but the original theory was not systematically 

tested. The sources of the anomalies that is, the magnetic substances that cause them were unknown, and 

evidence relating the anomalies to hydrocarbons at depth 

was lacking.

Geophysical, geologic, and geochemical methods 

are being used in three areas of anomalous magnetization 

to test the original theory. The test areas are (1) the 

Cement oil field, which has been developed; (2) an area in 

Alaska that represents a known but undeveloped oil field; 

and (3) an area in Idaho and Wyoming that shows high 

promise for oil and gas resources. Studies in the Cement 

oil field indicate that an unusual magnetic iron-sulfide 

mineral, pyrrhotite (fig. 14), formed in abundance in 

shallow rocks directly above the field and that formation 

of the pyrrhotite is closely related to leaking hydrocarbons; magnetite was not observed in these rocks. Anomalous magnetization in an oil field in Alaska's North Slope 

also is caused by a magnetic iron-sulfide mineral in this 

case, greigite, the formation of which may be related to oil 

leakage. In the central part of the Idaho-Wyoming thrust 

belt, magnetic anomalies on trend with nearby gas and oil

Figure 14. Photomicrographs of pyrrhotite in well cuttings from the Cement oil field of Oklahoma. The pyrrhotite formed 

in shallow rocks directly above the field, and its formation was closely related to leaking hydrocarbons. Left, Mosaic of 

pyrrhotite plates within mudstone. Right, Tabular crystals of pyrrhotite partly replaced by pyrite.

Petroleum Resources 21
fields to the south are caused by magnetite, but, because tion of anomalous magnetic signals, whereas other envithe magnetite was present when the rock formed, the ronments are not. Future geologic studies will focus on

anomalies are not related to hydrocarbon leakage. developing models to distinguish between favorable and

Preliminary studies indicate that certain hydrocar- unfavorable environments and should lead to more effecbon seepage environments are favorable for the genera- live and reliable applications of this exploration technique.

22 National Energy Resource Issues
Focus: The Monterey Formation of California

The Monterey Formation of Miocene age is a 

fine-grained organic-rich siliceous rock unit of great 

economic importance. Long known as a major source 

rock for oil, the Monterey is also a prolific reservoir rock, 

both onshore and offshore in a series of California basins 

(fig. 15). Oil has been produced from the Monterey since 

the late 1800's, but very recent discoveries show the 

particular importance of fractured-rock areas as exploration targets in the siliceous formation. The Point Arguello 

field, reported to contain on the order of 500 million 

barrels of recoverable oil (Isaacs and Petersen, 1987), is a 

major fractured-rock reservoir offshore in the Monterey, 

and the regional geologic framework of the formation 

suggests much promise of other such petroleum occurrences.

Fractured rocks are not a common reservoir type, 

and almost all oil reservoirs worldwide have been discovered in porous, permeable rock layers where oil is trapped 

in relatively large pores by overlying impermeable layers. 

As a result, well log analysis and other techniques for 

locating oil have focused on finding high-porosity zones. 

In the Monterey, however, oil is trapped in rocks having

many but very small pores, and oil production is possible 

only because extensive fractures connect the pores and 

increase rock permeability. Conventional well log analysis 

has not proved very helpful in recognizing fractured-rock 

reservoirs, but exploration techniques developed for the 

Monterey should prove valuable in recognizing other 

fractured rocks.

Other exploration challenges abound in the Monterey. The formation is thinly bedded and highly diverse, 

and correlating rock sequences from one basin to another 

typically has been more guesswork than science. Postdepositional chemical changes in the rocks have variably 

altered the character of potential reservoir rocks from one 

basin to another, as well as within a basin. Organic matter 

in the Monterey has been interpreted through conventional analysis as not having matured (been altered by 

heat) sufficiently to generate oil, even where oil accumulations have been discovered.

For the past several years, research by USGS scientists has been aimed at deciphering the character and 

history of the Monterey Formation. One of the major 

problems addressed was how to determine regional trends

San Miguel

OFFSHORE

SANTA MARIA

BASIN

Point 

Pedernalesjfe

Bonito^

Arg u ell o

ONSHORE SANTA MARIA BASIN 

Guadalupe

Santa Maria V'allc\

C a * C a n \ r, n 

D ee r

lompoo

Los 

Alamos

0

l_

SANTA BARBARA CHANNEL

10 MILES

Figure 15. Onshore and offshore oil fields (red) in the Santa Maria basin of California.

Petroleum Resources 23
ORCUTT FIELD WELL *8

SILICA/

SILICA AND ORGANIC 

SILICA CARBONATE DETRITUS CARBONATE MATTER APATITE

0 50 0 50 0 50 0 50 0 15 0 15

500

1,000

£ 1,500

X 

a. 2,000

2,500

3,000

Figure 16. Chemical analyses of well cuttings from the Monterey Formation provide a basis 

for detailed stratigraphic correlations.

in the distribution of rock types according to particular 

origin and character. The Monterey is composed of three 

types of sedimentary rocks: rocks composed of finegrained, biologically produced marine sediment, which 

become highly fractured as a result of chemical changes 

during burial; rocks composed of fine-grained landderived sediment, which are less fractured; and rocks 

containing organic matter, the source of the oil. Regional 

trends of these sedimentary components have been difficult to determine because of the formation's thin-bedded 

nature and diverse rock types. A major accomplishment 

was the successful testing of whole-rock chemical compositions of well cuttings as a tool to determine the average 

composition of many thin beds and thus categorize some 

of the diverse rock sequences (fig. 16).

Rates of sedimentation in the various Monterey 

Formation basins were also determined. The Monterey,

even where it is most siliceous, did not result from an 

unusually rapid, biologically derived influx of silica but 

rather from an extremely slow influx of diluting landderived sediment. The discovery of this relationship led to 

the important conclusion that regional facies trends were 

controlled principally by the supply of land-derived sediment rather than by the supply of biologically produced 

ocean sediment. Understanding the distribution of rock 

types in the Monterey thus requires focusing on the 

geologic processes that influenced the influx of sediment 

from land rather than on those that influenced the supply 

of material from the marine environment.

It was also recognized that use of normal measurement techniques results in a significant underestimation 

of the alteration of the organic matter in these unusual 

rocks. In fact, during early burial and before compaction, 

the sediments most likely were not only much thicker but

24 National Energy Resource Issues
also were subjected to high temperature gradients. As a Monterey Formation. From studies of regional setting and 

result, alteration (maturation) of organic material was geologic history to detailed geochemical research designed 

more advanced at an earlier stage in basin development to show the origin of oil and the changes that have 

than investigators had previously realized. occurred in the reservoir rocks, the new information 

These recent studies have produced a new under- provides an improved basis for selecting exploration tarstanding of the enormously productive and prospective gets and interpreting exploration data.

Petroleum Resources 25
Focus: Assessment of Petroleum Potential in the Arctic National Wildlife Refuge, Alaska

The coastal plain area of the Arctic National Wildlife Refuge in northeastern Alaska is an arctic environment where wildlife protection is an important concern. It 

is government-owned land currently under consideration 

for leasing for petroleum exploration, and Section 1002 of 

the Alaska National Interest Lands Conservation Act 

required the U.S. Department of the Interior to evaluate 

both the wildlife resources and the potential for petroleum resources, so that Congress could make a wellinformed decision about possible leasing. A consortium of 

oil companies was permitted to conduct some 1,300 miles 

of seismic surveys, and data from those surveys and other 

surface exploration were turned over to the USGS and the 

Bureau of Land Management for assessment of the area's 

oil and gas potential. The USGS estimated in-place 

resources, and the Bureau of Land Management overlaid 

economic and engineering factors to produce estimates of 

recoverable resources. A report to Congress on both the

148°

resource assessment and the environmental aspects of this 

important and controversial area of arctic land was issued 

in early 1987 by the U.S. Department of the Interior. The 

large oil and gas resource potential assessed was the basis 

for the Secretary of the Interior's recommendation to 

Congress that the area be opened to petroleum exploration.

Both the supergiant Prudhoe Bay field, which lies 

about 60 miles west of the refuge border, and the nearby 

smaller Kuparuk field produce oil from a complex of 

rocks called the Ellesmerian sequence. These rocks extend 

eastward beneath the coastal plain but vary greatly in 

thickness owing to an ancient period of erosion. Beneath 

parts of the coastal plain of the refuge, the Ellesmerian 

sequence probably is as thick as 5,000 feet. In the eastern 

two-thirds of the refuge, the rocks are caught up in an 

"overthrust" belt featuring complicated folds and faults. 

Figure 17 shows, for one of the reservoir rock units, some

142

70"

69

Bay

Sea

.,£_amden Bay

0 18 MILES i i i

Northern extent of 

Brooks Range 2,088" 

faulting affecting

the Lisburne Group \ 2,217 \ '' ll

2305*

ZONE OF TRUNCATION

1002 AREA

 Angun 

>Ppint

2.500 <V

Brooks Range

2J800

2.500

CONTROL POINT SHOWING THICKNESS 

OF LISBURNE GROUP, IN FEET

 WELL

X OUTCROP

1,500. CONTOUR OF THICKNESS

OF LISBURNE GROUP, IN FEET

COASTAL PLAIN AREA 

MOUNTAINOUS AREA

Figure 17. Regional and local geologic trends of the Lisburne Group in the Arctic National Wildlife Refuge of Alaska. 

Modified from U.S. Department of the Interior (1987, p. 56).

26 National Energy Resource Issues
70' 1

69

HIGHLY DEFORMED MESOZOIC AND 

TERTIARY ROCKS. MAY HAVE 

PETROLEUM POTENTIAL

MONOCLINAL NORTH-DIPPING 

STRATA. MAY HAVE PETROLEUM 

POTENTIAL

ANTICLINE

SYNCLINE

THRUST FAULT

COASTAL PLAIN AREA 

MOUNTAINOUS AREA

Figure 18. Generalized structural trends in rocks in the Arctic National Wildlife Refuge of Alaska. Modified from U.S. 

Department of the Interior (1987, p. 60).

of the information available from USGS regional geological surveys and the inferences that such knowledge 

permits about the continuity of the unit beneath the 

coastal plain. Without information from drilling, inferences are limited with regard to exactly how much of the 

Ellesmerian sequence is present, and important details 

such as organic content and its level of alteration must be 

either assumed or extrapolated from Prudhoe Bay and 

other drilled areas outside the refuge and from very 

limited surface information.

The Ellesmerian sequence is overlain by a very 

thick group of rocks named the Brookian sequence. 

Although this sequence is highly prospective to the east in 

Canada, it is not as promising for oil and gas in the refuge 

area as the Ellesmerian sequence is. Some petroleum 

source rocks and potential reservoir rocks do occur, 

however, in the Brookian sequence. Surface observations 

and seismic data indicate numerous fold and fault structures that are potential exploration targets, and, in parts of

the area, petroleum seeps have been observed. Figure 18 

shows a highly generalized structural geologic interpretation of the Brookian sequence based on available seismic 

and regional geologic data.

Seven different plays that is, areas having particular sets of geologic characteristics favorable for oil and gas 

occurrences were identified by the USGS. From these 

plays, in-place oil and gas resources were assessed. 

According to these estimates, there is a 95-percent likelihood that the assessed area contains more than 4.8 BBO 

and 11.5 TCFG and a 5-percent likelihood of more than 

29.4 BBO and 64.5 TCFG; the mean resource is 13.8 

BBO and 31.3 TCFG. Twenty-six prospects within the 

seven plays were delineated and assessed to estimate how 

much of the in-place resource might be recoverable (fig. 

19). This assessment by the Bureau of Land Management 

included consideration of technological and economic 

factors that might limit extraction of the total resource 

inferred by the USGS for each prospect. It was estimated

Petroleum Resources 27
148' 142

70" -

69

MEAN ESTIMATE

OIL IN PLACE GAS IN PLACE

(BBO) (TCFG)

BLOCK A 5.5 12 7

BLOCK B 1.5 2.9

BLOCK C 5.1 11.5

BLOCK D 1.6 4.2

DISTRIBUTION OF GAS IS VER 

SIMILAR TO THAT OF OIL

APPROXIMATE DISTRIBUTION 

OF IN-PLACE OIL

SEISMICALLY MAPPED 

PROSPECTS (1-26)

RESOURCE BLOCKS (A-D) 

OF THE 1002 AREA

COASTAL PLAIN AREA 

MOUNTAINOUS AREA

Figure 19. Twenty-six prospects (numbers) in the coastal plain area (Section 1002) of the Arctic National Wildlife Refuge 

were delineated and assessed for their hydrocarbon potential, primarily by using geophysical (seismic) methods. Oil and 

gas resources were estimated for four geographic resource blocks (letters). Modified from U.S. Department of the Interior 

(1987, p. 49, 68).

that, if economically recoverable oil is present (the likelihood of which was estimated to be about 20 percent), 

there is a 95-percent likelihood for more than 0.6 BBO 

and a 5-percent chance for more than 9.2 BBO, the mean 

being 3.2 BBO. There is a very small likelihood that the 

two largest prospects might contain economically recoverable oil in amounts rivaling Prudhoe Bay. Recoverable 

gas resources were not estimated, because a gas delivery

system was judged not likely to become available in the 

foreseeable future. Overall, the favorable setting and 

petroleum geology of this large area indicate that the 

Arctic National Wildlife Refuge is one of the most important prospective undrilled areas in the United States. The 

study, mandated by Congress, is a particularly apt example of geologic knowledge's being recognized as basic to 

national energy policy decisions.

28 National Energy Resource Issues
COAL RESOURCES

The United States is rich in coal resources. Today, 

coal provides only about 24 percent of the total energy 

consumed in the United States (fig. 1), but, as conventional oil and gas become scarcer and more expensive, 

coal will play an ever-increasing role in the energy future 

of the United States. Current levels of coal utilization, 

however, have given rise to an array of problems and 

issues, and an increase in coal use surely will bring 

increased attention to those concerns. Many factors come 

into play in considering how much of the large resource 

base may ever be available. A very large percentage of the 

total resource will never be used because of a variety of 

economic and technical limits and legal restrictions. Coal 

quality is an especially important limiting factor on coal 

use. '

Coal is, in many ways, a difficult fuel to use. Its 

mining disturbs the environment. Its transport is expensive and often adversely affects communities along transport routes. Much of the coal burned by utilities must be 

cleaned before burning; the flue gases commonly must be 

scrubbed of sulfur and other noxious components after 

burning. Even with such treatments, applied at considerable cost, coal combustion remains a major contributor to 

air pollution and acid rain. Waste materials resulting from 

coal combustion and the spoil piles and disrupted ground 

of coal mines are sources of noxious chemical elements 

that may be mobilized by rainwater leaching to contaminate surface and ground water.

A wide range of environmental problems associated 

with coal mining and utilization is shown in figure 20. 

Many of these problems are regulated at State and 

Federal levels, and many represent economic and technological impediments to full utilization of coal resources. 

Another coal issue concerns the vast amounts of coal on 

Federal lands and the appropriate use of those lands and 

resources.

Given the unavoidable concerns that accompany the 

benefits of America's coal riches and the plans to expand 

the role of coal, comprehensive geologic information is 

needed about the wide variability of these resources. Such 

information includes the amounts and locations of various 

types of coals, their suitability for different extraction 

methods and uses, and their accessibility to mining or 

in-place uses such as gasification or liquefaction. Knowledge of the physical character, chemistry, and mineralogy 

of coal is needed to gauge the potential for, and to 

determine how to deal with, environmental or technological problems associated with coal extraction and use. 

Such information will help improve technologies of coal 

mining, cleaning and burning, and synthetic fuel conversion and will provide an informed basis for the policy and 

economic decisions that inevitably will be required by 

increased coal usage.

COAL RESOURCES AND RESERVES IN 

NATIONAL PERSPECTIVE

Current annual U.S. production of coal is about 890 

million tons. About 85 percent of this coal is used by 

utilities to generate electricity, and coal provides about 58 

percent of the Nation's electricity. Projections of growth in 

markets for coal tend to focus on electricity generation 

and suggest that, by 1995, coal consumption in the United 

States will be about 1 billion tons per year (U.S. Department of Energy/Energy Information Administration, 

1986). These projections are greatly affected by the 

course of oil and gas prices and availability and by the 

future of nuclear power, and they typically do not include 

much use of coal for either synthetic fuels or petrochemicals, although some demand in these areas could develop 

quickly if petroleum availability were curtailed.

In any case, current domestic coal usage is very 

small in comparison with amounts usually quoted for 

domestic coal resources. In 1974, the USGS estimated the 

coal resources of the conterminous United States, in beds 

thicker than 14 inches and at depths shallower than 6,000 

feet, to be about 4 trillion tons (Averitt, 1975, p. 1). (Coal 

resource data for Alaska are incomplete, but rough 

calculations indicate that Alaska's coal resources may at 

least equal those of the conterminous States. Alaskan 

coal, however, cannot be economically delivered to markets in the conterminous United States, and U.S. coal 

resources for the foreseeable future generally are 

assumed to be the 4 trillion tons estimated to exist in the 

conterminous United States.)

The estimated resource base includes coals from 

many sedimentary basins across the United States (fig. 

21). These coals vary considerably in heat content, quality 

factors such as sulfur, nitrogen, and ash content, and 

accessibility factors such as depth, thickness, land use 

restrictions, and distance from markets. But, before the 

effects of these variations are considered, it is important 

to understand what is included in the 4-trillion-ton estimate of potential resources.

Figure 22 illustrates the various components of the 

estimated total coal resource and shows what parts of the 

resource are likely to be excluded from practical consideration. For example, less than half of the estimated coal 

resource (1.8 trillion tons) of 1974 is considered identified that is, relatively certain to occur on the basis of 

mapping, drilling, and relatively limited extrapolation 

beyond points of data. The other, larger part of the 

estimated resource is considered hypothetical that is, 

projected across basins at depth, far beyond points of 

data, on the basis of geologic reasoning about regional 

geology and probable favorable conditions for the occurrence of coal.

Coal Resources 29
Polycyclic organic material

AIR

Dust

Sulfur 

Particles CO compounds

\ ! /

Polycyclic

Trace elements Radionuclides organic material 

Polycyclic >"~~-\^_^_^ | 

organic material ^~~~~^-~. I ^ QQ

Thermal 

discharge

Fumes from fires

I Ash Sludge

\___J Beneficiation

Erosion 

Flood danger Underground 

mine

Waste 

disposal 

Waste problem

disposal 

problem

Slurry pipeline

Land use

Changes and disruption, 

ecological displacement

Discharge

Water consumption Water consumption

f Leaehates

WATER Acid mine drainage

Sedimentation

Chemical pollutants

Trace metals

Dissolved and suspended solids

Dissolved and 

suspended solids

Thermal discharge, 

dissolved solids

Figure 20.

(1979).

Environmental disturbances resulting from coal-related activities. From Office of Technology Assessment

The identified resource is further divided into a 

larger inferred category and a smaller demonstrated 

category. The inferred portion is loosely constrained by 

geologic observations and involves extrapolation techniques that vary from geologist to geologist and according 

to custom from State to State. The demonstrated portion 

also is poorly controlled because of nonspecific definitions used in earlier studies and because, from State to 

State, the boundary between demonstrated and inferred 

coal is variously 0.25 to 2.0 miles from actual data points.

Some coals included in the demonstrated resource 

are too shallow, too deep, too thin, or too thick to be

mined effectively and economically. Coal mined or lost in 

mining is removed next from the remaining coal resource, 

and the resource is then further reduced by 20 percent to 

account for restrictions on land use or mining. This 

reduction factor, however, may be too low. An inventory 

of surface development and other restrictions for a small 

area of western Kentucky indicates that 20 percent of the 

coal land is off limits to mining. In the Powder River basin 

of Wyoming, various restrictions currently reduce coal 

availability by about 16 percent, but economic projections 

indicate that, in the future, only about 50 percent of the 

available coal will actually be available as the result of

30 National Energy Resource Issues
SULFUR NITROGEN

DIOXIDE DIOXIDE

2.1 3.8

4.1 

9.1 

5.4 

3.8 

1.8 

4.8

3.4

3.5 

3.5 

4.0 

3.5 

3.4

Anthracite 

Bituminous 

Subbituminous 

Lignite

Figure 21. Coal fields of the United States and nitrogen dioxide and sulfur dioxide emissions (in pounds per million Btu) 

for coal from some of these fields. Modified from M.D. Carter (written communication, 1986) and J.H. Medlin and P.O. 

Simon (written communication, 1986).

restrictions (see Focus, "Regional availability and economics of coal," p. 44). Finally, as much as 50 percent of 

the coal left in the estimate may be lost in future mining, 

depending on the kind of mining.

The net result of all these restrictions and reductions is that possibly less than one-twentieth of the 4 

trillion tons of coal originally estimated as conterminous 

U.S. resources may actually be available for commercial 

production (fig. 22). Of course, many billions of tons of 

additional usable coal may exist in the inferred and 

hypothetical categories, but these amounts are not known. 

On the other hand, heat content, quality factors, and 

locations of different coals relative to markets have not 

yet been considered in this discussion, and they certainly 

reduce the overall amount of coal economically available 

and usable at the present time.

A closer look at coal availability begins with the 

recognition that the right kind of coal is not necessarily in 

the right place. For example, although the use of lowsulfur coal can reduce the sulfur oxide (SO2 ) emissions 

from powerplants that contribute to acid rain, the principal known resources of low-sulfur coal are in the Powder 

River basin of Wyoming, far from the major markets of 

the Eastern United States. In addition to transportation 

costs, the use of western coal in eastern markets requires

paying a heat (Btu) premium, because western coals 

generally are of low rank (subbituminous) and contain 

only about two-thirds to three-quarters of the heat value 

of eastern coals. In terms of average sulfur content, very 

few basins in the United States contain coal that complies 

with government regulations on coal burning (fig. 23), at 

least without expensive precombustion or postcombustion 

treatment. If concerns about clean air result in further 

tightening of SO2 emission standards, no significant 

amount of coal will be available in the United States that 

can be burned without treatment.

In areas long associated with coal mining, the 

resources that actually will be available (that is, the 

minable reserves) may be much smaller than most investigators had supposed. Much of the original coal resource 

in these areas has already been mined or lost in mining, 

and much of the remaining coal is not suitable for mining 

or marketing or has surface developments or restrictions 

that preclude mining. The Focus section on a well-known 

source of low-sulfur coal in eastern Kentucky (p. 36) 

suggests that only about one-eighth of the original coal 

resource remains as recoverable reserves for future mining. Because of the growing realization that there are 

limits on coal recoverability, the emphasis in USGS and 

State coal programs is shifting from collecting data on

Coal Resources 31
Total original coal resource in ground 100%

Identified 45% Hypothetical 55%

Demonstrated 18% Inferred 27%

Shallow 16% Deep 2%

Thick 13% Thin 3%

Remaining 10% Mined and lost in mining 3%

Accessible 8% Restricted by land use, legal, technolog 

and natural constraints 2%

Producible 4% Lost In mining (future) 4%

102030405060708090100

Figure 22. Components of the estimated coal resource of the United States. Modified from M.D. Carter (written communication, 1986).

O 

se.

5 - 

4- 

3- 

2- 

1 - 

0-

1

ILLINOIS 

BASIN

FORT i ,

 1 BASIN"4

>AN JUA 

BASI

N 

N

k 

RATOI*

WIS

INT1

BAi

"^^~^

TERN

.RIOR

IN

NORTHERN 

APPAIACHIAT 

BASIN

BLACK

WARRIOR 

BASIN i-<S

 -S$OTHER?v

M|SA_^AFPALACH

" \ BASIN

I 1

0 11 12 1.3 14 \

3

" =

c ; 0 «

1 .2

l_ '~

a- j.

^cT °~

« ^ 

jj «

°1 *

|AN_^

1

15

THOUSANDS OF Btu PER POUND*;

Figure 23. Very few coal-bearing areas in the 

United States are likely to contain large quantities of 

coal that will meet either new-source performance 

standards (NSPS) or revised new-source performance standards (RNSPS) for sulfur emissions without some utilization modification. SO2 emissions are 

limited to 1.2 pounds per million Btu (NSPS), and a 

90-percent reduction in potential emissions is 

required except when emissions are less than 0.6 

pound per million Btu; in this case, a 70-percent 

reduction in potential emissions is required. Solid circles represent average sulfur and Btu values for coal 

from major coal-bearing regions; bars represent one 

standard deviation about these values. Analytical 

data are for whole coal samples, as received at the 

testing laboratory directly from the mine. Modified 

from F.T. Dulong (written communication, 1985). 

Source performance standards from Environmental 

Protection Agency (1979).

32 National Energy Resource Issues
resources to categorizing reserves that is, inventorying 

the coal likely to be accessible for recovery and categorizing this coal in terms of its probable suitability for 

various end uses.

The accessibility of coal for underground mining 

and the ultimate recoverable amount may be limited if 

more than one coal bed occurs in an area. In such 

situations, coal extraction commonly is restricted because 

mining one bed tends to render the beds above or below 

unminable. Both the collapse of rock above the mined bed 

and the uneven distribution of overburden weight through 

the mined bed to underlying beds can result in the 

effective loss of large resources of coal. In areas where 

underground mining has occurred in shallow beds beneath 

relatively weak overburden rocks, collapse of rocks overlying the coal bed eventually may extend to the surface. 

This collapse produces significant disruption of land and 

hazards to life and property, including underground mine 

fires. The Focus section on coal mine subsidence hazards 

(p. 42) describes problems related to subsidence, including mine fires, and notes the geologic factors that may be 

involved in choosing between underground and strip 

mining.

COAL QUALITY AS A POLICY AND 

ECONOMIC ISSUE

Beyond all the factors described so far, coal quality 

is and will remain the principal constraint on coal utilization. Coal quality is defined as the combination of various 

characteristics that contribute to heat content, sulfur 

oxide and other emissions levels, problems with combustion and waste-product handling, and many other factors. 

It affects how coal can be used that is, directly by 

burning, in mixtures with other fuels, or by conversion to 

synthetic fuels or petrochemicals.

The quality aspects of coal place coal combustion at 

the center of national policy concerns about air pollution 

and acid rain. Policymakers, economists, and scientists 

disagree greatly about the specific causes, distribution, 

and extent of problems produced by coal burning and the 

most effective strategies to mitigate adverse effects of 

coal burning. Better information on both coal itself and 

the effects of its burning is needed to properly address 

these problems, problems that will only broaden as coal 

use increases. For example, if sulfur and nitrogen oxide 

emissions were adequately controlled and coal usage thus 

increased, the amounts of other noxious components in 

coal such as arsenic, lead, fluorine, and chlorine might 

reach harmful levels of concentration in the environment. 

In addition, removing pollutants from one medium (air) 

through flue gas desulfurization and transferring them to 

other media (solid waste and water) simply create other 

problems. If sulfur and other undesirable chemical elements are disposed of with the coal ash, then water 

percolating through the waste solids may be acidified and

may mobilize pollutants into the environment. Contaminants in scrubber sludge also may create disposal and 

ground-water problems.

At the practical level of efficient and economical 

coal use, the physical, chemical, and mineralogical characteristics of coal are critical factors, whether the coal is 

burned or converted to other hydrocarbon forms. Coal is 

a complex and heterogeneous mixture of organic and 

inorganic constituents, and the composition of this mixture varies significantly between regions with regard, for 

example, to rank or sulfur and nitrogen emissions potential (fig. 21). The chemistry and mineralogy of coal also 

commonly vary over short distances in a single bed and 

between different coal beds in any given mining locality 

(fig. 24).

Most coal-fired powerplants are built for a particular "design fuel" of specified physical and chemical characteristics, and characteristics such as the Btu, sulfur, ash, 

and volatile-matter content and the chemistry and mineralogy of the inorganic fraction are critical in the plant 

design. For example, switching from a high-Btu coal to a 

lower Btu coal that contains less sulfur is an obvious, 

though possibly not economical, way for a utility to meet 

clean-air standards, but not if the replacement coal does 

not fit the plant design. In the combustion process, 

variations in coal properties and differences in burning 

characteristics can cause major and costly malfunctions in 

equipment, such as corrosion, slagging, and fouling of 

boiler tubes, and changes in the volatile content of coal 

can require changes in flue gas treatment. If the coal must 

be cleaned to remove sulfur compounds before burning, 

the cleaning process must be designed according to the 

properties and mineralogy of the feedstock coal.

Modifying plants to handle different coals or living 

with the results of undesired coal variations can be 

economically burdensome. One utility company estimated 

that better control on sulfur and ash contents of coal 

could improve boiler availability by 5 percent (about $1.5 

million per year for a 650-megawatt unit). Another utility 

company calculated that, for each 1-percent increase in 

coal ash content above the plant design level, plant 

availability will be reduced by 1 percent. A third company 

found that an increase in coal ash content from 15 to 20 

percent would cost an additional $2.6 million per year. 

Recently, a large western mining company encountered 

an unexpected chemical change in the coal being mined, 

and the coal could not be shipped to the customer utility; 

4 million tons of production reportedly was lost before a 

new, acceptable reserve was found. Numerous similar 

examples reflect problems of coal quality variation and 

indicate the importance of having reliable geologic information on coal in advance of each step of mining, cleaning 

and sizing, and utilization.

Coal Resources 33
COAL A

36" £

COAL B .

Upper 25" 

bench 

Middle 10" 

bench

Lower 22" 

bench

Figure 24. Variability of sulfur and ash contents (in percent) of coal within a single coal bed (coal B) and between coal 

beds (coals A and B). Vertical lines represent cored drilled holes. Modified from P.C. Lyons (written communication, 1984).

THE ROLE OF GEOLOGIC INFORMATION

Coal is the compressed and altered residue of plants 

that grow in freshwater or brackish-water swamps. As the 

plant residues accumulate, they are transformed into 

peat. Later, during burial by sediments, the residues are 

altered chemically and physically into coal. Widely varying amounts of sand, silt, and mud are washed into the 

peat swamps, and this admixed sediment forms the bulk of 

the ash in burned coal.

The processes active in forming coal, as well as 

those that affect the coal after it forms, vary according to 

the environment of the original peat swamp and the 

subsequent geologic setting of the coal. These variations 

in processes commonly result in variations in physical 

character, chemistry, and mineralogy (figs. 21, 24). Modern geologic studies of coal typically attempt to decipher 

the setting and depositional environment of the original 

peat deposit, including paleobotanical and paleoclimatic 

aspects (see Focus, "Coal quality and the origins of coal," 

p. 38), and are fundamental to the characterization of coal 

reserves in specific areas. The studies also provide a basis 

for modeling coal-bearing areas to predict the occurrence 

and quality of coal beyond current exploration boundaries

in an attempt to determine both tomorrow's reserves and 

the problems that producing those reserves might bring.

Two major gaps in knowledge limit the understanding of coal quality. First, the chemical nature of coal is not 

well understood, and the processes of coal formation and 

interactions among various coal constituents need further 

study. Second, current knowledge is based on a relatively 

small number of samples from coal beds that either have 

been mined out or are currently being mined, and few 

data are available for deeper coals yet to be mined. Figure 

25 shows the distribution of sample information for a 

major Appalachian coal bed and illustrates the problem 

of coal sampling. Although obtaining samples from a coal 

bed in advance of mining is both costly and difficult, such 

samples are required to confirm the ability to predict coal 

quality on the basis of geologic understanding. As both 

that understanding and the associated modeling of coal 

deposits improve, fewer samples will be needed to make 

reliable predictions about reserves and resources for 

industry and government planning.

An important component of current studies of coal 

reserves and resources is the USGS National Coal 

Resources Data System (NCRDS). This computerized 

bank of information on coal and its enclosing rocks is the

34 National Energy Resource Issues
Figure 25. Distribution of sampling information (solid circles) in the Pittsburgh coal bed. Most samples for which data are 

available are from the edges of the main deposit or from isolated pockets of the main deposit (that is, areas that have been 

mined out or currently are being mined). Very few, if any, samples are available from the more deeply buried parts of the 

coal bed. Sample localities shown outside the outline of the coal bed represent very small pockets of the main bed. 

Modified from J.H. Medlin and P.O. Simon (written communication, 1984).

product of a continuing effort by the USGS and State 

agencies in 20 coal-producing States. Statistical analysis 

and mapping routines can be applied to large amounts of 

data to aid in geologic research and resource assessment. 

For example, this national data set was used in the 

discovery of a previously unrecognized and apparently 

fundamental aspect of sulfur occurrence in coal (see 

Focus, "Sulfur in coal," p. 47). Although the NCRDS data 

bank and analytical procedures can be readily applied to 

obtain detailed delineations of area reserves, updated 

information on the physical and chemical characteristics 

of coal is needed to support such studies properly.

NATIONAL RESEARCH AGENDA

At a national meeting on coal quality convened by 

the USGS in 1985, experts from industry, government, 

and academia developed a proposed national agenda for 

research on coal quality (Garbini and Schweinfurth, 

1986). Cooperative work toward fulfilling this agenda has 

begun but is in its infancy, considering the scope of the 

problem and the importance of the subject. Studies of 

basic coal science and the characterization of coal 

resources with respect to quality, quantity, and accessibility could allow development of realistic options for 

expanded coal use and more reliable prediction of the 

consequences of such expansion. They could also provide 

a framework for decisions concerning extraction and 

preparation methods that is, whether to clean, blend, 

crush, or size coal and by what methods and they can 

form the basis for planning coal feedstock sources and 

specifications. The information gained from these studies 

will undergird efforts to improve technologies for cleaning, burning, and converting coal and perhaps for gasifying or liquefying coal in place.

On the basis of knowledge gained from these studies, regional models of potential sulfur emissions can be 

constructed for both the short- and the long-term future. 

Coal deposit and coal accessibility models that include 

accurate and comprehensive information about coal quality and coal availability could allow formulation of policies 

and regulations strategically directed toward solving 

important long-term problems of coal use and avoiding 

unnecessary or inappropriate restrictions on coal use. 

The costs of expanding both basic and applied research on 

coal are small in comparison with the costs of technologic 

mistakes or of promulgating and enforcing regulations 

that fail to resolve problems surrounding coal use.

Coal Resources 35
Focus: Coal Resource and Reserve Characterization in Eastern Kentucky

The Eastern Kentucky coal field is one of the most 

productive coal-producing areas in the United States and 

probably in the world. It produces one-sixth of the coal 

mined in the United States and contains one-half of the 

operating coal mines. Coal has been mined in eastern 

Kentucky for 200 years, and 7.5 billion tons of coal has 

been either mined or lost in mining. Although the remaining resources of the field are estimated at 56.6 billion 

tons, some authorities believe that as few as 10 billion tons 

of economically recoverable coal remain.

Kentucky's legacy as one of the foremost coalproducing States has produced a culture, infrastructure, 

and business climate favorable to coal mining that paradoxically now poses a threat to future mining. Many of 

Kentucky's remaining resources are adjacent, superjacent, or subjacent to mined-out areas, and both government mining regulations and mining engineering practices 

preclude the mining of coal too close to existing mines. 

Although no attempt has been made to assess the impact 

of past mining on future potential, the extent of past 

mining suggests that the amount of affected coal is quite 

large.

In 1983, the Kentucky Geological Survey completed 

an assessment of Kentucky's coal resources. Considerable 

effort was spent mapping the thickness and extent of each 

coal bed, quantifying resources by thickness, and qualifying the estimates on the basis of distances from actual coal 

measurements. Approximately 25,000 coal thickness measurements were computerized for easy plotting and calculation of resources; this work was partly supported by the 

USGS. The data base was used to prepare 3,500 coal 

maps for 40 coal beds and coal bed splits thicker than 14 

inches. Resource reports for six coal resource districts 

have been published, and the supporting data are being 

published.

The remaining resources of the field were estimated 

by subtracting the total coal mined times two from the 

original resource. The total coal mined times two roughly 

approximates the sum of coal actually mined and coal left 

in the ground as pillars or lost in cleaning and represents 

the commonly accepted recovery factor of 50 percent. 

Many factors important to understanding the fuel supply 

potential of these resources were not considered, including overburden ratio, depth, quality, and minability, which 

includes factors such as coal bed continuity, dip and 

splitting of the bed, and roof and floor quality. Consequently, the estimate of remaining coal resources in the 

Eastern Kentucky coal field includes large amounts of 

coal currently not economically or legally minable. The 

estimate of 56.6 billion tons for remaining resources in 

the field is overly optimistic and potentially misleading

without appropriate qualifications, and research has 

begun to characterize remaining reserves.

Maps of mined-out areas that were made by coalmining companies are now being used to refine the 

Kentucky Geological Survey's coal resource maps. The 

locations of mined-out areas, legal easements for roads, 

towns and certain designated public lands, and oil and 

gas wells (near which mining cannot occur) are overlaid 

on coal resource maps. After remaining resources have 

been limited to coal that is legally accessible, modern 

mining and economic criteria can be applied to estimate 

the remaining reserves according to specified costs. 

Studies of test sites in the Eastern Kentucky coal field 

are expected to allow extrapolation of reserve estimates 

to the entire coal field and perhaps to parts of West 

Virginia, Virginia, and Tennessee. Preliminary results 

from an area of Pike County, Kentucky, indicate that 

about 250 million tons, or 31 percent, of the original 

resource in one major coal bed has been mined or lost 

in mining, and as much as 350 million tons, or 44 

percent, may not be accessible because of interference 

resulting from prior mining and various physical and 

legal obstacles to future mining (fig. 26, table 1). Only 

about 25 percent of the original 800 million tons in 

place remains as minable reserves, and only a little 

more than one-half of that amount has a high probabilTable 1. Preliminary remaining coal reserve characterization in an area of Pike County, Kentucky 

[Reserve characterization map shown in figure 26]

Amount of

coal, in 

millions of 

_________________ ___ ___ __ short tons

Estimated original resources 800 

Mined out and lost in mining -250 

Geologic constraints -150 

(high ash content, cutouts, bad roof, too

thin).

Legal constraints 50 

Interference -150 

(mine barriers, ownership patterns, oil 

and gas wells).

Estimated remaining reserves in ground 200 

"Surface" recovery factor 40

(80 percent on 50 million tons). 

"Underground" recovery factor 75

(50 percent on 150 million tons).

Estimated remaining potentially 115 

recoverable reserves 1______________________

1 Not all potentially recoverable resources are economically 

minable. The ultimate decision to mine depends on factors such as 

ash fusion, chlorine content, location of transportation systems and 

cleaning facilities, and others not considered in this analysis.

36 National Energy Resource Issues
GEOLOGIC CONDITIONS

Channel cutting 

out the coal bed

Coal with splits 

and high ash

Coal less than 

28 inches thick

Coal removed 

by erosion

MANMADE CONDITIONS

Strip mine

Subsurface mine

Remaining coal of 

apparent minable 

quality

Drainage, dashed 

where intermittent

2 MILES

Figure 26. Various factors, both geologic and man induced, affect the future minability or extraction of coal resources. 

This map of a small area in Pike County, Kentucky, uses representative measurements from the county to show how these 

factors combine to severely limit the amount of coal suitable for mining.

ity of being recovered. Other economic, engineering, coal 

quality, land ownership, and environmental factors will 

determine what ultimately will be produced.

Research has just begun to characterize the 

remaining coal reserves of the Eastern Kentucky coal 

field and to assess the impact of past mining, legal 

restrictions, oil and gas wells, geologic obstacles, and

mining engineering and economic criteria. Because 

many of the Nation's energy, electricity generation, mining, transportation, and State government plans are 

based on the assumed availability of economically minable coal, a characterization of the remaining reserves 

as either fact or wishful thinking is fundamental toward 

informed consideration of both plans and policy.

Coal Resources 37
Focus: Coal Quality and the Origins of Coal

Variations in coal quality result from the chemistry 

of the peat-forming environment, interactions among local 

sedimentary processes during peat formation, and chemical changes that occur after burial. Variations in coal 

quality have been documented in a detailed study (Stanton and others, 1986) of the Upper Freeport coal bed 

(Pennsylvanian age) in mines near Homer City, Pa., and a 

companion study of two coal beds in the Powder River 

basin of Wyoming.

The study of the Upper Freeport coal bed was done 

cooperatively by the USGS, the Environmental Protection 

Agency, the Pennsylvania Electric Corporation, and the 

New York State Electric and Gas Corporation. The entire 

block of coal reserves in these mines was studied with the 

aim of identifying and then predicting changes in coal 

quality, so that mining plans might be designed to minimize quality variations in the coal product delivered to 

powerplants.

The Upper Freeport coal bed contains discrete coal 

zones, or fades, that are characterized by distinctive 

associations and concentrations of compressed plant materials (macerals) and minerals. These coal bed facies were 

mapped over an area of 120 square miles in west-central 

Pennsylvania. Where the coal bed is thickest, it averages 

83 inches and contains 8 to 10 facies; in other areas, the 

bed averages about 48 inches and generally is composed 

of 4 facies. Figure 27 shows a schematic three-dimensional 

view of part of the coal bed. Once the coal facies were 

identified, they could be traced throughout the coal 

reserve. Zones of sandstone that developed during the 

peat-forming stage also were identified and their distribution predicted. The amount of ash-forming minerals in 

the coal bed increases substantially near these sandstone 

zones, the result being areas that should be avoided in 

mining. Other quality parameters, such as sulfur content, 

were found to be associated with individual coal facies, 

which have specific coal washability characteristics.

Areal distribution patterns of ash and sulfur for 

each coal bed facies indicate different physical and biochemical conditions during peat formation that affected 

both the type and amount of plant materials and minerals. 

Three sets of conditions were inferred for the origin of 

different coal bed facies of the Upper Freeport coal, 

consistent with interpretations of modern peat formation 

based on the interaction of climate, plant types, rainfall, 

ground-water chemistry, nutrient supply, and sedimentation. The resulting conceptual model provides a means to 

evaluate and predict more, precisely, in advance of mining, 

the variability of coal resource or reserve quality.

Depositional controls on peat-forming environments that produce thick (greater than 30 feet) coal beds

can be inferred from relationships among coal bed geometry, organic material composition, and associated rock 

types. A study of these relationships within sedimentary 

sequences associated with the Wyodak-Anderson (Paleocene age) and the Felix (Eocene age) subbituminous coal 

beds in the Powder River basin of Wyoming suggests two 

modes of peat accumulation, both of which are controlled 

by patterns of stream movement and sediment deposition 

by streams in swamp areas. The Wyodak-Anderson peat is 

interpreted to have formed in restricted parts of a flood 

plain that were separated from one another by channels of 

a braided stream. The channels and associated sediments 

maintained their positions through time because they 

were confined by thick deposits of raised or domed 

Wyodak-Anderson peat. In contrast, the Felix coal bed is 

interpreted to have formed as a raised but widespread 

peat on an abandoned platform of sands deposited by a 

meandering stream (fig. 28).

Other studies of coal quality by the USGS in 

cooperation with State surveys are producing new, practical results. Data from reconnaissance sampling of coal 

beds and rocks throughout the main coal-bearing geologic sequence of the central Appalachians show a distinctive pattern of ash and sulfur contents from the lowest 

to the highest coal beds in the sequence (fig. 29, table 2). 

Coal beds in the lower, or older, part of the sequence 

typically are low in sulfur and ash, whereas coal beds in 

the upper, or younger, part are high in sulfur and ash. 

This variation in coal chemistry with time is interpreted to 

be related to changing climate and conditions (or setting) 

of peat accumulation in swamps. The upper coal beds are 

impure and of relatively lower quality because their

Table 2. Characteristics of paleopeat formation and coal 

quality in coal beds in the central Appalachian basin

[Modified from Cecil and others (1985, p. 218)]

Pennsylvanian-Permian(?)

formation (series)

Kanawha 

New River 

Pocahontas

Dunkard 

Monongahela 

Conemaugh 

Charleston/ 

Allegheny

... Ever-wet Seasonal

tropical. tropical.

Paleopeat formation Rainwater Surface and

water source. . ground water.

Spatial form of Domed Planar

paleopeat deposits.

Coal quality Low ash, High ash,

low sulfur. high sulfur.

38 National Energy Resource Issues
s05

OT 

0]

 a 

cc

I

i

I

Q. 

Q.

13

"$c

a

CM

0)

D)

il

Coal Resources 39
FELIX COAL BED

PEAT ACCUMULATION

RESULTING COAL BED

WYODAK-ANDERSON COAL BED

PEAT ACCUMULATION

Finely laminated 

plant material

Woody lenses in 

vegetal groundmass

Woody peat (roots, 

stems, and stumps)

Coal

[ | Sand and sandstone

RESULTING COAL BEDS Fine-grained sediments 

and sedimentary 

rocks

0 10 KILOMETERS

Figure 28. Environments of deposition of coal of the Felix and Wyodak-Anderson subbituminous coal beds. Modified 

from P.O. Warwick and R.W. Stanton (written communication, 1987).

precursor peat formed in swamps fed by chemical-laden 

ground water and by surface water that contained relatively large amounts of mineral matter. This setting 

produced dominantly planar peat accumulations accompanied by heterogeneous plant communities. The lower 

coal beds are cleaner and of higher quality because they 

formed from domed peat deposits that received mostly 

rainwater nourishment and little sediment influx. The 

zoned plant communities that characterize this setting

produce a coal bed facies arrangement different from 

that formed by planar peat deposits.

Detailed coal quality studies are providing new 

understanding of the origin and development of coal, so 

that variations within and between coal beds can be 

identified, explained, and then extrapolated to make predictions about undrilled areas. The new insights provide 

a basis for better planning of coal mining, cleaning, and 

blending to obtain a preferred product.

40 National Energy Resource Issues
<u 

zu

x 

c

£m

"*ai

SERIES

Lower 

Permian (?)

Upper 

Pennsytvanian

Middle 

Pennsytvanian

Lower 

Pennsytvanian

FORMATION 

or

Dunkard

Monongahela

Conemaugh

Allegheny

Pottsville

Charleston

Kanawha

New River

^^^-^^-l_X^^^^«^-V»^y^-^v^~^-^X^r^_^-^^_^^.'^.^.

g

s?

^flmi

i i i i i i

01 2345

SULFUR, 

IN WEIGHT PERCENT

ASH, 

IN WEIGHT PERCENT RAINFALL / 

EVAPOTRANSPI RATION

Figure 29. Stratigraphic variations in ash and sulfur contents in coal beds of the central Appalachian basin and the ratio 

of rainfall to evapotranspiration as interpreted from lithology and coal quality of formations. Data from National Coal 

Resources Data System. Figure modified from Cecil and others (1985, p. 205, 210, 224).

Coal Resources 41
Focus: Coal Mine Subsidence Hazards

In areas where coal has been mined by underground methods, collapse of mine openings and related 

coal mine fires can cause serious and expensive hazards 

long after the mines have been abandoned. In many areas 

where underground mining was done in the 1800's and 

early 1900's, unmined coal pillars of variable size and 

spacing support the overlying rock and soil for decades or 

even centuries before yielding to cause gradual settling or 

sudden collapse at the surface.

When mine roofs collapse and the pillars crush or 

punch into the roof or floor rocks of the mine, depressions and cracks or pits eventually may form at the 

surface and pose a threat to life and property. The time 

required for hazards to develop after mining depends on 

the geologic properties of the rock, the depth of mining, 

and the method of mining. If most of the coal was 

removed, the rock commonly subsides gradually in a few

years, but, if pillars remain, pits may form above adjacent 

mine chambers decades or even centuries after the mines 

are abandoned.

Subsidence pits are common above abandoned 

underground mines in areas where the overburden is less 

than 10 to 15 times the thickness of coal mined (fig. 30). 

In areas where the caved material is carried away by 

ground-water flow, surface subsidence can occur at depths 

greater than 10 to 15 times the mined thickness. Subsidence depressions can occur at any depth above areas 

from which coal has been completely extracted and in 

which the minimum width of the mined cavity equals or 

exceeds the thickness of the overburden.

Subsidence is a nationwide problem. Results of a 

study by the U.S. Bureau of Mines (Johnson and Miller, 

1979) indicate that 7.1 million acres of land has been 

undermined in 25 States in the conterminous United

^ «fi£. *&.

Figure 30. Oblique aerial view of pits and troughs that formed by surface subsidence above abandoned coal mines 

located 6 miles north of Sheridan, Wyo. The mines were operated from the 1890's to the 1920's, and coal was mined from 

three different beds. In places, the mine workings are stacked above one another. The overburden comprises weak, soft 

rocks and is 15 to 150 feet thick. Pits and troughs located in draws draining into Goose Creek (near background) disrupt or 

divert surface water to old mine workings. The Bighorn Mountains are in the far background. From Dunrud and Osierwald 

(1980).

42 National Energy Resource Issues
States, of which 1.9 million acres already has been 

affected by subsidence. Of the 5.2 million acres of future 

potential subsidence, approximately 418,000 acres is near 

populated areas. The 10 States having the greatest areas 

(in acres) of potential subsidence (on the basis of underground production records) are Pennsylvania (151,000), 

West Virginia (89,100), Illinois (41,800), Kentucky 

(37,200), Ohio (21,800), Virginia (13,400), Alabama 

(11,700), Indiana (10,900), Colorado (6,300), and Tennessee (5,000). The total estimated cost of stabilizing land 

undermined by abandoned coal mines in the conterminous United States is $12.5 billion (1978 dollars) (Johnson and Miller, 1979).

In addition to subsidence problems, underground 

fires can destroy valuable coal resources and cause serious atmospheric pollution. The fires commonly start by 

spontaneous ignition when water and air enter abandoned 

mine workings through subsidence cracks or pits; they 

may start by careless dumping and burning of garbage in 

subsidence pits. The Bureau of Mines estimates that there 

are about 260 uncontrolled fires in abandoned mines in 

some 16 States; these fires threaten 760 million tons of 

coal and cause local atmospheric pollution and health 

hazards. The 10 States where the greatest amount of coal 

(in millions of tons) is threatened by fires in abandoned 

mines and inactive coal deposits are Montana (220), 

North Dakota (166), Colorado (100.5), Pennsylvania 

(91.3), Wyoming (81), Utah (45), Arizona (23), West 

Virginia (14.6), New Mexico (6.5), and Ohio (4.8).

USGS studies of the surface effects of past underground coal mining near Sheridan, Wyo., and in other 

areas of the Western United States indicate that underground mining of coal deposits located at strippable

depths eventually may damage the environment more 

than mining by modern surface methods, provided that 

proper restoration techniques are followed (Dunrud and 

Osterwald, 1980). In modern surface mining operations, 

the total land surface above the minable coal is sequentially removed, and, as the coal is removed, the overburden 

and topsoil are sequentially replaced and the surface 

regraded to the original landform and revegetated. Land 

disturbed by surface mining can be more easily returned 

to long-term use than can land underlain by shallow 

abandoned underground mines, and the resource recovery from surface mining typically is much greater than 

that from even modern underground mining procedures.

Detailed information on topography, geology, 

hydrology, and mining procedures is needed before 

existing and future subsidence hazards can be accurately assessed. Engineering geologic studies on the 

type, strength, and thickness of rocks above abandoned 

underground mines and a determination of the areal 

extent of abandoned mines are particularly important. 

Unfortunately, it is difficult to determine the extent of 

underground mines abandoned in the 1800's and early 

1900's, because mine maps and production records are 

unavailable or incomplete.

Experiences in populated areas underlain by 

abandoned underground coal mines such as the 

Denver-Boulder metropolitan area and Colorado 

Springs, Colo.; Scranton, Pa.; Rock Springs, \\tyo.; and 

Des Moines, Iowa indicate that the time and money 

spent on site studies and land use planning before surface development are much less than those spent on 

mitigation procedures after surface development.

Coal Resources 43
Focus: Regional Availability and Economics of Coal

Coal resources are more equally distributed across 

the United States than other fossil fuel resources are, but 

coal availability is affected by land access and land use 

restrictions, the sulfur content of the coal, and mining 

economics. Efforts to achieve clean-air standards by 

reducing sulfur emissions from utility plants have 

increased the demand for low-sulfur coal. High-Btu lowsulfur coal carries a price premium; much of this coal is in 

the Eastern United States and is extracted by underground mining. Low-Btu low-sulfur coal is abundant in 

the Western United States and typically is extracted by 

low-cost open-pit mining, but a significant amount of 

western coal is inaccessible because of land use restrictions and environmental concerns. Such concerns and the 

associated regulation of mining are particularly an issue 

with regard to large coal deposits within or near unique 

and highly valued natural areas.

The effects of local land use restrictions in important coal resource regions can be examined in relation to 

national coal distribution patterns and cost effects. A 

dynamic linear program model of the coal distribution 

network in the United States (243 demand regions, 100 

supply regions, and 5 transportation modes) has been 

developed by the USGS to estimate extraction, transportation, and sulfur removal costs for coal and to project the 

market effects of supply restrictions and consumption 

regulations. The program minimizes the costs of extraction, transportation, and cleaning subject to a set of 

constraints. For example, shipments cannot exceed supply, 

delivery must meet demands, sulfur discharges cannot 

exceed allowable limits, barged shipments cannot exceed 

waterway capacities, and transmission of minemouthgenerated electricity cannot exceed technical engineering 

limits.

The coal resources of the United States tend to have 

regional characteristics, such as rank (heat content), 

sulfur content, and number or continuity of beds. In 

addition, limiting factors, such as extraction and transportation costs, sulfur emission controls, and land use restrictions, tend to maintain a regional division into eastern, 

midwestern, and western areas of supply. The linear 

program was used to model demand and supply for 

Powder River coal, changes in intensity of Powder River 

coal use in the same markets over time, and the extent of 

new market penetration over time. The model is confined 

to the dominant Powder River coal source, the )\fyodak 

coal bed of Campbell County, Wyoming, in which 

overburden is less than 200 feet thick and strip mining is 

feasible. Figure 31 shows projected powerplant use of 

low-sulfur Powder River coal for the years 1990 and 2015. 

The model predicts that demand for this coal will expand 

from 155 million tons in 1990 to 468 million tons in 2015

in the markets served and that use of Powder River coal in 

midwestern and south-central markets will expand 

between 1990 and 2015.

If access to lands suitable for mining is unlimited, 

the model predicts that, by the year 2030, annual production of strip-mined Powder River coal will be 601 million 

tons and cumulative production will be 16.4 billion tons. 

Public land withdrawals and land use restrictions dictate, 

however, that only part of the coal will be available for 

future production. Figure 32 illustrates land use restrictions for Campbell County. Although only about one-third 

of the coal suitable for mining is likely to be legally 

restricted, a significant amount of the remaining coal is 

scattered among different owners or fragmented by land 

use restrictions and will not form logical mining units, or 

the land may have other uses or values deemed more 

important. It seems likely that a substantial portion of the 

potential coal resource of the area will never be exploited.

The effect of restrictions multiplies when it is also 

considered how much of the accessible coal will be 

available at different prices. The model has been used to 

compare cumulative coal production in the WyodakAnderson bed in Campbell County well into the next 

century and at different prices, for cases of both unlimited 

and limited (by land use restrictions) access. The model 

predicts that land use restrictions will reduce the available 

amount of the lowest cost coal by 6 billion tons and the 

available amount of higher cost coal (as high as $40 per 

ton) by almost 20 billion tons. When low-cost production 

from all of \\fyoming is modeled to compare projected 

output under existing land use restrictions in Campbell 

County with a hypothetical case in which no land use 

restrictions are imposed, the difference is remarkable. 

The model predicts that ^oming production will increase 

during the next 40 years but that, if restrictions are 

imposed, restricted production will begin to differ from 

unrestricted production after 2005. The difference in 

production projected to 2025 is more than 400 million 

tons (about 200 million tons of production with restrictions and 650 million tons without restrictions).

The State of Wyoming, which contains a large 

amount of Federal land, is a particularly good illustration 

of land use restrictions. Coal deposits in national parks, 

wilderness areas, and wildlife refuges cannot be mined, 

and, under current regulations, coal deposits near such

Figure 31. Predicted consumption of low-sulfur 

Powder River coal for powerplant use will increase 

from 155 to 468 million tons between 1990 (-4) and 

2015 (B) and use of Powder River coal in midwestern and south-central markets will increase.

44 National Energy Resource Issues
^m o - 100 

BBI 101 - 1,000

^ l 1,001 - 10,000

I I 10,001 - 50,000

IH 50,001 - 1,000,000

(IN THOUSANDS OF TONS)

0 400 MILES

I____I____L

B

Coal Resources 45
106'00 

45'flO

106'30'

44°30

44-00' -

restricted areas may never be mined. The model approach 

described shows that the economic effects of local land 

use restrictions reach into markets across the country and 

significantly change resource availability through time. 

Many types of restrictions, both regulatory and economic, 

apply to coal resources throughout the United States. The 

overall effect of land use restrictions on production is not 

now great but will increasingly influence production, 

price, and breadth of markets over the next 10 to 50 years 

in all parts of the United States. Other restrictions, such as 

stricter clean-air standards, will have greater and more 

immediate effects and can also be modeled to predict 

their ramifications.

43'30

10 MILES

Figure 32. Land use restrictions and unsuitability 

for mining, Campbell County, Wyoming. Red indicates areas in which coal development is restricted 

by competing land uses; green indicates areas in 

which coal development is acceptable pending further study of competing land uses; blue indicates 

areas of Federal coal leases.

46 National Energy Resource Issues
Focus: Sulfur in Coal New Insights on the Utilization Potential of High-Sulfur Coals

Although sulfur in coal varies from a few tenths of 

a percent to more than 12 percent of a coal by weight, 

coal typically is referred to as either high sulfur or low 

sulfur. These terms have been variously defined, but 

high-sulfur coal commonly is assumed to contain more 

than 3 percent sulfur and low-sulfur coal less than 1.5 

percent sulfur. The sulfur generally is partitioned into 

three forms: sulfate, organic sulfur bonded to carbon, and 

inorganic sulfide in the iron sulfide mineral pyrite. Various cleaning and washing methods have been developed to 

remove pyrite before coal is burned, but organic sulfur is 

an integral part of the carbonaceous matter and can be 

removed only by treating the combustion gases, an expensive process that produces large amounts of waste. Sulfur 

as sulfate is only a small part of the total sulfur and 

generally is not a problem.

On the basis of large-scale averaging, sulfur in 

high-sulfur coals generally is perceived to be partitioned 

into about 60 percent in pyrite and 40 percent in organic 

form, but this relationship should be reevaluated in light 

of recent research on how sulfur occurs in peat and how 

its occurrence is modified during the coalification process. Results of this research indicate that organically held 

sulfur in high-sulfur coal decreases to a low plateau value 

as formation of pyrite increases, no matter how much

total sulfur the coal contains, and examination of chemical 

data in the USGS NCRDS files provides broad support 

for this new hypothesis. In planning for industrial use of 

coal or for government regulation of sulfur emissions 

from coal combustion, it has been assumed that much of 

the high-sulfur coal in the U.S. resource base cannot be 

economically utilized because about 40 percent of its 

sulfur is in hard-to-remove organic form. It now appears 

that most of the sulfur in many high-sulfur bituminous 

coals occurs as pyrite and can be removed by standard 

cleaning techniques.

This new insight stems from recent research that 

has developed a picture of changing sulfur distribution 

during the coalification process. Living vegetation normally contains very little sulfur, and the sulfur in most 

coal was emplaced from surface waters that permeated 

the original peat deposits from which the coal eventually 

formed. These waters carried sulfate, from which sulfur 

was fixed in the peat in two organic forms: sulfide, which 

is fully reduced and bonded directly to carbon of the 

organic matter, and oxidized sulfur, which is combined 

with oxygen, through which it is bonded to the organic 

carbon. Research on peats in the Everglades swamps 

shows that this oxidized organic sulfur is transformed to 

free sulfide as part of the respiration process of sulfatereducing bacteria in oxygen-deficient peat swamps. The

free sulfide then reacts with iron to form pyrite. A key 

finding in the Everglades peats is that, as pyrite formation 

proceeds, oxidized organic sulfur declines by an equivalent amount. If the bacteria remain active and the transformation goes to completion, the organic sulfur that 

finally remains is the originally reduced, carbon-bonded 

sulfide. In the aging and metamorphosis of peat through 

lignite to coal, free sulfate is progressively lost, pyrite 

continues to develop, and, eventually, pyrite and organic 

sulfur are the dominant forms.

NCRDS provides data on the forms of sulfur in 

thousands of peat, lignite, and coal samples. Analysis of 

these data suggests that the distribution of sulfur forms 

evolves differently in low- and high-sulfur peats during 

their transformation to coal (fig. 33). In both low- and 

high-sulfur peats, pyrite generally is subordinate, most 

sulfur is organic sulfur, and high total sulfur simply 

means high organic sulfur. Low-sulfur coal retains the 

distribution pattern of sulfur forms in peat, but, as total 

sulfur increases, pyrite becomes progressively more 

important and organic sulfur declines, so that organic 

sulfur rarely exceeds 1.5 to 2.0 percent in sulfur-rich 

coals. The sulfur in excess of this plateau value for 

organic sulfur occurs as pyrite.

The plateau value of 1.5 to 2.0 percent for organic

sulfur in high-sulfur coal is particularly significant and is 

probably related to the amount of carbon-bonded sulfide 

in the original peat-swamp environment. Even if the total 

sulfur content is as high as 10 percent, about 85 percent 

of the sulfur in the coal will be in pyrite that can be 

washed from the coal'before it is burned. Sulfur data for 

all Appalachian coal beds having data in NCRDS and 

having an average total sulfur content of 7 percent or 

more indicate that 80 percent of the samples contain 25 

percent organic sulfur or less and 50 percent of them 

contain less than 20 percent organic sulfur (fig. 34). In 

samples having an average total sulfur content of 10 

percent, organic sulfur composes 15 percent of the total 

sulfur. These values are equivalent to about 1.5 to 2.0 

percent organic sulfur in the composition of each coal 

sample and document the concept of plateau value in a 

large regional sampling similar to that observed for 

high-sulfur coals nationwide.

Overall, this research strongly suggests that highsulfur bituminous coal contains 1.5 to 2.0 percent organically bound sulfur. This conclusion has important implications for the use of high-sulfur coal currently perceived 

to be unusable. High-sulfur bituminous coal resources 

should be carefully reevaluated, and the distribution of 

sulfur forms among coal beds and basins in each coal 

region of the United States should be documented.

Coal Resources 47
PEAT

1.0

3

55 o.s

=3 

i/t

u

i .

LOW SULFUR

* ?

0.5 1.0

HIGH SULFUR

Q

< 1.5

LIGNITE 1.0

>-

0- 0.5

Z

LU

u

0.5 1.0 1.5 2.0 0 2 4 6 8 10

COAL

X 3.0

UJ 2.0

1.0 *>

lit I I I

012345 02468

TOTAL SULFUR, IN WEIGHT PERCENT 

 ORGANIC SULFUR PYRITIC SULFUR

Figure 33. Summary of sulfur data from coal analyses in the National Coal Resources Data System. The data show that 

low- and high-sulfur coals partition their sulfur differently. In low-sulfur coal, sulfur is dominantly in organic form; in 

high-sulfur coal, organic sulfur is reduced to a plateau value, and sulfur in excess of that value is in the form of pyrite.

48 National Energy Resource Issues
100

80

o

<

z

LLJ

u

60

40

20 -

 SULFUR AS SULFATE 

a ORGANIC SULFUR

 PYRITIC SULFUR

a a

5 8 10

TOTAL SULFUR, 

IN WEIGHT PERCENT

Figure 34. Sulfur content of all Appalachian high-sulfur 

coal beds containing 7 percent sulfur or more for which 

analyses are available in the National Coal Resources Data 

System. The data show that organic sulfur values typically 

do not exceed 1.5 to 2.0 percent, regardless of the total 

sulfur content.

Coal Resources 49
HIGHER COST, ALTERNATIVE HYDROCARBON RESOURCES

Although supplies of oil and gas, particularly 

domestic supplies, will become scarcer and more expensive, it is unlikely that the demand for fuel in both liquid 

and gaseous forms will decrease substantially in the near 

future, even given the inevitable advances in design of 

vehicles and machinery. The United States is extremely 

rich in possible alternative sources of liquid and gaseous 

hydrocarbons. These resources are commonly called 

"unconventional" because producing energy from them 

requires approaches different from those used for "conventional" oil and gas; they include oil obtained by 

enhanced recovery techniques, heavy oil, tar sands (bitumen), shale oil, gas from tight reservoir rocks, gas 

hydrates, and gas from coal.

Although these potential resources are very different one from another, they have two major points in 

common:

 Hydrocarbons are not yielded as simply as they are 

in the pumping of conventional oil and gas. Production rates for these resources will be much 

lower than those for oil and gas, and production 

will be technologically more complex and expensive. This slower and more expensive production 

surely will result in decreased availability and 

higher prices of energy products derived from 

unconventional resources.

 Problems associated with unconventional hydrocarbons stem mostly from the natural intractabilities 

of the rocks that contain them and the ways in 

which they are held in the rocks, and we must have 

the best knowledge possible about the geologic 

characteristics of the host rocks. This knowledge 

will allow us to develop the most economic 

resources first, to select the most effective existing 

technologies, and to provide for improvement of 

extraction technologies, the result being lower production costs and increased rates of availability.

Government's rather unsuccessful efforts to 

develop a synfuels industry may, to a large extent, be 

attributed to the premature emphasis on production 

instead of first establishing a foundation of research 

and information (Landsberg, 1986). Unconventional 

hydrocarbon supplies have always been slightly to much 

more expensive than conventional oil and gas, and their 

future success depends on their place in a competitive 

market that is controlled by oil and gas prices. As oil 

and gas prices rise, unconventional hydrocarbons will 

become economic earlier if improved production methods have been developed. Development of improved 

production methods depends greatly on better geologic 

information about the resources themselves. Better geologic information also will help improve assessments 

and categorizations of available resources, which, in 

turn, will permit more informed and economically 

attractive policy decisions by government and industry 

planners.

Some higher cost alternative hydrocarbons will 

become economic sooner than others. Although 

improved (or enhanced) recovery techniques already are 

being used in many oil fields and some gas is being 

recovered from tight reservoir rocks, much research and 

development must occur before the full potential of 

these additional resources and reserves can be realized. 

The economic barriers to full exploitation of resources 

such as oil shale and tar sands are formidable. Nevertheless, in a context of long-term energy needs and 

national security, it is important to explore means to 

utilize the enormous potential of alternative hydrocarbon resources.

ENHANCED OIL RECOVERY

When crude oil is extracted from its reservoir rocks, 

primary recovery by means of natural reservoir energy 

and secondary recovery by means of water flooding usually obtain about one-third of the oil actually in place in 

the rock. Some of the remaining two-thirds probably can 

be produced by drilling more closely spaced wells to 

obtain the kind of field growth described in the chapter on 

oil and gas resources, but a significant percentage of the 

oil not originally recovered is tightly held either as films 

surrounding mineral grains of the host rock or in small 

pores not reached in the original recovery efforts. During 

the past few years, industry has been actively seeking 

methods to recover this additional oil. Enhanced oil 

recovery (EOR) techniques developed thus far include 

thermal recovery, miscible and immiscible flooding (using, 

for example, carbon dioxide), and chemical flooding using 

detergents and surfactants (tables 3, 4). EOR methods 

are expensive; some require major energy input, which 

cuts into the net energy gain. In addition, the effectiveness 

of the methods is quite variable and is highly dependent 

on the character of the reservoir rocks.

Nonetheless, EOR is a game well worth playing. 

Nationwide, two-thirds of the original resource left in the 

ground is a very large amount of oil. Historic production 

of about 130 BBO, reserves of 50 to 55 BBO, and 

estimated undiscovered recoverable resources of 80 BBO 

total 260 to 265 BBO. If this total represents one-third of 

the original resource, then about 500 BBO have been or 

will be left in the ground. If this amount of oil could be

50 National Energy Resource Issues
Table 3. Enhanced oil recovery projects in the United States

[Data for 1971-1982 from the National Petroleum Council (1984) and for 1984 and 1986 from Leonard (1986)]

Method

Chemical --- ------

Miscible« 

Immiscible CO2 -----

Thermal 

Total 

1971

...... 19

...... 22

.... 0

...... 91

1974

18

19

0

o-a

120

1976

^fi

24

1

106

159

1978

46

30

4

115

195

1980

42

'JO

4

150

224

1982

oc

45

5

139

274

1984

i-ao

66

1 Q

151

373

1986

f\{\£

in

*yQ

191

501

Table 4. Production from various enhanced oil recovery methods in the United States

[Production in barrels per day. Data for 1976-1982 from the National Petroleum Council (1984) and for 1984 and 1986 from Leonard

(1986)]

Method

Chemical 

Immiscible COa 

Thermal - 

Total1 - 

1976

3 400

. __ a/I isn

. __ n

ofln nnn

.........366,580(4.5)

1978

3,030 

76,070 

0 

290,000 

369,100 (4.2)

1980

2,400 

54,820 

0 

352,130 

409,350 (4.8)

1982

4,410 

50,660 

0 

450,200 

505,270 (5.8)

1984

13,390 

82,310 

700 

364,570 

460,970 (5.2)a

1986

16,900 

106,870 

1,350 

479,670 

604,490 (6.8)2

1 Values in parentheses are percentages of U.S. daily production.

2 DeGolyer and MacNaughton (1986).

considered even remotely to be available as extractable 

oil, then the United States, whose oil consumption is 

about 6 BBO per year and whose domestic production is 

only 3 BBO per year, would be in a fortunate resource 

position.

However, two factors must be considered: first, the 

amount of oil that can be obtained by using real-world 

technology, and, second, the rate at which enhanced 

recovery can be expected to produce oil. In 1984, the 

National Petroleum Council issued a major study on EOR 

prospects and problems. A base case using current EOR 

technology was examined and projected over the next 30 

years. The projections show that, at an oil price of $30 per 

barrel, EOR will add only about 14.5 BBO to U.S. oil 

supplies (fig. 35) and that annual production in about the 

year 2000 will be 0.4 BBO (fig. 36). If projections 

assuming advances in recovery technology are made, then 

ultimate recovery increases to 27.5 BBO, and annual 

production in the year 2000 is about 0.6 BBO. At $20 per 

barrel, the base case increases ultimate U.S. production 

by only about 8 BBO, and advanced technology development will not be supported. The sharp decrease in oil 

prices during 1986 appears to have produced the result 

projected by the National Petroleum Council in that

numerous trade journal articles indicate significant industry cutbacks in EOR research.

It is difficult to determine how soon the economics 

of petroleum will bring EOR to the fore and what 

technologic advances may occur to make EOR more 

effective. It is not difficult, however, to predict that 

improving EOR will require sophisticated geologic knowledge. Reservoir rocks have unique geologic characteristics, and both selection of the proper recovery method and 

improvements in that method depend on a knowledge of 

the porosity, permeability, mineralogy, and chemistry of 

reservoir rocks and their contained natural fluids. Such 

knowledge can be derived only through detailed studies of 

drill-core samples and well measurements. Information 

from these studies can be used to construct models of the 

original depositional environment of the sediments and 

the many changes that the sediments undergo after deposition as the result of interaction with ground water.

An enormous amount of oil potentially is available 

for EOR. Can we really expect to obtain only 5 percent of 

this oil and then only at greatly increased prices? The 

remaining 95 percent provides a major target and incentive for geologic and engineering research.

Higher Cost, Alternative Hydrocarbon Resources 51
40

35

30

25

wQ 20

QE

uig

<0 15 

213

j5 10

Chemical

Miscible 

Thermal

i

I I I J I I

S20-C S30-C S30-A S40-C $40-A $50-C $50-A

NOMINAL CRUDE OIL PRICE, 

IN 1983 DOLLARS PER BARREL

Figure 35. Ultimate recovery of oil in the United States calculated by using both current 

(C) and advanced (A) enhanced oil recovery technology. Dollar amount shown is price 

per barrel. Modified from National Petroleum Council (1984, p. 71).

3,500

1984 1987 1990 1993 1996 1999 2002 2005 2008 2011

Figure 36. Projected daily production from enhanced oil recovery (relative to crude oil price) 

calculated by using both current (C) and advanced (A) enhanced oil recovery technology. Dollar 

amount shown is price per barrel. Modified from National Petroleum Council (1984, p. 68, 76).

52 National Energy Resource Issues
Focus: Geologic Studies Related to Enhanced Oil Recovery

Recent studies of reservoir rocks indicate that it is 

critical to understand the fine details of these rocks. An 

important reservoir rock, the Minnelusa Formation in the 

Powder River basin of Wyoming, was deposited by a 

combination of marine and wind depositional processes. 

These varied depositional processes produced heterogeneous sandstone bodies. Highly permeable zones are 

adjacent to impermeable (or tight) zones, and fluids used 

in EOR can be easily channeled away from much of the 

oil-bearing rock. Porosity and permeability in the Minnelusa Formation are highly variable; the original porosity 

and mineralogic character were controlled by the depositional process, which in turn controlled how and where 

secondary porosity developed as the result of the later 

passage of ground water (fig. 37).

In rocks of the Minnelusa Formation, original 

cementing material around the sand grains was partially 

dissolved to create complex secondary pore-space pathways; these pathways were then partially filled by very fine 

grained minerals. If recovery fluids are used under pressure, this late-growth fine-grained mineral matter can be 

dislodged and block other pores in an uncontrolled fashion and thus interfere with oil recovery. Moreover, some of 

the late-growth minerals are clays and zeolites that can 

swell or react chemically upon contact with certain recovery fluids and block pores or cause other problems. Thus, 

for each target reservoir rock, a well-designed recovery 

operation should begin with a knowledge of the depositional environment and an understanding of the mineralogy, chemistry, and primary and secondary porosity of the 

rocks, as well as the sequence in which these developed. 

In recognition of the importance of EOR and in 

order to fill part of the gap resulting from the oil 

industry's shutdown of research, the USGS is extending its 

research program to include study of an increased number of representative reservoir rocks and to build a data 

base of pertinent reservoir characteristics. One of the 

program's goals is to compile geologic and engineering 

information from a national file of well data and to study 

in detail well cores held by the USGS in its National Core 

Library. The program also includes the use of complex 

new geophysical techniques to measure rock properties in 

drill holes and in core samples. Overall, the program is 

designed to encompass studies of:

 Detailed reservoir rock characteristics, including 

granularity, mineralogy, and chemistry, special 

attention being given to clays and other reactive 

minerals and to fluid-flow pathways. Clay minerals 

are extremely important because they critically 

influence reservoir quality, and, if the types and

Figure 37. Scanning electron photomicrographs of eolian sandstones from the Minnelusa Formation, Powder River basin, 

Wyoming. A, Secondary porosity has resulted from anhydrite dissolution, and small dolomite rhombs have formed both 

along the pores and on the remnant anhydrite. The dolomite rhombs and the complex topography of the remnant 

anhydrite increase tortuosity and surface area in the pore throats. During reservoir enhancement, the dolomite can detach 

from the walls of the pore throats, be carried in the fluid, and later plug up or restrict pore throats. B, The clay minerals 

smectite and illite/smectite (spongy areas and small crystals) are common pore-lining cements and can react with fluids 

and cause swelling and increased surface area within the pores. Large crystals are anhydrite. (Photographs courtesy of 

C.J. Schenk.)

Higher Cost, Alternative Hydrocarbon Resources 53
distribution of clay minerals are not adequately 

understood before application of EOR techniques, 

reservoir porosity and permeability can be irreversibly damaged. Given this information, conceptual 

models can be achieved to understand and predict 

variations in pore-space pathways and fluid movement as a function of the basic geology of the 

reservoir rock.

Organic geochemistry, including character, level of 

alteration, trace-metal content, sources of the oil, 

and the possible degradation of oil by postdepositional processes.

Reservoir classification, a categorization based on 

geologic, engineering, and production attributes, to 

help guide selection of recovery techniques and 

possible improvements of these techniques. 

Resource assessment, an estimation of potentially 

recoverable resources by category of reservoir, 

based on studies of selected reservoirs and extrapolation to a larger population of reservoirs.

HEAVY OILS

Some petroleum reservoirs contain viscous hydrocarbons known as heavy oils or extra-heavy oils. These oils 

are too viscous to flow in response to the pumping or 

flooding techniques used to produce conventional oil. 

They typically are viscous either because they have been 

altered more than normal oils through geologic time or, 

more commonly, because they are contained in reservoirs 

so shallow that rock temperatures are too low to keep the 

oils mobile. Many potential heavy-oil resources are in 

reservoirs at depths of only 1,000 to 5,000 feet, and, if 

recovery techniques are developed, these shallow depths 

could make the oils economically attractive.

Although heavy oils occur widely in small accumulations, most heavy-oil resources occur in a more 

restricted fashion (fig. 38). Future exploitation probably 

will involve only 20 to 60 fields, most of which are in 

California, the gulf coast, and Alaska (table 5). The 

original heavy-oil resources of California are estimated at 

about 35 BBO, of which 10.2 billion BBO have been

Figure 38. Heavy-oil resources in the United States.

54 National Energy Resource Issues
produced through 1984. The heavy-oil resources of Alaska 

may be as much as 40 BBO in shallow rocks overlying the 

giant Prudhoe Bay field of conventional oil. All these 

numbers represent original oil in place and not recoverable oil; presumably, only a small fraction of the total 

heavy-oil resource of the United States will ever be 

produced. It should be noted that the heavy-oil resources 

of the United States are dwarfed by the enormous potential resources of Venezuela and the U.S.S.R.

Heavy oil is extracted by using EOR techniques (in 

particular, steam injection). In the future, shallow heavyoil reservoirs conceivably may be developed by using 

underground techniques such as mining or horizontal 

drilling, but use of these techniques will result in significantly higher prices. The effective use of all heavy-oil 

recovery techniques will benefit from improved geologic 

knowledge. The heavy-oil resources of the United States 

have been only crudely estimated, and many more studies 

similar to those described for EOR are needed to determine the distribution and field size of potentially recoverable heavy oils and the geologic characteristics of their 

reservoirs.

Table 5. Production from heavy-oil deposits in the United 

States

[Cumulative crude oil production through January 1 of the year 

listed for most, though not necessarily all, reservoirs in State]

State

A T*Lp'incic

California 

Louisiana 

Mississippi 

TVvac.

WyomingOther States ----- -

Year

.......... 1982

.......... 1985

____ 1982

.......... 1985

.......... 1985

.......... 1985

 Not applicable

Cumulative crude 

oil produced, in 

millions of barrels

605 

10,202 

1,002 

261 

1,173 

1,177 

147

TAR SANDS

The term "tar sands" is used to refer to both 

sedimentary rocks and unconsolidated sands that contain 

an asphaltic substance called bitumen, which is not mobile 

at reservoir conditions and cannot be extracted by conventional petroleum recovery methods. Bitumen-bearing geologic materials include sandstone, limestone, dolomite, 

conglomerate, siltstone, and unconsolidated sand. Most 

tar sands in the United States are in fields that each 

contain more than 100 million barrels of oil in place (fig. 

39). The total tar sand resource of the United States is 

about 53 BBO in place, 22 BBO of which are measured 

reserves and the rest speculative reserves (fig. 40). 

Another 1 BBO is estimated for smaller fields. More than 

two-thirds of the estimated resource is in Utah, Alabama,

California, and Texas, and a very large but only crudely 

estimated speculative resource is in Alaska.

Bitumen recovery is virtually 100 percent if the tar 

sand deposit is amenable to open-pit mining, as are the 

giant Athabasca deposits in central Canada. Most deposits 

in the United States, however, have geologic or physiographic settings that probably will require either underground mining or in-place recovery techniques similar to 

those used for EOR.

Although most natural bitumen deposits look alike 

superficially, each deposit is unique in the geochemistry 

of its hydrocarbons and in the mineralogy and grain 

texture of its reservoir rock. The highly altered bitumens 

characteristic of most tar sand deposits represent only 

about 20 percent of the oil that existed before degradation 

by bacterial activity, dissolution of some components by 

freshwater, and evaporation of components having low 

boiling points. Oil from these tar sands is a residue, not 

unlike the residual oil in refinery stills, and it contains all 

of the most stable components of the original oils, including complex heavy molecules of asphaltenes and resins 

and other hydrocarbons rich in nickel, vanadium, and 

nitrogen-oxygen-sulfur compounds. Characteristics such 

as viscosity, specific gravity, and vanadium, sulfur, and 

asphaltene content should be determined before attempts 

at recovering the bitumen are made. Only then can the 

technological and economic aspects of producing, upgrading, transporting, and refining these hydrocarbons be 

assessed.

The geologic setting and the detailed mineralogic 

and chemical compositions of both reservoir rocks and 

surrounding rocks are important. For example, although 

tar sand deposits around the margin of the Uinta basin in 

Utah are among the largest in the United States and are 

reasonably attractive recovery targets, thermal recovery 

methods (steaming) have been unsuccessful because of 

porous "thief" zones in the rock sequence into which 

injected steam is lost to recovery. The sandstones in the 

reservoir rock sequence are quite heterogenous as a result 

of both the processes and the environments of their 

deposition. Individual lenticular tar-bearing sandstones 

are enclosed in finer grained rocks and are not well 

interconnected. In-place recovery must target individual 

sandstones, and, as a result, the amount of reservoir rock 

from which oil can be obtained in a single attempt is 

greatly reduced. The sandstones have a complex primary 

and secondary mineralogy and contain many clays and 

other minerals that may interfere with recovery (fig. 41). 

The original pores of the sandstones contain late-growth 

mineral grains that are unstable in the presence of some 

recovery fluids, and formation damage can easily occur if 

recovery methods are not specifically designed for the 

particular sandstone. Moreover, the tar appears to occupy 

secondary pores that developed erratically. All of these

Higher Cost, Alternative Hydrocarbon Resources 55
Figure 39. Tar sand resources in the United States.

SPECULATIVE 

MEASURED

I

I 5

Figure 40. Distribution of 

tar sand resources in the 

United States. Tri-State area 

includes parts of Missouri, 

Kansas, and Oklahoma. 

Modified from a figure prepared for the U.S. Geological 

Survey by Lewin and Associates (1983).

56 National Energy Resource Issues
Figure 41. Scanning electron photomicrographs of the Sunnyside tar sand, Uinta basin, Utah. A, This bitumen-bearing tar 

sand is mineralogically complex, and, as a result, bitumen recovery will be difficult. The bitumen (pasty material) occupies 

the minute topography of the framework grains (areas labeled F and large blebs) and late-growth minerals (small crystals) 

and is difficult to separate from these minerals. B, In a nonbitumen-bearing sandstone, kaolinite (plates and elongate 

masses of plates), pyrite (small cubic crystals), and dolomite (large cubic crystals) combine to produce extremely large 

surface areas that reduce permeability and make access of recovery fluids difficult, if not impossible. (Photographs 

courtesy of C.J. Schenk.)

problems are difficult to overcome by using only an 

engineering approach, but bitumen recovery may be significantly improved if detailed geologic information on the 

origins and characteristics of the reservoir sandstones is 

available.

OIL SHALE

Oil shales are fine-grained sedimentary rocks that 

contain kerogen, which produces oil and combustible 

gases upon destructive distillation. Kerogen consists of 

carbon, hydrogen, oxygen, nitrogen, and sulfur in varied 

proportions, depending on the organic matter from which 

it was derived and on the postdepositional chemical 

changes and thermal history of the oil shale. Oil shales 

generally form in lake or marine environments, and the 

kerogen is derived mostly from algae and aquatic organisms. A good grade of oil shale typically contains 15 to 20 

weight percent kerogen; the remainder of the rock is 

composed of mineral matter usually having a complex 

mineralogic and chemical composition. Some oil shales 

contain other organic matter such as bitumen and humus 

(derived from land plants), depending on conditions of 

deposition, proximity to land masses, and thermal history.

Oil shales are a low-grade energy resource in 

comparison with other fossil fuels. In terms of Btu per 

ton, the amount of heat energy in oil shale is about 

one-eighth of that in crude oil (fig. 42). Estimated 

resources of shale oil, however, are about 14 times as 

great as those of conventionally recoverable oil, and

estimates of about 2 trillion barrels of shale oil probably 

will increase as more information is gathered on less well 

known shale deposits.

The relatively low heat energy in oil shales results 

from dilution of kerogen by the large proportion of 

mineral matter in the shales. This mineral matter contributes to mining, processing and waste disposal problems, and costs. Unlike crude oil, which is sent directly to 

the refinery, or coal, which commonly requires only 

crushing, screening, and perhaps washing before it is 

burned, oil shales require significant handling, retorting, 

and upgrading before they are refined, and attention must 

be given to environmental concerns in disposing of waste 

materials. Nevertheless, the large amount of oil that 

potentially can be extracted from oil shales in the United 

States probably ensures its eventual inclusion in the 

national energy mix. The future of oil shales as an energy 

resource will be enhanced by continued research on the 

geologic, mineralogic, and chemical character of the 

principal oil shale deposits in the United States as a basis 

for improving both resource assessments and extraction 

techniques. At the present time, oil is plentiful and cheap 

on world markets, and oil shale development efforts and 

the research that underlies these efforts have been almost 

completely abandoned by industry. The USGS is continuing a small program of research on oil shales that is 

designed to build on past information and to bridge 

today's lull in activity in order to ensure better information for tomorrow's needs.

Oil shales are widely distributed in the United 

States and vary greatly in type and geologic age (fig. 43).

Higher Cost, Alternative Hydrocarbon Resources 57
ENERGY VALUES OF FOSSIL FUELS

CRUDE 

OIL

COAL OIL 

SHALE 

{25 GALLONS 

PER TON)

> °

5 <*

Q Z

6s

AMOUNTS OF 

FOSSIL-FUEL RESOURCES

CRUDE 

OIL

COAL OIL 

SHALE

Figure 42. Energy values and resource amounts of oil, coal, and oil shale in the United States. Data from Duncan and 

Swanson (1965), Averitt (1975), Dolton and others (1981), and the American Petroleum Institute (1982, sec. 15, table 3).

Oil shale deposits 

in the Tertiary 

Green River Formation

Devonian and Mississippian

organic-rich shales 

Other stratigraphic units

that contain oil shale

0 400 MILES

Figure 43. Oil shale resources in the United States. Modified from L.J. Schmitt and J. Roen (written communication, 

1986).

58 National Energy Resource Issues
Figure 44. Block of white-weathering high-grade oil shale from the Green River Formation showing evenly bedded 

laminae characteristic of deposition in undisturbed oyxgen-deficient lake waters. Beneath the weathered surface, the oil 

shale is brownish black. (Photograph by J.R. Dyni.)

Only the largest deposits have received much study and 

analysis, and, even for these deposits, much more detailed 

work is necessary to support economic extraction 

attempts. The two largest deposits in the United States 

are the Green River oil shales in Colorado, Utah, and 

Wyoming (lake origin, Tertiary age) and the black shales 

of the Appalachian plateau (marine origin, DevonianMississippian age). Thousands of assays and other analytical data from hundreds of drill holes are available for 

the Green River shales, especially those in Colorado. 

Analytical data for the eastern oil shales are sparse 

relative to their wide distribution, and resource estimates 

for these shales are much more uncertain than those for 

the Green River shales.

The Green River oil shales contain an estimated 1.8 

trillion barrels of oil in beds that will yield 15 or more 

gallons per ton (Donnell, 1980). In Colorado alone, these 

deposits contain an estimated 1.2 trillion barrels. Most of 

these shales can be reached by open-pit, underground 

room-and-pillar, and in-place retorting methods of mining 

or extraction. The distribution of richness in the shales is 

a function of the environments in the ancient lake in which 

the shales were deposited (fig. 44), and geologic mapping 

and compilation of assay data by the USGS have resulted 

in delineation of zones of estimated oil yields (fig. 45). If 

this information is overlaid on a map showing basin 

topography, significant amounts of shale can be seen to

have overburden thin enough to permit strip mining, and, 

as prices of competing fuels rise, these shales will become 

economically more attractive. Strip mining economics 

also may be improved if the enormous quantities of the 

industrial minerals nahcolite (a source of soda ash) and 

dawsonite (a source of alumina) in the rock sequence can 

be mined as coproducts with the oil.

Government and industry have invested billions of 

dollars in an effort to make the oil shales of Colorado an 

economic resource, but costs have always been higher 

than the price of oil. This differential cannot be overcome 

by good geologic information alone, but, if oil shale is ever 

to reach an economic threshold, geologic information is 

an essential ingredient in improving the processes of site 

selection, mining, retorting, and waste handling.

Site selection to achieve a combination of richest 

yields and thinnest overburden or to locate shale zones 

amenable to underground mining or in-place extraction is 

paramount. In addition, the extraction process being 

considered must fit the mineralogy and chemistry of the 

shale. Open-pit and underground operations must not 

disrupt aquifers or adversely affect other aspects of the 

local ground water; for example, they must not introduce 

pollutants or adversely affect the natural water chemistry. 

One study by the USGS resulted in important new 

information on natural rock fracture systems in the shale 

that can be used to help determine mining, crushing, and

Higher Cost, Alternative Hydrocarbon Resources 59
45°00'

108° 00'

I

<c~ %Meeker

COCQJMY MINE 

ANVIL POTNT^MINE

I I Area underlain by

Green River Formation

I I Areas of oil shale mining 

activity and Federal 

oil shale leases

Aggregate thickness of 

> oil shale beds >10 feet 

thick and yielding 

25 or more gallons 

per ton of oil. Dashed 

where formation has 

been removed by 

erosion

10 MILES

Figure 45. Areal extent of the Green River Formation in western Colorado, locations of several oil 

shale operations, and contours of the aggregate thickness of oil shale beds yielding at least 25 gallons 

of oil per ton. Modified from C.W. Keighin (1975, p. 67).

retorting procedures and to handle problems associated 

with ground-water movement in mine areas.

Numerous retorting devices and methods have been 

designed, some of which have been tested at pilot scale. 

Different oil shales may behave quite differently in the 

retort, which distills oil and gases from the raw feedstock. 

Breakage and fracture characteristics of the shale are 

important. The reactions of different mineral components 

(in particular, carbonate and sulfide minerals) at various 

retorting temperatures can cause heat loss or problems of 

water chemistry leading to environmental concerns.

No single retorting process has yet emerged as the 

best method for retorting oil shale. Newer, innovative 

technologies, including microwave processing, hydroretorting, and solvent extraction, may lead to methods of 

economically recovering shale oil. But any and all of these 

methods, like those previously tried, depend on characteristics of the target shale, such as mineralogy, kerogen 

and trace-element contents, depth, thickness, and grade. 

Beneficiation (upgrading) of oil shale before retorting by 

liquid flotation and mechanical separation techniques has 

been tested at laboratory scale but must be tailored to the 

precise physical, mineralogical, and chemical characteristics of the shale to be treated.

Some shale oil tested in jet engines is corrosive, and 

piping has been corroded during some extraction tests. 

The cause of this corrosion is not known, but one suspicion focuses on the presence of fluorine, which is in the 

fluorine-bearing mineral phase apatite in some shales. Oil 

shale varies both laterally and vertically, and the identity 

and distribution of fluorine-bearing minerals in oil shale 

are not well known. Other deleterious trace elements in oil 

shale (also of unknown detailed distribution) include 

mercury and arsenic, both of which poison catalysts in the 

refining process.

Environmental concerns in the mining and processing of oil shale include (1) release of gaseous and particulate stack gas effluents from above-ground retorts; (2) 

dust resulting from large-scale open-pit mining; (3) contamination of surface and ground water by the dissolution 

of soluble organic and inorganic constituents from piles of 

raw and retorted shale and overburden; and (4) compaction and slope stability of waste piles and their long-term 

exposure to erosion and dissolution of soluble materials.

Some organic constituents of oil shale are carcinogens. These compounds are in the shale oil as well as in 

the organic waste products (Savitz and others, 1984). 

Little is known about either their concentrations in the

60 National Energy Resource Issues
shale or shale oil or their levels of toxicity to man, 

livestock, wildlife, and native vegetation. Potentially toxic 

elements include fluorine, sulfur, arsenic, boron, molybdenum, mercury, and lithium. Little is known about the 

concentration, distribution, and mineral residence of these 

elements in the oil itself. The USGS and others have 

initiated geochemical studies of some of these potentially 

harmful elements in order to understand and predict their 

distribution and abundance in oil shale and their concentrations and leachability in retorted shale. In addition, the 

USGS has determined concentrations of various trace 

elements in selected native plants in the Piceance basin of 

western Colorado in order to establish a baseline of 

geochemical data under natural conditions before mining. 

When an oil shale industry is established, these data will 

be useful in monitoring trace elements of environmental 

concern.

fcLU

Q

OIL, IN GALLONS 

PER TON

-Tn I I

-J20 40 60 ' r3____

SULFUR, IN WEIGHT

PERCENT I --[ py | |

' 1.0 2.0 3.0

Mahogany 

zone

R _ 4

1-2.700 2.700

Figure 46. Chemical analyses of Green River shale oil 

from a drill hole in the deeper part of the Piceance basin of 

Colorado. Geochemical data help the process engineer 

determine the amount of sulfur that can be recovered as a 

byproduct from oil shale. Zones R-1 through R-6 and the 

Mahogany zone are oil-rich layers in the shale sequence.

Much remains to be learned about our major oil 

shale resource, the Green River Formation in Colorado, 

Utah, and Wyoming. Current research by the USGS 

includes geologic mapping, stratigraphic and basin analysis studies, resource inventories of the Colorado shales, 

geochemical studies of selected elements, compilation of a 

large computerized data base, and the accumulation of 

government and industry drill-core samples to be made 

publicly available for further research. A series of subsurface stratigraphic sections of the Piceance basin in 

Colorado is being produced to detail rock types and 

resources of oil shale, nahcolite, and dawsonite. The 

sections pass through each of the major oil shale project 

areas in the basin, including Federal lease tract C-a and a 

proposed offsite waste disposal area for the tract, Federal 

lease tract C-b, the Colony project, and the government 

experimental mines at Horse Draw and Anvil Point (fig. 

45). These sections delineate a leached zone in the upper 

part of the oil shale sequence that is an aquifer that may 

cause problems in mining. They also show correlations 

between depositional character and mineralogical and 

trace-element patterns, information that will be useful 

before shale mining and processing. For example, we 

know that the lateral and vertical distribution of sulfur is 

partly controlled by depositional conditions and that the 

concentration of sulfur is partly related to the abundance 

of kerogen (fig. 46).

Oil shales above the well-known oil-rich Mahogany 

zone (fig. 47) in the upper part of the Green River 

Formation also are targeted for study. These lower grade 

oil shales (5-25 gallons per ton) could be exploitable

Figure 47. Aerial view of the Mahogany oil shale ledge 

(ML) and underlying oil shale zones on the northern slope 

of the East Fork of Parachute Creek, near the Union oil 

shale mine, southern Piceance basin, Colorado. (Photograph courtesy of J.R Dyni.)

Higher Cost, Alternative Hydrocarbon Resources 61
resources if deep open-pit mining in parts of the basin is 

ever economically feasible.

In the past few years, Devonian oil shales in the 

Eastern United States have received considerable attention as a potential source of energy. These large, potentially strippable deposits occur in several States (fig. 43). 

Currently available resource estimates need to be revised 

but are on the order .of 400 BBO for those shales 

containing 10 gallons per ton or more. Although conventional Fischer assay yields for Devonian oil shales are only 

one-half of those for Green River shales, it recently has 

been discovered that such assays do not measure a rock's 

total hydrocarbon potential. In fact, an experimental 

hydroretorting technique releases as much as 200 percent 

more oil than Fisher assays indicate is in Devonian shales. 

Because these Devonian shales contain less carbonate, 

they should be easier to crush and beneficiate than Green 

River oil shales and should pose less of a problem of 

leaching in terms of large amounts of soluble compounds. 

Water for processing, a problem in the Western States, is 

abundant, and labor, transportation, power, and markets 

are nearby. These factors, together with the potential for 

improved retorting, may help offset the fact that eastern 

oil shales are thinner and less oil rich than Green River 

shales.

Kerogen-rich shales occur in several other parts of 

the United States, but their oil resource potential is not 

well known. Some of these shales are irregularly distributed and are in geologic and physiographic settings 

not amenable to exploitation. Occurrences in Montana and 

Nevada, however, may contain billions of barrels of shale 

oil. This potential calls for basic geologic investigation, 

although perhaps at a lower priority than investigations of 

the more important deposits described above.

GAS HYDRATES

Gas hydrates are compounds of solid water (ice) 

and gas, usually methane. Pressure and temperature 

conditions suitable for formation of gas hydrates are 

found in arctic permafrost regions (fig. 48) and beneath 

the sea floor of outer continental margins and ocean 

basins. In arctic regions, gas hydrates occur not only in 

permafrost but also below the base of permafrost at 

temperatures above the freezing point of water.

Significant quantities of gas hydrates have been 

detected in several permafrost regions of the world, 

including the North Slope of Alaska, both onshore and 

offshore. Marine seismic reflections offshore from the 

North Slope in the Arctic Ocean and in the Blake

Point Barrow

NATIONAL PETROLEUM RESERVE 

OF ALASKA

Well containing 

gas hydrate

Well containing 

no gas hydrate

Zone of hydrate 

stability

Figure 48. Areas in which gas hydrates are stable, North Slope, Alaska.

62 National Energy Resource Issues
Plateau-Bahamas region of the Atlantic Ocean show 

features known as bottom-simulating reflectors, which 

are construed to indicate gas hydrate occurrences. Seismic data defining the extent of gas hydrates offshore from 

the North Slope and in the Blake Plateau area are 

reasonably complete, and limited seismic data indicate 

the possible existence of gas hydrates in the Bering Sea, in 

a zone along the southern side of the Aleutian arc, and on 

the Pacific slope off northern California.

The potential gas resource contained in gas hydrates 

in U.S. Territories was reviewed by the Potential Gas 

Commission (1981). Information on occurrence, thickness, continuity, and gas content is highly speculative, and 

reliable estimates are not possible. Estimates of worldwide gas hydrate resources range from 500 to 1,200,000 

TCFG, and, although any estimate of world resource 

must be taken as an order-of-magnitude approximation at 

best, an enormous number such as 500,000 TCFG is 

within the range of estimates and is a useful assumption 

for the volume of gas potentially present in hydrates. In 

addition to the large amount of methane that probably is 

present in gas hydrates, another noteworthy aspect of gas 

hydrates as a potential resource is their occurrence at very 

shallow depths, less than 3,600 feet below the sea floor 

and from 650 to 4,000 feet below ground surface in 

permafrost areas.

Another important resource aspect of gas hydrate 

layers is that they may form impermeable seals beneath 

which significant accumulations of gas may be trapped. 

Seismic reflection data off northern Alaska and off the 

Carolinas strongly suggest the presence not only of gas 

hydrates but also of low-velocity zones beneath the gas 

hydrate layers that probably contain gas.

The U.S. Department of Energy has sponsored a 

modest program of research by the USGS aimed at 

improving knowledge about the occurrence and character 

of gas hydrates in the permafrost area of the North Slope 

and at collecting information on gas hydrates worldwide.

COAL-BED METHANE

In Europe and in the Eastern United States, coalbed gas has been produced and utilized in limited quantities for many years, and, recently, coal-bed gas has been 

produced from coal beds in the Western United States. 

Several areas in the United States, most notably the Black 

Warrior basin in Alabama and the San Juan basin in New 

Mexico and Colorado, are now producing commercial 

quantities of gas. A recent issue of the Oil and Gas 

Journal (September 8, 1986, p. 43) reports a single 

month's production of more than 1 billion cubic feet of 

coal-bed methane in Alabama, 14 percent of the State's 

total gas production; this gas was produced from 266 wells 

in seven fields. This production represents only a tiny

fraction of the potential of coal-bed methane. Coal-bed 

methane resources in the United States are estimated at 

72 to 860 TCFG, and most estimates are between 300 and 

500 TCFG. Potentially productive areas in the United 

States include all of the coal basins.

During early stages of coalification, coal beds are 

affected by microorganisms in a predominantly lowtemperature environment. Methane, carbon dioxide, and 

traces of other gases are released, as well as large amounts 

of water. Temperature and pressure increase as coal beds 

are buried by continued sedimentation, and increasing 

quantities of methane and carbon dioxide and smaller 

quantities of nitrogen, oxygen, hydrogen, and the heavier 

hydrocarbons such as ethane, propane, and butane are 

generated. Although much of this gas either is lost to the 

atmosphere or migrates from the coal into adjacent rocks, 

large quantities are retained in the coal as free gas within 

joints or fractures in the coal or as adsorbed gas within the 

fine micropore coal structure. Gas contained in joints and 

fractures is more easily removed from the coal than is the 

more abundant adsorbed gas. The gas adsorption capability of coal increases with increasing coal rank. Coal-bed 

gas contains 90 to 99 percent methane and has a heat of 

combustion of 950 to 1,035 Btu per cubic foot. During the 

formation of 1 ton of coal, as much as 46,000 cubic feet of 

gas may be generated.

At the present time, coal-bed gas is produced from 

deep, unminable seams, from drainage of gas in advance 

of coal mining, and from drainage of gas from mined-out 

areas. Production rates are highly variable. Initial daily 

rates from some of the better producing wells are more 

than 1 million cubic feet per day, but rates in most wells 

are less than 250,000 cubic feet per day. Physicochemical 

factors affecting recoverability of coal-bed gas include 

coal rank, moisture content, gas adsorption capability, 

macropore and micropore structure, cleat (or fracture) 

development, type of organic matter, temperature, and 

pressure.

From the perspective of petroleum geology, coal 

beds have some advantages over conventional gas reservoirs. Geographic and stratigraphic occurrences of coal 

beds in the United States and elsewhere are relatively well 

known, and, because the coal beds are both the gas source 

and the gas reservoir, problems of gas generation and 

migration are less complex. These factors, in conjunction 

with drilling depths of generally less than 3,000 feet, 

reduce exploration and exploitation costs. Nevertheless, in 

commercial production of coal-bed methane, as in the 

mining of coal itselfj an understanding of coal-bed geology and the original conditions of deposition of coal beds 

enhances the ability to predict continuity of beds, their gas 

content, and their fracture development, three important 

factors related to gas production. Detailed studies of the 

original organic matter and of the thermal maturation 

(coalification) level are particularly valuable in predicting

Higher Cost, Alternative Hydrocarbon Resources 63
gas contents. It is important to obtain any information 

that could improve estimation of gas flow rates, and there 

is a dearth of information on the gas contents and gas flow 

characteristics of coal beds throughout the United States. 

In many areas, a knowledge of the ground-water geology 

is important because many coal beds are good aquifers, 

and the production of methane is commonly accompanied 

by large amounts of water that reduce gas production 

rates. This water may be acidic or alkaline, commonly is 

rather saline, and may require special considerations and 

expense for its environmentally sound disposal.

TIGHT GAS RESERVOIRS

In addition to gas produced by normal flow from 

permeable reservoir rocks, a major potential gas resource 

exists in reservoir rocks having such low permeability that 

the gas cannot be produced by using conventional engineering techniques (fig. 49). These so-called "tight" reservoir rocks generally are blanket or lenticular sandstones 

or chalky limestones and have permeabilities to gas of less 

than 0.1 millidarcy. The low permeabilities result either 

from fine grain size and tight packing or from cementation 

that has closed off much of the original pore space and the 

connecting passageways between pores. Most tight rocks 

are naturally fractured, and the fractures provide pathways that improve gas flow from the reservoirs.

Tight reservoir rocks containing significant potential resources of gas are in sedimentary basins both in a 

Rocky Mountain belt that extends from New Mexico

to Canada and in the South Central United States (fig. 

50). Of the 20 basins known to contain such resources, 

the Piceance basin in Colorado, the Uinta basin in Colorado, and the greater Green River basin in Wyoming and 

Colorado are the most explored and have the greatest 

potential for early significant gas production. Some studies, such as one done by the National Academy of Science 

in 1976 and one conducted by the National Petroleum 

Council (1980), indicate that tight gas reservoirs have 

potential recoverable resources approximately equal to 

those of undiscovered conventional gas. The Rocky Mountain basins are estimated to contain in-place resources of 

perhaps 600 TCFG, and the remaining 17 basins probably contain an equal amount. If a recovery rate of 25 to 40 

percent of in-place resources is assumed, the potential 

recoverable tight reservoir gas resource of the United 

States is 300 to 480 TCFG.

Production from tight gas reservoirs is achieved by 

hydraulically fracturing the rocks around a well. A waterbased gel mixed with sand is pumped into the well under 

extremely high pressure to fracture the surrounding reservoir rocks, and the sand keeps the fractures open. Under 

ideal conditions, these fractures can extend as much as 

2,000 feet outward from a well and provide new large 

surface areas from which the contained gas can flow. If 

the zone is effectively fractured, gas commonly will flow at 

a lower rate than it will from a conventional well but for a 

longer time.

Both exploration and production are more expensive in tight gas reservoirs than they are in conventional

Figure 49. Photomicrographs of (A) conventional sandstone reservoir rock from the Cretaceous Muddy Sandstone in the 

Powder River basin of Wyoming and (B) low-permeability (tight) reservoir rock from the Cretaceous Mesaverde Group in 

the Piceance basin of Colorado. Pore spaces in both A and B are filled with blue epoxy. Bar scale is 0.2 mm. (Photographs 

supplied by C.W. Spencer.)

64 National Energy Resource Issues
reservoirs. Geologic information on the occurrence of 

reservoir rocks and the depositional and postdepositional 

processes that formed them is particularly important. For 

example, most fluvial (river-deposited) sandstones are 

highly lenticular and have irregularly distributed reservoir 

characteristics. They do not fracture as well or as predictably as blanket sandstones deposited in nearshore marine 

environments. On the other hand, the more laterally 

continuous blanket sandstones typically have low porosity 

resulting from erratically distributed, postdepositional 

mineral grain solution and deposition. Reservoir rocks 

comprising blanket sandstone, siltstone, and chalk deposited in deeper marine environments have yet another set 

of rock properties that must be considered during exploration and production. These rocks are very fine grained, 

and their pores and interconnecting spaces are very small; 

as a result, they commonly have good porosity but low 

permeability.

Tight gas reservoirs are difficult to identify by using 

conventional seismic reflection exploration techniques, 

and an accurate knowledge of the environments of deposition of the reservoir rocks can help determine good 

targets for drilling. When a potential target reservoir is

drilled, conventional interpretive methods must be used 

very carefully, because tight formations are texturally and 

mineralogically different from conventional reservoir 

rocks. A knowledge of the continuity of reservoir rocks 

and their detailed physical, mineralogical, and chemical 

characteristics is critical in designing production methods 

that will not damage the formation by the plugging of pore 

connections resulting from the movement of fine-grained 

minerals or the swelling of clays, an increase in water 

saturation and a consequent reduction in the relative 

permeability to gas, and chemical interactions between 

additives and mineral grains. In addition, the distribution 

of both gas and water in the reservoir must be known 

before production begins.

A knowledge of the geologic factors described 

above may help determine if gas from tight reservoirs can 

be included in the energy resource base of the United 

States. In addition, government land use policies may be 

a critical factor in determining future resources, because 

most basins having the potential for gas in tight reservoirs 

are in the Western United States and contain large areas 

of Federal land. Current knowledge of the geology of 

potential reservoir targets is not sufficient to make 

informed resource assessments.

0

l..._...

400 MILES

Figure 50. Basin areas in the United States containing tight reservoir rocks.

Higher Cost, Alternative Hydrocarbon Resources 65
Focus: Detailed Studies of Tight Gas Reservoirs

USGS studies of tight gas reservoirs have been 

concentrated in areas where test well projects of the U.S. 

Department of Energy and of industry offer large 

amounts of geophysical data and drill-core samples for 

the target rocks: the Department of Energy's Multiwell 

Experiment site in Garfield County, Colorado, a second 

site in the Piceance basin about 30 miles from the 

Multiwell Experiment site, and an area of several wells on 

the Pinedale anticline in the Green River basin of Wyoming. Syntheses of the structural and stratigraphic geology in each basin were done to provide a framework for 

detailed observations at the well sites.

Tight gas reservoirs in the Piceance basin are fluvial 

and marine sandstones of the Cretaceous Mesaverde 

Group and fluvial sandstones of the lower Tertiary 

Wasatch Formation (Spencer and Keighin, 1984). Most of 

the detailed studies have been concentrated on rocks of 

the Mesaverde Group. The character of these rocks is 

quite variable and is dependent on the original environments of deposition. The sediments were deposited along 

the margin of a seaway in marine, delta plain, and stream 

environments. Deposits of these environments interfinger 

in a complex fashion and are difficult to distinguish by 

using conventional well log analysis techniques.

Each rock type has distinctive textural and mineralogical characteristics that result both from original 

differences in deposition and from subsequent postdepositional changes. Understanding the character of these 

reservoir rocks and their thermal history and organicmatter alteration levels is important in designing engineering approaches to gas recovery.

The need for better geologic information as a basis 

for both exploration and production of gas in tight reservoirs of the Piceance basin or any other basin has been 

well stated by Chancellor and Johnson (1986, p. 351,357) 

in a report on cooperative industry-USGS research on five 

wells drilled in an area about 30 miles from the Multiwell 

Experiment site:

Based on production information to date, 

attempts at selecting intervals with comparatively better than average permeabilities using 

state of the art techniques were not successful. 

This study points out several important differences in the Mesaverde Formation/Group

between the area of the five wells and the 

MWX [Multiwell Experiment] site. Formation 

temperatures are higher and levels of thermal 

maturity are lower in the area of the five wells 

than at the MWX site. High formation pressures were encountered in the lower part of 

the Mesaverde Formation at the MWX site, 

while thus far, only near normal to slightly 

below normal pressures have been encountered in the Mesaverde Group in the area of 

the five wells.... Development of the gas 

resource will depend on: (1) the development 

of economic methods to stimulate thick intervals without blockage of matrix permeabilities; 

and (2) methods to define areas or formation 

intervals where effective permeabilities are 

somewhat higher than average. It is also 

important to define where gas generation 

occurred in the past, and areas where significant rates of gas generation are occurring 

today....The traditional use of state-of-the-art 

geophysical log analysis and available geologic 

information in the selection of intervals to 

stimulate, has not resulted in improved deliverability rates. The identification of areas or formation intervals of higher than average effective permeabilities, may require a greater 

understanding of the regional geologic setting, 

including the environments of deposition, and 

the diagenetic postdepositional history.

Studies in the Green River basin have produced a 

picture of similar complexity. Porosity and permeability 

in tight reservoir rocks typically depend on dissolution 

of rock fragments and distribution of carbonate 

cements, neither of which appears to follow a pattern. 

Geochemical studies aimed at determining the source 

of the gas indicate that, as suspected, the gas came from 

coals and carbonaceous shales interbedded with the reservoir sandstones. Research on organic alteration, past 

and present basin temperatures, and gas generation has 

led to a partial understanding of reservoir overpressuring, including prediction of areas and depths at which 

overpressured gas reservoirs may occur.

66 National Energy Resource Issues
GEOTHERMAL ENERGY RESOURCES

A vast amount of naturally occurring heat is stored 

in the Earth, but most of this geothermal energy is too 

deeply buried and too dispersed to be tapped for human 

use. Geothermal energy can be exploited only where it 

occurs in high concentrations at accessible depths, like 

concentrations of other natural resources such as ore 

deposits and petroleum accumulations. Currently, both 

high temperature at drillable depth and sufficient water or 

steam to transport the thermal energy to the surface are 

needed to exploit geothermal systems for electrical production or direct-heat use.

Geothermal energy currently provides only about 

0.2 percent of U.S. electrical needs. However, although 

use of geothermal energy in the United States is dwarfed 

by use of traditional fossil fuels, hydropower, and nuclear 

energy, USGS studies indicate that the geothermal 

resources of the United States are large. During the next 

decade, development of geothermal energy probably will 

remain focused on hydrothermal (hot water or steam in 

the ground) resources that could provide a few percent of 

the electrical generation capacity in some Western States. 

Great potential exists, however, for growth of geothermal 

utilization in direct-heat uses of lower temperature 

resources.

In considering geothermal energy, it is important to 

distinguish between the amount of geothermal energy 

stored in the ground and the lesser amount that can be 

extracted and recovered at the surface. The accessible 

geothermal resource base is the thermal energy in rocks 

and fluids at depths shallow enough to be reached by 

drilling in the foreseeable future, whereas the geothermal 

resource is that part of the accessible resource base that 

might be extracted economically at some future time, 

given reasonable advances in technology and economic 

favorability. Geothermal projects on line or under construction reflect development of geothermal reserves, that 

part of the geothermal resource extractable at a cost 

currently competitive with other energy sources. For 

long-term planning of energy policy, the magnitude of the 

resource is of greatest importance.

The geology of geothermal systems is related to 

resource development in the following ways:

 Both the geologic controls and the effects of sustained production and accompanying injection of 

spent fluids on the natural life expectancy of a 

geothermal system are not completely understood.

 The discovery of geothermal systems not yet identified because they lack obvious surface features 

such as hot springs, as well as the resource characterization of known hydrothermal systems for 

which reservoir temperature and volume currently 

may be underestimated, requires geologic information. Undiscovered geothermal resources are estimated to be several times greater than identified 

resources, and significant long-term growth in geothermal resource development depends on 

improved techniques for locating and evaluating 

the undiscovered component.

 Geothermal development has been limited to economically drillable depths, generally less than 2 

miles. Deeper parts of geothermal systems can be 

tapped for energy recovery when technological 

advances and economic factors permit, and geologic characterization of these root zones will be 

necessary.

GEOTHERMAL SYSTEMS AND THEIR 

DISTRIBUTION

Almost all development of geothermal resources 

has exploited hydrothermal convection systems in which 

the buoyant movement of hot water through rock pores 

and fractures concentrates thermal energy into restricted 

volumes or reservoirs (fig. 51). In the most common 

hydrothermal convection systems, hot pressurized water 

enters a drill hole and flashes in part to steam. This 

water-steam mixture flows up the well to the surface, 

where steam and water are separated; steam then is 

routed to turbines to generate electricity, and unwanted 

water is injected back into the ground. In the much less 

common vapor-dominated systems, steam is the predominant fluid phase at depth, and dry steam can be produced 

at the wellhead without the need to separate and dispose 

of large volumes of water.

Geothermal Energy Resources 67
Figure 51. Schematic cross section of a high-temperature hydrothermal 

system. Modified from White (1973, p. 76).

Although hydrothermal systems having temperatures of less than about 200 °C currently are not economical for separating steam from water for use in turbines, 

geothermal water from such systems can be used to heat 

a secondary fluid such as freon, which in turn drives 

turbines. Hydrothermal systems having temperatures of 

40 to 100 °C can be used for direct applications such as 

space heating and industrial drying.

Most high-temperature (greater than 150 °C) geothermal resources currently being exploited are associated with regions of recent volcanism, in which bodies of 

magma (molten rock) provide sources of heat and deeply 

penetrating faults foster circulation of water to depths 

where temperatures are high. These regions of high heat 

flow typically are along boundaries between the Earth's 

tectonic plates, at hot spots within plates, or along rift 

zones (fig. 52). In the United States, high-temperature

geothermal resources are in the Western States, and 

intermediate- (90-150 °C) and low-temperature (less 

than 90 °C) resources are more widely dispersed (fig. 53).

In 1978, the USGS estimated the identified resource 

in 215 known hydrothermal systems having temperatures 

greater than 90 °C and depths less than about 2 miles to 

be about 400 Quads (quadrillion Btu); the undiscovered 

resource was estimated to be 2,000 Quads. The part of 

the identified resource having temperatures greater than 

150 °C is equivalent to 23,000 megawatts of electricity 

for a 30-year period. In 1982, the USGS evaluated 1,161 

low-temperature (less than 90 °C) systems and estimated 

a resource of 87 Quads. Approximately 70 percent of this 

energy is contained in 42 systems in the Central United 

States, including aquifers of significant lateral extent, such 

as those that extend under much of Montana, North and 

South Dakota, and Wyoming.

68 National Energy Resource Issues
180° 180

o

<D O E? (Di

m3 o>

45

^

'

.tUIlt. /-1IIUTT3 JIIUTT

direction of relative 

movement

Rift or zone of normal 

faulting; teeth on downthrown block

Active ridges and continental 

extensions. Arrows indicate 

direction of relative plate motion

Subduction or overthrust zone; 

teeth on upper block

Figure 52. World distribution of geothermal fields from which electricity is being produced (open circles).

O (Ao>ID
B

Figure 53. Geothermal resources 

in the United States. A, Identified 

hydrothermal convection systems 

(greater than 90 °C) in the Western 

United States. Modified from Brook 

and others (1978, p. 32). B, Lowtemperature geothermal systems in 

the Western United States. Modified from Mariner and others (1983, 

fig. 13). C, Areas of low-temperature geothermal resources within 

a sedimentary basin or beneath a 

coastal plain in the Central and 

Eastern United States. Blue pattern 

indicates regional aquifers that 

contain low-temperature geothermal resources; red pattern indicates areas containing undiscovered resources; red circles denote 

resource areas of less than 100 

km2 ; blue circles denote resource 

areas containing thermal springs. 

Modified from Sorey and others 

(1983, figs. 14, 15).

70 National Energy Resource Issues
GEOTHERMAL ENERGY IN THE NATIONAL 

ENERGY MIX

The United States leads the world in geothermal 

electricity-generating capacity. In 1986,17 countries generated 4,733 megawatts of electricity from geothermal 

sources. In mid-1986, the geothermal capacity in California, Hawaii, Nevada, and Utah was approximately 2,000 

megawatts (table 6), and projects under construction or 

planned could increase this capacity to as much as 3,300 

megawatts in the next several years.

Table 6. Geothermal powerplants in the United States as 

of June 1986

State Field Capacity, in 

megawatts

California The Geysers

Imperial Valley 

East Mesa 

Salton Sea 

Heber

Wendell-Amadee 

Mammoth Lakes 

Hawaii Puna 

Nevada Wabuska Hot Springs 

Beowawe 

Steamboat Springs 

Desert Peak 

Utah- Roosevelt Hot Springs

Cove Fort 

Total installed capacity-- - - -

1,788

12.5

44.5

94

.6

7

3

.6

17

5.5

9

20

2.7

2,004.4

Most geothermal capacity in the United States is 

at The Geysers field in northern California. This large 

vapor-dominated system has been developed since 1960 

and consists of 19 separate powerplants having a capacity of almost 1,800 megawatts, enough to satisfy the 

electricity-generating needs of San Francisco and 

Oakland.

Direct-heat applications of geothermal energy for 

space heating, agriculture, aquaculture, and industrial 

processes are at hundreds of locations in the United 

States and supply about 210 megawatts of thermal 

energy. Identification of many areas containing 

low-temperature geothermal systems indicates large 

potential growth for this resource.

RESOURCE ASSESSMENT

A resource assessment is a statement made at a 

specific time and using a given data set and certain 

assumptions concerning economics and technology. Both 

the data set and the assumptions can change rapidly, and 

any assessment should be periodically updated. Geothermal assessments especially need to be revised regularly,

because exploration and development are rapidly increasing and because the worldwide energy situation is in a 

state of flux as countries try to come to grips with finite 

fossil fuel resources, environmental effects, nuclear waste 

disposal, and other issues.

Today's developed geothermal reserves represent 

only a fraction of the estimated geothermal resource in 

the United States. In 1975, the USGS completed the first 

national geothermal assessment based on a welldocumented methodology and constrained by specific 

data on the chemistry and physics of geothermal systems; 

in 1978, it updated this assessment, using a large body of 

new data. In 1982, the USGS published the first quantitative assessment of low-temperature geothermal 

resources, and it is now refining the 1978 estimate of the 

geothermal resources of the Cascade Range, an active 

volcanic belt extending about 740 miles from British 

Columbia into northern California.

GEOLOGIC RESEARCH AND EXPLORATION 

FOR HYDROTHERMAL RESOURCES

Exploration for geothermal energy usually begins 

with the selection of geologically favorable terranes, such 

as those containing hot springs and (or) young volcanic 

rocks. Several volcanic fields have been intensively studied 

as part of the USGS Geothermal Research Program: The 

Geysers-Clear Lake, Long Valley, and Coso fields in 

California; Newberry and Mt. Hood volcanoes in Oregon; 

the San Francisco Mountains in Arizona; Yellowstone 

National Park; the Snake River plain in southern Idaho; 

and the Cascade Range of Washington, Oregon, and 

northern California. These studies have greatly increased 

our knowledge of the processes of mass and energy 

movement within magmatic and associated hydrothermal 

systems.

Seismic techniques help characterize geothermal 

systems. Timing the passage of seismic waves from distant 

earthquakes can locate zones of partially molten rock 

within the Earth's crust. USGS studies have determined 

that molten material apparently underlies volcanic fields 

at Long Valley, The Geysers-Clear Lake area, and Coso 

in California, at Yellowstone National Park, and at Roosevelt Hot Springs in Utah. Another technique maps the 

paths of seismic waves generated by controlled explosions 

and has been used to delineate the structure of the crust 

beneath the Imperial Valley, an extensive geothermal area 

in southern California that has few surface hydrothermal 

features.

Geochemical techniques pioneered by USGS scientists allow subsurface temperatures within a geothermal 

reservoir to be estimated from the chemistry of thermal

Geothermal Energy Resources 71
water that leaks to the Earth's surface as hot springs or 

that is produced from shallow drill holes. These techniques greatly increase the chances of finding a hightemperature hydrothermal system before and during drilling and are applied worldwide as standard exploration 

tools. The USGS also has helped develop a variety of 

geophysical methods to map the lateral and vertical extent 

of a hydrothermal system in the shallow crust.

Hydrologic research provides information on the 

natural state of hydrothermal reservoirs and their behavior under production. Hydrologic analysis was a key 

element in the recent USGS assessment of lowtemperature geothermal resources. Hydrologic studies 

are important in understanding hydrothermal convection 

systems in Nevada, at Newberry volcano in Oregon, and at 

Lassen Volcanic National Park and Long Valley in California, and they are critical in understanding the enigmatic springs of the Cascade Range in Oregon. Computerassisted modeling is useful in estimating the rate and 

duration of production from a reservoir.

Research drilling is a relatively expensive and therefore infrequently used tool, but it allows direct testing of 

models of subsurface conditions. In 1981, the USGS 

drilled a 3,057-foot-deep hole at Newberry volcano and 

discovered a very high temperature zone (265 °C) beneath 

a 1,970-foot-thick zone of cooler ground water. The 

temperature-depth profile from the hole gives credence to 

the hypothesis that deep hydrothermal systems in the 

Cascade Range are blanketed by percolating snowmelt 

and rainwater and thus hidden from surface expression. 

Other hypotheses concerning both the deep parts of 

geothermal systems where mineralization may be occurring and the coupling of magma bodies and hydrothermal 

convection systems remain untested by surface and shallow measurements. Accordingly, the USGS, in conjunction with other Federal agencies, is promoting programs to 

drill into hotter and deeper levels of geothermal systems. 

In one of these programs, the U.S. Department of Energy 

recently has drilled to a depth of 10,564 feet in the Salton 

Sea field of California's Imperial Valley.

Focus: Geothermal Energy in California

Geothermal energy is an important part of 

California's total energy mix, providing about 5 percent of 

the State's electricity in 1986. In 1972, the USGS began a 

long-term multidisciplinary research program at The Geysers in northern California as one of the first projects of 

the newly funded Geothermal Research Program. This 

research effort has deciphered the volcanic and tectonic 

history of the area and inferred the location and properties of a crustal magma body (heat source for the 

hydrothermal system). Geochemical studies of the thermal waters, together with geologic and geophysical studies, were used to define the subsurface boundaries of the 

geothermal field. Seismic monitoring has established that 

small-magnitude earthquakes are induced by geothermal 

production but currently are not a hazard. Both seismic

monitoring and geochemical studies are continuing to 

determine the response of the natural system to sustained 

production.

The Imperial Valley, southeast of Los Angeles, also 

contains substantial geothermal resources. Recent development of several hot-water systems has demonstrated the 

technical and economic feasibility of generating electricity 

from geothermal fields having characteristics less favorable than those of The Geysers. Studies by the USGS at 

the Salton Sea field have helped decipher the geologic 

effects of hot saline brines in the geothermal system 

interacting at elevated temperature and pressure with 

sediments of the Colorado River delta. An extensive 

seismic survey of the Imperial Valley has delineated the 

subsurface structure of this unique region.

72 National Energy Resource Issues
URANIUM RESOURCES

Although nuclear power provides about 13 percent 

of the electricity consumed each year in the United States, 

its future is clouded by problems: increased timeliness and 

sharply increased costs for plant construction, regulatory 

and legal delays, and, above all, real and perceived issues 

of nuclear safety. Projections of modest levels of growth in 

electricity demand indicate a need either to start building 

more nuclear plants in the 1990's or to dramatically 

increase fossil-fuel (most likely coal) electricity-generating 

capacity. The latter option has its own problems, such as 

increased amounts of carbon dioxide in the atmosphere 

(the "greenhouse effect"), acid rain from sulfur emissions, and the resource availability issues discussed elsewhere in this volume.

The many problems surrounding nuclear energy 

have sharply curtailed domestic production of uranium. 

Most of the mines active during the early 1980's are now 

closed because of the precipitous drop in the demand for 

uranium and in its price. Competition from cheaper 

imported uranium has also put pressure on the domestic 

uranium mining industry.

Some exploration and mining activities persist 

despite market conditions. Two types of uranium deposits 

appear to offer economic potential at this time young 

surficial deposits (see Focus, "Surficial uranium deposits," p. 74) and mineralized breccia pipes and USGS

research is being directed toward understanding such ore 

occurrences. In addition, continuing analysis of information gathered during the uranium boom of the late 1970's 

and early 1980's is now producing significant new insights 

into the process of uranium mineralization and the mechanisms of formation of some of the most important 

uranium ore deposits in the United States (see Focus, "A 

new model for uranium mineralization in the San Juan 

basin of New Mexico," p. 76). Research continues on 

uranium geology in order to refine existing knowledge 

about the uranium resources of the United States, 

resources that will be needed if nuclear energy assumes 

renewed importance in the future.

The USGS is the repository of data from the $300 

million U.S. Department of Energy National Uranium 

Resource Evaluation (NURE) program. These data are 

of value in many regional geologic and resource investigations. A recent application of the NURE data and 

expertise in uranium geology is connected with the growing effort to assess and predict the occurrence and hazard 

potential of radon gas. Radon is a daughter product of the 

radioactive decay of uranium, and knowledge of the 

geologic habits of uranium underlies an understanding of 

radon in the geologic environments of rocks, soils, and 

ground water. This active research by the USGS is capitalizing on years of study of uranium geology and takes 

full advantage of the NURE data.

Uranium Resources 73
Focus: Surficial Uranium Deposits

Scientific studies and exploration currently are 

focused on surficial uranium deposits, a type of uranium 

accumulation that was recognized only a few years ago. 

These deposits typically have formed within the last 

12,000 years and are so young that radioactive decay has 

not yet produced enough daughter products to permit 

detection by using normal gamma-ray radiometric surveys. Instead, the deposits must be located by sampling 

and chemical analysis.

These young uranium deposits commonly are found 

in terranes containing granitic rocks from which surface 

waters can leach uranium. As the mobile uranium moves 

downslope with shallow ground water, it comes in contact 

with organic materials along small stream drainages and 

is precipitated or absorbed from solution. Significant 

concentrations of uranium have been found in boggy 

meadows along valleys at the drainage divides between 

streams, in swamps impounded by beaver dams, in bogs 

around lake margins, and in swamps or meadows in flood 

plains and cutoff river meanders. The distribution of the 

uranium in these young deposits depends both on the

water flow and on the permeability of the interlayered 

peat and stream sediments. In areas where the principal 

flow of surface and shallow ground water is down the axis 

of the valley, uranium is concentrated at the upstream 

edges of valley bogs and swamps. In valley settings where 

ground water wells up beneath the organic-rich environment, uranium is concentrated at the bottom of organicsediment columns. In spring-fed meadows along valley 

slopes, uranium is most concentrated near the surface, 

and its concentration decreases downward through the 

peat and sediments.

One surficial deposit has been mined along Flodelle 

Creek in northeastern Washington State. The climate, 

water flow, source rocks, and peat accumulation pattern 

in that area are highly favorable for the formation of 

surficial uranium deposits. The Flodelle Creek deposit 

probably contains about 1 million pounds of uranium 

oxide and has an average grade of 0.08 percent, similar to 

the grade of sandstone-hosted uranium deposits long 

mined in the United States. Similar deposits have been 

found in relatively similar geologic settings in northeastFigure 54. Infrared aerial photograph of the Carson Range, just east of Lake Tahoe. Bright red delineates areas of 

deciduous vegetation along stream bottoms, along which both organic matter and uranium leached from rocks of the 

Carson Range have accumulated. Twenty-two surficial uranium deposits have been found along these drainages.

74 National Energy Resource Issues
400 MILES

Figure 55. Surficial uranium deposits in the United States. Blue indicates areas known to contain surficial uranium 

deposits; red indicates areas believed to contain surficial uranium deposits.

ern and northwestern Washington State, north-central 

Idaho, the Sierra Nevada in California (fig. 54), the 

Colorado Front Range, and Maine (fig. 55).

The radioactivity of surficial uranium deposits is 

relatively low. Health hazards in mining are minimal, and 

mining spoils generally can be returned directly to the 

mine without treatment. The ore occurs as loose material 

at the surface and can be removed by using light equipment and, consequently, at low cost. The ore is porous 

and permeable, and little preparation is required before 

direct extraction of the uranium; some ore may be amenable to in-place leaching techniques. In addition, the

deposits are suitable for small-scale mining and milling 

operations. Deposits typically cluster along a stream 

course, and ore from individual deposits can be fed to 

a centrally located mill.

Uranium is a highly mobile element; its poisonous 

effects are similar to those of arsenic, and it is a carcinogen after long-term accumulation in the human body. 

Uranium moving in ground or surface water, either 

before precipitation by organic matter or after remobilization from its precipitate habitat, can be of environmental 

concern in populated areas. Continuing USGS studies of 

surficial uranium deposits are aimed at both the resource 

and the hazard aspects of uranium.

Uranium Resources 75
Focus: A New Model for Uranium Mineralization in the San Juan Basin of New Mexico

Key new field and laboratory studies of uranium 

deposits and their associated rocks and years of observations and insights attained by many geologists have been 

used to construct a conceptual model explaining the 

location and origin of the ore deposits in the most 

important uranium district in the United States (TurnerPeterson and Fishman, 1986). A basin analysis method 

was used to achieve an understanding of the depositional 

setting of the ore-host sandstones and the overlying 

volcanic ash-rich sedimentary units and of the probable 

source of the organic material that acts as a trap for the 

uranium.

The Late Jurassic (about 140 million years ago) 

tectonic setting of the San Juan basin in northern New 

Mexico was integral to ore genesis. Uplift in a magmatic 

arc region hundreds of miles west of the Jurassic basin 

established the stream gradients necessary to deliver 

sediment to the subsiding basin and resulted in deposition 

of the host sandstones of the Westwater Canyon Member 

of the Morrison Formation. Throughout Morrison time, 

volcanism in the arc region supplied abundant volcanic 

ash. This ash accumulated and was preserved most abundantly in a saline-alkaline lake atop the Westwater Canyon sandstones. It formed the Brushy Basin Member, and 

its chemistry was a key element in controlling pore-water 

composition in the Morrison Formation.

The ore occurs as a pore-filling uranium-organic 

matter mixture in the sandstones, and the main ore 

control is the organic material (fig. 56). Detailed examination of the rocks indicates that the organic material was 

introduced into the host sandstones soon after deposition 

and then served to precipitate uranium from groundwater percolation through the rock. Several lines of evidence indicate that organic material in ore zones was 

derived from humic material, and the source of this 

organic material is the main concern in ore genesis.

Defining the depositional environments of the 

Brushy Basin Member constrained reconstructions of the 

geometry of the Jurassic basin and also explained orerelated alteration patterns in Morrison sandstones. These 

alteration patterns in turn aided reconstruction of orerelated hydrology and pointed to the Brushy Basin Member as a source for the organic material. The geometry of 

the Jurassic basin can be accurately inferred because 

saline-alkaline lakes develop only in closed-basin settings 

and because mapping of late-growth (postdepositional) 

mineral distributions in the lake sediments has defined the 

paleolake basin. The Jurassic lake extended well north of 

the present-day San Juan basin margin. Organic-bearing 

pore water descending from these paleolake sediments 

altered underlying sandstones, and mappable lateral 

trends in these altered areas are parallel with lateral

Figure 56. Organic-rich uranium ore (black layer) in sandstone of the Westwater Canyon Member of the Morrison 

Formation in the San Juan basin of New Mexico.

76 National Energy Resource Issues
changes observed in late-growth mineral occurrences in 

the overlying lake sediments. Mineralogical changes in 

the ore-host sandstones reflect this downward movement 

of pore fluids. Alteration of iron oxide grains can be 

directly related to movement of organic-bearing fluids, 

and detailed mapping of the altered mineral grains indicates that the mudflat-deposited sediments of the Brushy 

Basin Member are the source of these fluids. For this 

reason, ore is restricted to sandstones that received fluids

from the mudflat-deposited part of the Brushy Basin 

Member (fig. 57).

The conceptual model provides a new picture of 

Morrison basin sedimentation history and an explanation 

for the source of the organic material that trapped the 

uranium. This new understanding of the process of mineralization explains the geologic control of the location of 

uranium deposits and thus offers a guide for future 

exploration.

CENTRAL 

PLAYA

PLAYA

MUD FLAT

ALLUVIAL 

PLAIN

NORTH

SOUTH

Figure 57. Distribution of sedimentation zones in the Brushy Basin Member of the Morrison 

Formation marking different environments in a saline-alkaline playa lake of Jurassic time. Fluid 

moving downward from the mudflat zone (arrows indicate direction of fluid flow) altered or destroyed 

Fe-Ti (iron-titanium) oxide minerals in the underlying Westwater Canyon Member and created the 

conditions necessary for the precipitation of uranium in ore deposits (black lenses) in the San Juan 

basin of New Mexico. Modified from Turner-Peterson and Fishman (1986).

Uranium Resources 77
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