U.S. Natural Gas Availability: Conventional

Gas Supply Through the Year 2000

September 1983

NTIS order #PB84-114909
Recommended Citation:

U.S. Natural Gas Availability: Conventional Gas Supply Through the Year 2000-A Technical Memorandum (Washington, D. C.: U.S. Congress, Office of Technology Assessment,

OTA-TM-E-12, September 1983).

Library of Congress Catalog Card Number 83-600584

For sale by the Superintendent of Documents,

U.S. Government Printing Office, Washington, D.C. 20402
—.

Foreword

This technical memorandum is an interim product of OTA’s assessment of “U.S.

Natural Gas Availability. ” The assessment is examining the future potential for production of all forms of natural gas in the U.S. Lower 48 States, emphasizing the time

frame 1990-2000. Gas production in this period will depend primarily on gas that will

be made available from the growth of already-discovered fields, from new discoveries

of conventional gas, and from the exploitation of those “unconventional” gas sources

that today are close to commercial feasibility. The House Committee on Energy and

Commerce and its Subcommittee on Fossil and Synthetic Fuels requested the assessment, and the request was endorsed by the Subcommittee on Energy Research and

Development of the Senate Committee on Energy and Natural Resources.

This technical memorandum discusses the future availability of conventional gas—

gas that can be produced at prices and with technology that are relatively close to today ’s.

We first examine the efficacy of different generic resource assessment methods, review

specific estimates (including those of the U.S. Geological Survey and the Potential Gas

Committee), present alternative arguments concerning specific areas of uncertainty such

as the amount of gas to be found in small fields, and describe OTA’s conclusions about

a plausible range for the size of the conventional gas resource. Next, we discuss trends

in reserve additions and production, leading up to a projection of production potential

to the year 2000. Finally, we review the potential from gas sources other than domestic

production.

The material in this technical memorandum is being released at this time to assist

Congress during the current debate over natural gas. The material will also be incorporated, along with OTA’s analysis of unconventional gas sources, in a final assessment report to be published at the conclusion of the U.S. Natural Gas Availability study.

OTA is grateful for the assistance of its assessment advisory panel, its contractors,

its colleague; at the Congressional Research Service and U.S. Geological Survey, and

the many others who provided advice and information. However, OTA assumes full

responsibility for this technical memorandum, which does not necessarily represent the

views of individual members of the advisory panel.

.,,

Ill
U.S. Natural Gas Availability Advisory Panel

William Vogely, Chairman

Department of Mineral Economics, Pennsylvania State University

Marc Cooper Lawrence Moss

Research Director Independent Consultant

Consumer Energy Council of America Estes Park, Calif.

Lloyd Elkins Roy E. Roadifer

Petroleum Consultant Chief Geologist

Tulsa, Okla. Mobil Oil Corp.

Ed Erickson Benjamin Schlesinger

Professor of Economics and Business Principal

North Carolina State University Booz, Allen & Hamilton, Inc.

Daniel Grubb

Vice President of Gas Supply

Natural Gas Pipeline Company of America

John Haun

Professor of Geology

Colorado School of Mines

Donald Kash

George Lynn Cross Research Professor of

Political Science, and Research Fellow

Science and Public Policy Program

University of Oklahoma

John C. Sharer

Assistant Director

Unconventional Natural Gas

Gas Research Institute

John Weyant

Deputy Director

Energy Modeling Forum

Stanford University

John Schanz

Senior Specialist in Energy Resource Policy

Congressional Research Service

Harry C. Kent

Director

Potential Gas Agency

ACKNOWLEDGMENTS

Many people contributed to this technical memorandum by providing information, advice, and substantive

reviews of draft materials. We would like to acknowledge the valuable contributions of the following individuals:

●

●

●

●

●

●

Lawrence Drew, David Root, John Houghton, ●

Richard Meyer, U.S. Geological Survey, Reston,

Va. ●

Dudley Rice, Gordon Dolton, U.S. Geological ●

Survey, Denver, Colo.

Richard O’Neill, Energy Information Administration, U.S. Department of Energy ●

Thomas Woods, Gas Research Institute ●

Paul Ching, Shell Oil Company ●

Wallace Howes, Natural Gas Pipeline Company

of America

Robert Kalisch, Michael German, Jeffrey

Wingenroth, American Gas Association

John Scheunemayer, University of Delaware

J. N. Sommerfrucht, David White, Bill James,

Robert Megill, Warren Strickland, W. R. Finger,

Exxon Company, U.S.A.

William Fisher, University of Texas at Austin

Scott Farrow, Carnegie Mellon University

Gary Pagliano, Congressional Research Service

iv
OTA U.S. Natural Gas Availability Project Staff

Lionel S. Johns, Assistant Director, OTA

Energy, Materials, and International Security Division

Richard E. Rowberg, Energy and Materials Program Manager

Steven E. Plotkin, Project Director

Julia C. Crowley, Unconventional Gas Sources

Vykie G. Smoyer, Natural Gas Basics, Other Sources

David Strom, Computer Supply Models

Administrative Staff

Lillian Quigg Edna Saunders

Other Contributors

Joseph Rival Congressional Research Service

Kathryn White, Independent consultant: editor

Contractors and Consultants

Richard Nehring, Pacific Palisades, Calif.

Jensen Associates, Inc., Fairfax, Va.

OTA Publishing Staff

John C. Holmes, Publishing Officer

John Bergling Kathie S. Boss Debra M. Datcher Joe Henson

Glenda Lawing Linda A. Leahy Cheryl Manning

v
Contents

Chapter Page

1.

2.

3.

4.

5.

SUMMARY ., . . . . . . . . . . . . . . . . . . . . . . . . . . 3

Introduction .........,...,..........,,. 3

Major Findings . . . . . . . . . . . . . . . . . . . . . . . . 3

Natural Gas Production Potential . . . . . . . . 4

Uncertainty 1: The Gas Resource Base... 5

Uncertainty 2: Interpretation and

Extrapolation of Discovery Trends ..., 8

Uncertainty: Production From Proved

Reserves—The R/P Ratio . . . . . . . . 10

Summary of Assumptions and Conditions

Underlying OTA’s Projections . . . . . . 11

Other Sources of Lower 48 Supply . . . . . . . . 11

INTRODUCTION. ...,.. . . . . . . . . . . . . . . . . 15

NATURAL GAS BASICS . . . . . . . . . . . . . . . . 21

What is Natural Gas? . . . . . . . . . . . . . . . . . . . 21

How Does Natural Gas Form? . . . . . . . . . . . . 21

Where is Natural Gas Found? . . . . . . . 21

How is Natural Gas Discovered?.. . . . . . . . 23

How is Natural Gas Produced? . . . . . . . 26

THE NATURAL GAS RESOURCE BASE . 29

Resource Base Concepts. . . . . . . . . . . . . . . . . . 29

Approaches to Gas Resource Estimation . . . 31

Geologic Approaches . . . . . . . . . . . . . . . . . . 32

Historical Approaches ..., . . . . ..., 3 3

Dealing With Uncertainty . . . . . . . . . 36

Comparison and Review of Individual

Estimates. . . . . . . . . . . . . . . . . . . . . . . . . 38

U.S. Geological Survey . . . . . . . . . . . . . 38

Potential Gas Committee. . ., . . . . . . . . 40

RAND/Nehring . . . . . . . . . . . . . . . . . . . . . . . 42

Hubert . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44

Reconciling the Different Estimates . . . . . . 46

Is There A Consensus?. . . . . . . . . . . . 46

How Credible Are the Methods? . . . . . . . 49

Are the Physical Implications of the

Assessments Plausible? . . . . . . . . . . . . . 50

A Break With Past Trends? . . . . . . . . . . . . 50

Some Alternative Explanations. . . . . . . . 56

Conclusions . . . . . . . . . . . . . . . . . 65

GAS PRODUCTION POTENTIAL . . . . . . . . 69

Approach Number l—Projecting Trends in

the Individual Components of

Reserve Additions. . . . . . . . . . . . . . . . . . . 70

New Field Discoveries . . . . . . . . . . . 70

Extensions and New Pool Discoveries, . . 74

Revisions. . . . . . . . . . . . . . . . . . . . . 78

Reserves-to-Production Ratio . . . . . . . 8 1

Production Scenarios . . . . . . . . . . . 84

Approach Number 2—Projecting New Pool

Discoveries, Extensions, and Revisions

as a Single Growth Factor. . . . . 86

Chapter Page

6.

Approach Number 3—Region-by-Region

Review of Resources and Exploratory

Success . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

Approach Number 4—Graphing the

Complete Production Cycle . . . . . . . . . . 91

A Range for Future Gas Production . . . . . . . 92

Public and Private Sector Forecasts of

Future Gas Production. . . . . . . . . . . . . . 94

OTHER GAS SOURCES–SUMMARY . . . . 99

Mexico . . . . . . . . . . . . . . . . . . . . . ...........100

Canada . . . . . . . . . . . . . . . . . . . . . . . . ........101

Alaska . . . . . . . . . . .......................102

Liquefied Natural Gas . ..................103

Appendix A: Glossary . ....................107

Tables

Table No. Page

1.

2.

3.

4.

5.

6.

7,

8.

9.

10.

11.

12.

13.

14.

15.

Gas Production Forecasts . . . . . . . . . . . . . . . . 5

Alternative Estimates of Remaining

Conventional Natural Gas Resources in

the U.S. Lower 48 States . . . . . . . . . . . . . . . . . 5

Bases for OTA’s Projections of Natural

Gas Production—Baseline Assumptions:

Good Market Conditions, Readily

Foreseeable Technology . . . . . . . . . . . . . . . . . . 11

Estimated Total U.S. Proved Reserves of

Natural Gas–1977-81 . . . . . . . . . . . . . . . . . . . 25

Why It Is Difficult to Compare Resource

Estimates. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Alternative Estimates of Ultimately

Recoverable and Remaining Natural Gas

in the United States . . . . . . . . 38

Comparison of Potential Gas Committee

Estimates of Ultimately Recoverable Gas

Resources in the Lower 48 States . . . . . . . . . . 41

Field Discovery Implications of USGS

Circular 725, Onshore Lower 48

Undiscovered Petroleum Resource. . . . . . . . 44

Hubbert’s Estimates of Ultimately Recoverable

Gas Resources in the Lower 48 . . . . . . . . . . . 45

The Optimist’s View of Gas Resources. . . . . 48

The Pessimist’s View of Gas Resources ..., 48

Returns to New Field Wildcat Drilling in

the Onshore Lower 48 States, 1966-81 . . . . 51

Historical Record: Number of New Gasfield

Discoveries Proved After Six Years

To Be of Significant Size . . . . . . . . . . . . . . . . 53

Oil and Gas Drilling Success Rates . . . . . . . 58

Potential Recoverable Gas Resources

From New Discoveries in the Permian Basin 62

vii
Table No. Page

16

17.

18.

19.

20.

21.

22.

23.

24.

25.

26.

27.

28.

Additions to Lower 48 Natural Gas Proved

Reserves: Extensions and New Pool

Discoveries, 1966-81 . . . . . . . . . . . . . . . . . . . . . 76

Summary of Projections of Components

of Reserve Additions and R/Ps . . 85

Lower 48 States Natural Gas Production

and Reserves 1981-2000—Scenario 1A:

Optimistic Exploration, Rapid Production . 85

Lower 48 States Natural Gas Production

and Reserves 1981-2000—Scenario 1B:

Pessimistic Exploration, Slowed Production 86

Arguments for the Question, “Will the

Reserve Growth in New Fields Be Larger or

Smaller Than the Growth Recorded in

Previously Discovered Fields?’’ . . . . . . . . . . . . 87

Alternative Estimates of Growth Factors

for Initial Reserve Estimates for Gasfields

Lower 48 States Natural Gas Production

and Reserves, 1982-2000—Scenario 2A:

Very Optimistic. . . . . . . . . . . . . . .

Lower 48 States Natural Gas Production

and Reserves, 1982-2000—Scenario 2B:

Pessimistic ..., . . . . . . . . . . . . . . .

Lower 48 States Natural Gas Production

and Reserves, 1982-2000—Scenario 2C:

Very Pessimistic . . . . . . . . . . . . . . . . .

. . 88

. . 88

. 89

89

Lower 48 States Natural Gas Production and

Reserves, 1982-2000—Scenario 3A. . . . . . . . . 90

Lower 48 States Natural Gas Production and

Reserves, 1982-2000—Scenario 3B . . . . . . . . . 90

A Comparison of Conventional Lower 48

Natural Gas Supply Forecasts . . . . . . . . . . . . . 95

Natural Gas Imports Summary Table... 99

Figures

Figure No. Page

1.

2.

3.

4.

5.

6.

7.

8.

9.

Alternative Concepts of the Natural Gas

Production Cycle If Remaining Resources

Equal 400 TCF . . . . . . . . . . . . . . . . . . . . . . 6

Natural Gas Production: Additions to

Reserves, and Total Reserves of the Lower

48 States . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Known Oil- and Gas-Bearing Areas in the

Lower 48 States. . . . . . . . . . . . . . . . . . . . . . . . 22

Four Requirements for Petroleum

Accumulation. . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Trapping Mechanisms . . . . . . . . . . . . . 23

AAPG and API Classification of Wells . . . . 24

Production Mechanics . . . . . . . . . . . . . . . . . . . 26

The McKelvey Box . . . . . . . . . . . . . . . . . . 30

Discoveries of Recoverable Natural Gas in

the Lower 48 States v. Cumulative

Exploratory Drilling . . . . . . . . . . . . . . . . . 34

Figure No, Page

10.

11.

12.

13.

14.

15.

16.

17.

18.

19.

20.

21.

22.

23.

24.

25

Probability Distribution for Undiscovered

Recoverable Gas Resources in a Province . . 36

Number of Gasfields Discovered As a

Percentage of New Field Wildcats Drilled,

by Field Size Grouping . . . . . . . . . . . . . 54

Number of Gasfields Discovered per Year,

by Field Size Grouping . . . . . . . . . . . . . 54

Gas Potential, Gas Well Completions, and

Expenditures—1978. . . . . . . . . . . . . . . . . . . . . . 57

New Field Wildcat Success Rate, 1966-81 58

Size Distribution of Discovered Oil and

Gas Fields in the Lower 48 States . . . . . . 60

Known and Projected Size Distributions of

Discovered Oil and Gas Fields in the Lower

48 States ., . . . . . . . . . . . . . . . . . . . . . . 62

Natural Gas Production From 1981 Lower

48 Proved Reserves. . . . . . . . . . . . . . 69

Additions to Lower 48 Natural Gas Proved

Reserves: New Field Wildcat Discoveries,

1966-81 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Additions to Lower 48 Natural Gas Proved

Reserves: Extensions and New Pool

Discoveries, 1966-81 . . . . . . . . . . . . . . . . . . 75

Additions to Lower 48 Natural Gas Proved

Reserves: Revisions As Reported, 1966-81. . 79

Additions to Lower 48 Natural Gas Proved

Reserves: Revisions As Amended, 1966-81 80

Reserve-to-Production Ratios for Natural

Gas in the Lower 48 States . . . . . . . . . . . 83

The Growth of Year-of-Discovery Estimates

of the Amount of Recoverable Natural

Gas Discovered in the Lower 48 States . . . . 86

Future Production Curves for Conventional

Natural Gas in the Lower 48 States . . . . . 92

Two Production Futures, One Resource

Base: Alternative Representations of Future

Production of Conventional Natural Gas

in the Lower 48 States, Based on the USGS

Resource Assessment ., . . . . . . . . . . . . . . 93

Boxes

A.

B.

c.

D.

E.

Page

Does the Monte Carlo Technique

Underestimate Uncertainty? . . . . . . . . . . . . . . 37

Rand Assessment’s Arguments Against a Large

Undiscovered Oil and Gas Resource Base . . 43

A Very Brief History of Petroleum

Exploration . . . . . . . . . . . . . . . . . . . . .......47

Are the USGS and PGC Gas Resource

Assessments Really Similar? . . . . . . . . . . . . . . 49

Sources of ’’New Gas From Oil Fields’’. . . . . 63

. . . Vlll
Chapter 1

Summary
Chapter 1

Summary

.—

INTRODUCTION

Within the last 5 years or so, the general perception about the outlook for future U.S. gas supplies has moved from pessimism to considerable

optimism. The pessimism was based partly on

short-term problems, such as periodic regional

shortages, and partly on disturbing long-term

trends, such as the declining finding rate for new

gasfields and, since the late 1960’s, the ominous

and apparently unstoppable decline of proved

reserves. The new optimism is based on several

factors, including the gas “bubble” caused by

declining gas demand coupled with high gas

deliverability, the rebound of reserve additions

to levels which exceeded production in 1978 and

1981, and continuing optimistic estimates 01” domestic gas resources by the U.S. Geological Survey (USGS) and the industry-based Potential Gas

Committee (PGC).

What does this apparent change in the outlook

for U.S. natural gas supply mean? Can we now

count on natural gas to play a major, perhaps

even expanded role in satisfying U.S. energy requirements, or is the seeming turnabout only a

temporary respite from a continuing decline in gas

reserve levels and, soon to follow, a decline in

gas production capabilities?

MAJOR FINDINGS

Certain technical uncertainties—primarily those

associated with incomplete geological understanding, alternative interpretations of past discovery

trends, and difficulties in projecting likely patterns

of future gas discoveries—are so substantial that

by themselves they prevent a reliable estimation

of the remaining recoverable gas resource and the

likely year 2000 production rate. Even after ignoring the potential for significant changes in gas

prices and technology in the future, OTA could

not narrow its range of estimates of resources and

future production beyond a factor of 2 from the

lowest to the highest estimate. Inclusion of uncertainties associated with changing gas prices and

This technical memorandum presents the first

phase of OTA’s assessment of these questions: an

evaluation of the future prospects for the discovery and production of conventional natural gas

in the Lower 48 States. The memorandum examines the gas resource base and future production

potential under the following conditions:

. wellhead prices are assumed not to change

substantially from today’s levels in real

terms,

. new technologies that are not readily foreseeable extensions of existing technology are

not considered, and

• demand is assumed to be high enough to

avoid reductions in production potential due

to curtailment of investments in exploration

and production.

The memorandum also summarizes the prospects

for additional conventional supplies to the Lower

48 from pipeline imports from Canada, Alaska,

and Mexico, liquefied natural gas (LNG) imports,

and synthetic gas from coal. The final report of

OTA’s assessment also will evaluate the so-called

“unconventional” sources of natural gas—gas in

tight sands, Devonian shales, coal seams, and geopressurized brines.

market demand and the continuing evolution of

gas exploration and production technology would

undoubtedly widen the range still further.

Specific findings of the study are as follows:

● Current proved reserves in the Lower 48

States will supply only a few trillion cubic

feet (TCF) per year of production by the year

2000. All other domestic production must

come from gas which has not yet been identified by drilling.

Ž There is no convincing basis for the common

argument that the area of the Lower 48 States

is so intensively explored and its geology is

3
4

●

●

so well known that there is a substantial consensus on the magnitude of the gas resource

base. Plausible estimates of the amount of remaining conventional natural gas in the Lower 48 States that is recoverable under present

and easily foreseeable technological and economic conditions range from 400 to 900 TCF.

At the lower end of this range, production

in the year 2000 will be seriously constrained

by the magnitude of the resource base.

Assuming market conditions favorable to gas

exploration and production and no radical

changes in technology or gas prices, plausible estimates of the year 2000 production potential of conventional natural gas in the

Lower 48 States range from 9 to 19 TCF/yr.

In 1990 production is likely to be anywhere

from 13 to 20 TCF/yr.

Because it is unclear whether the recent surge

in the rate of additions to proved gas re-

●

●

✎

serves’ is sustainable, the range of plausible

annual reserve additions is wide even for the

near future. The range for the Lower 48

States for 1986 and beyond is from 7 or 8

TCF/yr up to 16 or 17 TCF/yr, assuming

that the current excess of gas production capacity ceases and market conditions improve.

The rate at which gas can be withdrawn from

proved reserves, or R/P (reserves-to-production) ratio, may range from 7.0 to 9.5 as a

national average by the year 2000, further

adding to the difficulty of projecting future

production potential.

An important source of uncertainty in evaluating past discovery trends is the lack of

publicly available, unambiguous, disaggregate data about gas discoveries.

● The 1981 addition was about 21 TCF versus about 10 TCF/yr

or less for 1969-77.

NATURAL GAS PRODUCTION POTENTIAL

OTA finds insufficient evidence on which to

base either an optimistic or a pessimistic outlook

for conventional domestic gas production. Given

market conditions favorable to gas exploration

and production, the production of natural gas

from conventional sources within the Lower 48

States could range from 9 to 19 TCF/yr by the

year 2000. Similarly, production in the year 1990

could range from 13 to 20 TCF/yr. * These ranges

do not include gas from pipeline or LNG imports,

synthetic gas from coal or other materials, or gas

from unconventional sources that are not producing today. They do include gas from low-permeability reservoirs that is currently economically

recoverable, even though this gas is borderline

conventional and might be considered unconventional by some assessors.

OTA’s wide range for plausible levels of conventional gas production in the Lower 48 States

in the year 2000 is in sharp contrast to the relatively narrow range displayed in publicly available

forecasts. Table 1 presents the summarized results

of 20 separate forecasts from oil companies, other

*Current annual production is about 18 TCF/yr, and actual production capacity is probably 1 or 2 TCF/yr higher.

private institutions and individuals, and Government agencies. A striking feature of this group of

forecasts is that 13 of the 14 forecasts that project a year 2000 production level fall within 11

to 15 TCF/yr. This high level of agreement for

a production rate two decades in the future is

made all the more unusual by the probability that

there are substantive differences in the baseline

assumptions used by the various forecasters. The

high level of agreement might, however, reflect

the probability that the forecasts are not all independent, original estimates; some may simply

be averages of other forecasts, reflecting the “conventional wisdom, ” and some may have been influenced by others that preceded them.

The wide range in OTA’s projection of future

gas production reflects the existing high degree of

uncertainty about:

1.

2.

3.

the magnitude and character of the gas resource base;

the appropriate interpretation and extrapolation of past trends in natural gas discovery, and;

the rapidity with which gas in proved reserves can be produced, expressed as the reserves-to-production (R/P) ratio.
.

5

Table 1 .—Gas Production Forecasts (in trillion cubic feet)

.

Government

Oil companies Other private agencies Average OTA

1985

Lowest . . . . . . . . . . . . . . . . . . . . . . . .

Average . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Highest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1990

Lowest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Average . . . . . . . . . . . . . . . . . . . . . . . . . .

Highest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2000

Lowest ., . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Average . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Highest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Number of individual forecasts ..., . . . . . . . . . . . .

17.0

18.7

19.5

13.9

17.1

18.8

8.9

13.5

14.6

9

15.5

17.1

18.3

13.6

15.4

17,7

11.6

12.2

13,5

6

16.5

17.3

18.0

14.3

15.1

15.5

12,8

13.1

13.5

5

—

17.9

—

—

16.7 —

—

13,1

—

—

—

—

—

13

—

20

9

—

19

—

NOTE All forecasts calculate gas on’’dry’’bas!s at standard temperature and pressure Some forecasts include unconventional sources of supply, suchas t!ghi sands

and DevonIan shales; others Include only conventional sources

SOURCE Off)ceof Technolofw Assessment, based ondataln Jensen Associates, Inc “Understandin~ Natural Gas Supply lntheUS “ contractor report to the OffIce

of Technology Ass;”ssment, April 1983

The first two sources of uncertainty are inseparable; the magnitude and character of the resource

base have played—and will continue to play—

an important role in shaping trends in gas discovery, and these trends in turn provide important clues to gauging the remaining resource base.

Consequently, uncertainties in trend interpretation automatically contribute to uncertainties in

resource assessment, and resource uncertainties

in turn complicate the processor projecting future

discovery trends. Similarly, estimating future R/P

ratios will depend on projecting discovery trends

and understanding the character of the remaining resources.

Each of the three sources of uncertainty will be

discussed in turn.

Uncertainty 1: The Gas Resource Base

Many individuals and organizations have published assessments of the natural gas resources of

the Lower 48 States. Table 2 presents seven such

estimates of the gas resources that remained in the

Lower 48 at the beginning of 1983. They range

from Hubbert’s 244 TCF to the PGC’s 916 TCF.

The resource estimates at high and low ends of

the range in table 2 have quite different messages

for gas production forecasters. At the upper end,

the USGS and PGC estimates imply that gas production in this century will be relatively unconstrained because of the resource base magniTable 2.—Alternative Estimates of Remaining

Conventional Natural Gas Resourcesa in the

U.S. Lower 48 States (as of Jan. 1, 1983)

Trillion

Sourceb (publication date) cubic feet

Hubbert (1980) . . . . . . . . . . . . . . . 244

RAND Corp. (1981). . . . . . . . . . . . . . 283

Shell (1977) . . . . . . . . . . . . . . . . . . . . . . 320

Bromberg/Hartigan (1975). . . . . . 340

Wiorkowsky (1975) . . . . . . . . . . . . . . . . 663

U.S. Geological Survey (1981) . . . . . . 774

Potential Gas Committee (1983) . . . . 916

aThe term “resources” includes proved reserves, expected growth of existing

fields, and undiscovered recoverable resources In all but the Hubbert estimate,

the term does not trrclude gas not recoverable by current or readily foreseeable

technology nor gas not recoverable at price/cost rattos similar to today’s

bln most cases, the sources for these est!mates were assessments of either the

ultimately recoverable resource or the undiscovered resource base The

est I mates shown are derived by subtract! ng cumulat Ive product Ion from

estimates of ultimately recoverable e resource or by adding proved reserves and

expected growth of known fields to esttmates of the undiscovered resource

Where ranges of resource est!mates are given by the source, the estimate In

this table IS based on the mean value

SOURCE Office of Technology Assessment, 1983

tude—although this does not rule out the possibility that production may be sharply constrained by

the character of the remaining resources. * In contrast, estimates at the lower end—Shell, Hubbert,

RAND, and Bromberg/Hartigan—imply a serious

resource constraint. If these estimates are correct,

gas production will decline substantially by the

year 2000 (see fig. 1). Therefore, selection of a

“best” resource estimate, or narrowing of the

range, could conceivably have profound implications for expectations of future gas production. ————

*For example, by their location, depth, degree of contamination,

and size distribution of fields and reservoirs.
6

Figure 1 .—Alternative Concepts of the Natural Gas Production Cycle If Remaining Resources = 400 T CF

(conventional gas only)

—

30 t

Curves A and B represent two conceptions of how the production cycle for natural gas in the Lower 48 might be completed If

the remaining resources as of December 31, 1982, were 400

TCF Curve B represents a future where explorers and pro.

ducers work extremely hard to maintain production at high

levels for as long as possible But even in this situation, pro.

duction drops drastically by the year 2000 Curves can be

drawn that would allow production to remain high through

2000 while obeying a resource constraint of 400 TCF, but these

curves would not be realistic. A substantial portion of the remaining resource cannot be produced quickly enough

because it IS located in small fields, which require many exploratory wells and many years to find, or in low permeability

reservoirs, which typicalIy release smalI quantities of gas over

long periods of time

9 “

8 “

7 “

6

5 .

\ \

4

3 “

2 .

1

0

Yea r

Some of the differences in the estimates may

merely be the result of differences in baseline assumptions or boundaries. For example, various

assessments may use different assumptions about

economic conditions and the state of exploration

and recovery technology and may have different

geographical boundary conditions. They may or

may not include areas currently inaccessible to development, gas from portions of tight sands or

other “unconventional” sources that are presently recoverable, or nonmethane components of the

gas. Finally, assessments may differ in their definitions of the degree of certainty that should be attached to the estimate. Unfortunately, many assessments do not fully specify their assumptions

and definitions, nor is it always clear what effects

these assumptions have on the resource estimates.

Consequently, it is not possible to “normalize” the

various estimates so that they are fully comparable. *

It is OTA’s opinion, however, that “normalization” of the various estimates would not eliminate

the major differences between them. OTA finds

no convincing basis for the common argument

that the area of the Lower 48 States is so intensively explored and its geology is so well known

● This does not imply, of course, that some normalization cannot be accomplished. For example, PGC has incorporated into its

resource estimate quantities of presently recoverable gas in tight reservoirs, whereas both RAND and USGS have tended to exclude this

gas from their resource estimates. Consequently, equalizing the conventional/unconventional boundaries of the assessments should

reduce the differences between PGC’s estimate and those of USGS

and RAND.
7

that there is a substantial consensus on the magnitude of the gas resource base.

Instead, there are several substantive resource

base issues that remain unresolved. Among the

more important of these are:

The Use of Past Discovery Trends

The extrapolation of past trends in the discovery of natural gas has generally led to pessimistic

estimates of the magnitude of the gas resource

base. For example, of the resource base assessments examined by OTA, three of the four that

used trend extrapolation techniques arrived at

estimates that were at least 400 TCF below the

USGS median estimate. Acceptance of discovery

trend extrapolation as a valid method of resource

base assessment, therefore, can yield conclusions

about the magnitude of the resource base that are

radically different from those that result from

using other assessment methods.

The validity of using past discovery trends to

estimate the magnitude of the resource base depends on whether the trends are affected more by

the nature of the resource base than by the general

economic and regulatory climate of the times. Resource “optimists” argue that the disappointing

trends in gas discovery of the past few decades

have resulted from controlled gas prices, high

levels of proved reserves, and limited markets that

until recently gave little incentive for high-risk or

high-cost drilling, They argue that extrapolation

of these trends is invalid because the economic

and regulatory conditions that created the trends

have changed. Resource “pessimists” argue that

the trends are driven mainly by a depleting resource base and are affected only minimally by

economic and regulatory conditions; therefore,

extrapolation is valid.

In addition to this basic issue, other questions

have arisen over the validity and interpretation

of resource estimates based on extrapolation of

past trends. For example, the accuracy of early

records of gas discovery and production is questionable; thus, trend analyses cannot accurately

incorporate the entire discovery and production

history. Also, the precise economic, technological, geographic, and geologic boundaries of these

estimates are difficult to define.

The Potential of Small Fields

Although fields that contain less than 60 billion

cubic feet (BCF) of gas have played a minor role

in gas production, some analysts believe that small

fields will have a major role in the future. The

difference between optimistic and pessimistic

estimates of the future role of small fields may

be 100 TCF or more. In OTA’s judgment, the arguments on both sides are based primarily on unproven statistical models of field size distributions

and on economic tradeoffs that are highly sensitive to gas prices. Only time and further exploration will settle this issue.

New Gas From Old Fields

There are sharp disagreements about the extent

to which the resources recoverable from older producing fields may respond to price increases. The

mechanisms to increase the “ultimately recoverable resources” of these fields might include lowering abandonment pressures, drilling at smaller

spacing to locate gas pockets that otherwise would

not be drained, and fracturing the reservoir rock

to allow recovery from low-permeability portions

of fields. Currently, estimates of the potential increase in recoverable resources range from a few

TCF to about 50 TCF.

The Potential of Frontier Areas,

Including Deep Gas

Although all resource analysts consider areas

such as the deep-water Gulf of Mexico, the deep

Anadarko Basin, and the Western Overthrust Belt

to have considerable gas potential, considerable

disagreement exists over the actual amount of recoverable resources in these areas. Recent indications of engineering problems and rapid pressure

declines from deep wells in the Anadarko, coupled

with price declines from previous very high levels,

raise doubts about whether much of this area’s

gas resource will be part of the (currently) economically recoverable resource. In the Overthrust

Belt, doubts about the magnitude of the resource

center on the significance of the failure of explorers to find a giant field over the past 3 to 4 years.

Also, areas such as the eastern Gulf of Mexico,

the Southeast Georgia Embayment, the Georges

Bank, and the Baltimore Canyon have been ex-
8

pensive failures thus far, and their eventual contribution to satisfying U.S. energy requirements

is unknown,

Estimates of the recoverable resource potential

in the frontier areas vary by up to 100 TCF or

more (the USGS and PGC differ by nearly 30 TCF

in their assessments of the eastern Gulf of Mexico, alone).

The Potential of Stratigraphic Traps

Stratigraphic traps are barriers to petroleum migration formed by gradual changes in the permeability y of sedimentary layers rather than by abrupt

structural shifts and deformation of the layers.

Because the structural traps are easier to locate,

they have been the primary targets for exploration. Some explorers predict that large resources

remain to be found in “mature” areas in subtle

stratigraphic traps. Although this issue is not settled, the optimistic argument is weakened by observations that numerous stratigraphic traps have

been found in the Permian Basin and elsewhere

and that the extensive drilling in areas that appear to have good prospects for stratigraphic traps

should have uncovered most of the larger traps,

which generally are extensive in area. Though it

may appear more likely than not that most of the

remaining undiscovered traps will be small in

volume, a possibility exists that larger fields may

have remained hidden because of the less effective exploration methods used in the past and

drilling that, while extensive, might have clustered

in the wrong places or been too shallow.

In addition to these five issues, a level of uncertainty is ever present in the process of estimating

the quantity of a resource that cannot be measured

directly prior to its actual production. The presence of economically recoverable concentrations

of natural gas requires an unbroken chain of

events or conditions, the presence or absence of

which generally cannot be measured directly.

First, adequate amounts of organic material and

suitable temperature and pressure conditions for

gas formation and preservation must be present.

Second, the gas must be free to migrate, and third,

an adequate reservoir must be available in the

path of migration to contain the gas. Finally, there

must be a mechanism to trap the gas, and the trap

must remain unbleached until the gas is discovered and produced. These sources of uncertainty

account for the various manifestations of risk in

natural gas development—the large number of dry

holes drilled during exploration, the often huge

differences in bids for leases, the multimillion dollar failures of many of the leased areas, and the

continuing disagreements over the size of the remaining resource.

OTA took into account these general issues, as

well as specific problems with individual assessments, in arriving at a plausible range for the

amount of remaining gas resources. In OTA’s

judgment, a reasonable range for the amount of

the remaining conventional natural gas in the U.S.

Lower 48 that is recoverable under present and

easily foreseeable technological and economic

conditions is 400 to 900 TCF as of December 1982.

This range is somewhat narrower than the range

displayed in table 2, because OTA considers the

low end of the range of resource estimates in the

table to be overly pessimistic. However, the general implication of OTA’s range is similar to the

implication of the range in the table: The uncertainty in estimating the remaining recoverable gas

resource is too high to determine whether or not

the resource base magnitude will constrain gas

production in this century. On the other hand,

even the more optimistic resource estimates imply

that conventional gas production must decline

sharply by the year 2020 or before unless technological advances and/or sharp increases in gas

prices add substantial quantities of gas to the

“economically recoverable” category.

Uncertainty 2: Interpretation and

Extrapolation of Discovery Trends

The key to projecting gas production potential

to the year 2000 is the successful prediction of

future discovery trends and of additions to proved

reserves. This focus on the discovery process is

necessary because gas that is already discovered,

that is, gas in proved reserves, will be of diminishing importance to production as we move into

the 1990’s. Assuming a constant R/P ratio of 8.0,

the current proved reserves of about 169 TCF in

the Lower 48 will provide only 2 TCF to total production by the year 2000. All other production
9

must come from gas added to proved reserves by

the discovery of new fields, the discovery of additional reservoirs in known fields (“new pool discoveries”), the expansion of the areas of known

reservoirs (“extensions”), and the reserve changes

due to new information or changed economics or

technology (“revisions’’ ).*

In addition to the effects of resource base uncertainty, interpretation and extrapolation of discovery trends are hampered by a variety of other

problems. These include:

Inadequate Discovery Indicators

The interpretation and extrapolation of trends

for projecting future reserve additions require the

availability of discovery “indicators,” such as finding rates for new field wildcats, that can be interpreted in a relatively unambiguous fashion.

OTA found that essentially all indicators available

from public data that describe the natural gas discovery process have ambiguous interpretations

because the data are highly aggregated and are

dependent on a wide variety of factors. For example, the “exploration” whose success is being

measured by a finding rate actually includes several kinds of exploratory drilling, from high-risk,

high-return drilling that searches for giant fields

in new geologic horizons, to low-risk, low-return

drilling that clusters around a new strike or redrills

already explored areas that have grown more attractive with price increases. Because the proportions of different varieties of exploratory drilling

may change substantially with changing market

conditions, interpreting trends in finding rates and

other indicators of exploration success is difficult.

This is especially true if the data are highly aggregated geographically.

Uncertainty About the Future Growth

of New Fields

At least three-quarters of past additions to

proved gas reserves have come from the discovery

process that follows the discovery of new fields.

This secondary discovery process seeks new reservoirs in the field and the expansion of known

boundaries of already discovered reservoirs. The

*This last category of reserve additions may be negative.

extent to which recently found fields and future

fields will grow in the same manner as fields found

in the past is critical to future reserve levels and

thus to future production. There has been speculation that the decline in finding giant fields—which

require many years and discovery wells to develop

fully—and the addition to the reserve base of increasing numbers of very small fields will lead to

significant declines in field growth. If the new

fields discovered in the past few years do not grow

at near-historic levels, then reserve additions due

to new pool discoveries and extensions will decline substantially from recent levels, even if new

field discoveries can stay at their present higher

rate. OTA believes that such a decline in field

growth is plausible, but verification requires additional analysis at the individual field level and

continued observation of field growth trends.

Difficulties in Interpreting the Recent Surge

in Reserve Additions

After the decade 1969-78, during which additions to gas reserves in the Lower 48 States averaged less than 10 TCF/yr,* reserve additions have

surged to over 20 TCF* * in 1981 and are expected

to be nearly as high in 1982. This surge has been

the centerpiece of arguments for future high production levels,

In OTA’s judgment, it is not clear whether or

not the recent high rates of additions to proved

gas reserves are sustainable, even if drilling rates

rebound to the levels achieved before the recent

slump. For example, 13.5 TCF of the total 1981

additions came from secondary discoveries, that

is, extensions and new pool discoveries. Normally, such a surge in secondary discoveries would

be preceded a few years earlier by an increase in

new field discoveries, because recently discovered

fields provide the most promising target areas for

secondary discoveries. However, the number of

new fields discovered in the 5 years before 1981

did not seem high enough to be the primary cause

of 1981’s high secondary discoveries. Alternative

or additional causes of the recent increases in sec-

—.

*As reported by the American Gas Association.

* *As reported by the Energy Information Administration The

American Gas Association, the major source of reserve data prior

to 1977, no longer publishes detailed information on reserve

additions.
10

ondary discoveries could include: an acceleration

in the normal pace of field growth (e. g., growth

that normally might occur over a 20-year period

instead is achieved in 5 years, yielding a shortterm increase in “per year” reserve additions followed by a dropoff in later years); the rapid development of a limited inventory of low-risk drilling prospects that had been identified in prior

years but ignored because of unfavorable economic conditions; and a substantially increased growth

potential for the current (and future) inventory

of discovered fields because of the expansion of

recoverable resources with higher prices and improved exploration and production technology.

The first two causes would imply that secondary

discoveries will decline sharply in the near future

as the limited inventory of prospects is used up;

the third cause implies that high levels of secondary discoveries might be sustainable. In fact,

it is likely that all three causes played a role in

the recent surge, but their relative share is

uncertain.

Similarly, it is not clear to what extent recent

higher reported rates of new field discoveries are

caused by any (or all) of the following factors:

an increased willingness of explorers to go after

riskier prospects; the exploitation of a limited inventory of low-risk prospects identified by past

exploration; an increase in the number of economically viable fields, caused by improved

technology and higher prices; and recent changes

in reserve reporting methodologies. *

OTA projected a plausible range of future additions to Lower 48 gas reserves by trying to account for uncertainties about the resource base

magnitude, the resource characteristics most likely

to affect the discovery process, and the actual

causes of past and recent discovery trends. OTA

concluded that, under the assumed demand/

price/technology conditions, multiyear average

levels of total reserve additions could range from

7 to 8 TCF/yr to 16 to 17 TCF/yr or higher by —.——

*The American Gas Association reported U.S. reserve additions

until 1979, The Energy Information Administration began reporting reserve additions in 1977 using a different data collection and

analysis procedure, and modified this procedure in 1979.

1986. Projected average values for individual

components of reserve additions are:

New field discoveries . . 1.5-3.5 TCF/yr

Extensions and new pool discoveries 6.0-11.0 TCF/yr

Revisions . . . . . . . . . O-+ 2.0 TCF/yr

Uncertainty 3: Production From Proved

Reserves-The RIP Ratio

The reserves-to-production (R/P) ratio reflects

the rate at which gas is being withdrawn from discovered reservoirs; consequently, it represents the

analytical link between projections of new discoveries and forecasts of gas production. There are

very large differences in R/P ratios from field to

field, depending on the age, geology, location, and

contract terms of the gas production. OTA projects that the aggregate average R/P ratio for the

Lower 48 may range from 7.0 to 9.5 by the year

2000, assuming that economic conditions are

generally favorable to production (in other words,

in contrast to today’s gas “bubble”). The R/P ratio

in 1981 was 9.0, the result of a long and relatively steady decline from a level of 30 in 1946.

Although the R/P ratio is sensitive to economic

factors, such as actual and expected gas prices and

interest rates, technical factors will also play an

important role in determining this ratio in the future. Gas in low-permeability reservoirs will play

an increasing role in reserves, tending to push up

R/P levels. The importance of offshore development will affect national R/P levels because offshore fields have typically been exploited very

quickly. As more and more gas is produced in

frontier areas with very high drilling costs, difficult tradeoffs will have to be made between the

desire for rapid production and the costs of drilling additional development wells. The rate of adding new reserves—which itself is highly uncertain—will determine the average age of the United

States’ producing fields, an important factor in

production rates. Uncertainty in these factors

makes it difficult to predict whether future average

R/P levels will increase or decrease from today’s

level.
11

Summary of Assumptions and

Conditions Underlying

OTA’s Projections

Table 3 summarizes the assumptions and conditions that lead to the low and high ends of

OTA’s projection for conventional gas production for the Lower 48 States in the year 2000.

Table 3.– Bases for OTA’s Projections of Natural Gas Production— Baseline Assumptions: Good Market

Conditions, Readily Foreseeable Technology

9 TCF/yr in 2000 ———.

1. Magnitude of remaining resources:

400 TCF 900 TCF

2. Character of remaining resources:

Remaining exploration playsa are only of moderate size;

few surprises. Some major potential remaining in

frontier areas but deep resource is disappointing. Small

fields are only a minor source of additional gas

because of economics and/or smaller numbers than a

straight-line extrapolation would predict. Resource in

strati graphic traps is disappointing; remaining growth

of old fields is moderate.

3. Causes of past trends in gas discovery:

Magnitude and character of the resource base were the

primary causes.

4. Meaning of recent surge in reserve additions:

A temporary response to higher prices, drilling a backlog

of easy but formerly marginal prospects—not

sustainable. Possibly also caused by a change in

reporting practices,

5. Projected rate of future annual reserve additions:

Total: Declines to 7,5 TCF by 1986:

New field discoveries: 1.5 TCF

Extensions and new pool discoveries: 6.0 TCF by 1986

Revisions: O

6. R/P Ratios:

9.5 by 2000, predicated on lower permeability reserve

additions, difficult production conditions.

19 TCF/yr in 2000

High potential for major new exploration plays. Deep

resource is both plentiful and economically accessible.

Small fields may play an important role, but many large

fields still remain. Resource remaining in mature areas,

much of it in subtle strati graphic traps, is substantial.

Remaining growth of old fields is high.

Artificially low prices and rigid regulation were as

important as the resource base.

An indication of a real turnabout in gas discovery; the

opening up of major new exploration horizons, readily

sustainable if exploratory drilling revives.

Maintained at 16.5 TCF or above for the next few

decades:

3.5 TCF

11.0 TCF

+ 2.0 TCF

7.0 by 2000, predicated on high demand coupled with

generally favorable physical conditions,

aplay — Ar, exploratory cam pal gn based on a cohes!ve 9e010CJlc idea

SOURCE Office of Technology Assessment, 1983

OTHER SOURCES OF LOWER 48 SUPPLY

Aside from domestic conventional gas produc- from Alaska, Canada, and Mexico; LNG imports

tion, gas consumers in the Lower 48 States may from a variety of gas-producing nations throughhave access to other sources of supply, including out the world; and synthetic natural gas from coal

production from so-called unconventional sources and biomass. The potential supply from uncon-

(tight sands, coal beds, gas in geopressurized ventional sources will be discussed in a future

aquifers, and Devonian shales); pipeline imports report of OTA’s U.S. Natural Gas Availability
12

study. OTA previously discussed synthetic natural gas in a report released in 1982.1

The United States currently imports about 0,9

TCF of gas per year, most of it from Canada.

Because each of the four sources of gas import

potential have substantial and accessible resources, imports could theoretically satisfy a major portion of U.S. gas requirements later in this

century and beyond. However, each of the import sources, like future domestic production, is

subject to considerable uncertainty. High trans-

‘Increased Automobile Fuel Efficiency and Synthetic Fuek: Alternatives for Reducing Oil Imports (Washington, D. C.: U.S. Congress, Office of Technology Assessment, OTA-E-185, September

1982)

portation costs are a particular problem for Alaskan gas and LNG, creating the need, at a minimum, to accept wellhead prices substantially

below equivalent oil prices. Similar problems exist

for Canadian and Mexican gas. Canadian and

Mexican exports to the United States must also

compete with the uncertain future requirements

of their own domestic gas users. Based on available studies, the expected import potential from

Canada, Alaska, and Mexico may range from 1.0

to 7.4 TCF in the year 2000, with Canada being

the most certain large contributor. LNG imports

are even less predictable. Finally, OTA projects

synthetic natural gas from coal to range from O

to 1.6 TCF/yr by the year 2000.
Chapter 2

Introduction
Chapter 2

Introduction

—.

The passage of the Fuel Use Act in 1977, which

sharply limited the allowed uses of natural gas in

the industrial and electric utility sectors, took

place in an atmosphere of extreme pessimism

about future gas supplies. An Electric Power Research Institute report published in that year

stated that:

Today almost every important supply indicator

points ominously to the fact that the Nation’s ability to meet present and future demands for natural

gas may be deteriorating rapidly and will continue

to do so unless aggressive and innovative measures

to rectify the situation are implemented immediately. 1

These pessimistic predictions were based partly on short-term problems—periodic curtailments

that caused considerable hardship to industry and

occasionally even to public facilities and to the

commercial sector. They were also based, however, on disturbing long-term trends, such as a

declining finding rate for new gasfields and, starting in the late 1960’s, the ominous and apparently unstoppable decline of proved reserves (fig. 2).

Since 1977, the national perception of future

natural gas availability has changed, for several

reasons, to one of relative optimism. First, shortterm supply is now in a state of surplus; a large

gas “bubble,” or surplus deliverability, estimated

to be as high as 2 trillion cubic feet (TCF) per

year,2 has been caused by a combination of energy

conservation, recession-induced reductions in industrial activity, and industrial fuel-switching

from gas to oil because of declining oil prices and

increased gas prices. At the same time, reserve additions have apparently rebounded from the depressed levels of the 1970’s to over 20 TCF in

1981. 3 Also, the U.S. Geological Survey (USGS)

‘ [<, ~ 1 ] I anc>, et al , A Comparatj \re .$(att~-ot -the-.4rt .4ssessment

()} Gas Supp/-t~ ,\ Zode)JrIg, EPR1 report EA-201, February 1977

1 oil Finds of 108 Blll]on bbl Seen in ‘80’s, ” oil & Gas )ourndi,

Sept. 27, 1982, p. 140.

‘Executi\’e summary and selected summary tables from “U.S .

Crude 011, Natural Gas, and Natural Gas Liquids Reserves, ” IQ!ll

Annual Report, prepubl]catlt}n draft, Aug 30, 1Q82, Energ} Int[~rmat Ion Administrate Ion ( EIA ), U.S. Department of Ener~y’. Because

the EIA data series appears to differ somewhat from the earl]er

American Gas Association data (EIA began in 1977), the interpretation of the recent higher reserve addttions ]s somewhat controvers]a]

and the Potential Gas Committee (PGC) have

each recently confirmed their earlier estimates of

the remaining recoverable resources in the Lower

48 States:4 the latest USGS estimate implies that

about 770 TCF of gas remain as of January 1983,

while the PGC estimate implies an even more optimistic 910 TCF.5 These estimates, which do not

include gas that could be recovered with completely new technologies and/or substantially higher

prices, both exceed the amount of gas that the

United States has already produced during the entire history of its gas use.

As a result of these optimistic signs, much of

the natural gas industry believes that gas demand

has replaced supply as a critical issue, and some

industry organizations are even claiming that supply from all sources could be sufficient to allow

a substantial expansion of U.S. gas consumption

in the next few decades.6 Also, Congress is reexamining the legislation governing the U.S. natural

gas market.

In reaction to this changing outlook for U.S.

natural gas supply, the House Committee on Energy and Commerce and its Subcommittee on Fossil and Synthetic Fuels, supported by the Subcommittee on Energy Research and Development of

the Senate Committee on Energy and Natural Resources, asked OTA to conduct a study of domestic (Lower 48 States) natural gas availability

over the next few decades. The overall study will

examine both conventional and unconventional

sources of natural gas (the unconventional sources

include coal-bed methane, tight sands, Devonian

shale, and geopressurized aquifers), review current estimates of resource bases and production

‘B, M. Miller, et al., Geological Estimates ot 1 lndlsco~rered R(’-

coverable 011 dnd Gas Resources in the L ‘njted States [lSGS C-lrcular 725, 1975; and Potential Gas C“omrn]ttee l’(~tent]d] Suppi}

oi Natura] Gas In the ~~n)ted States id+ (>t Lkcember .? 1 1 ~$i~ J

(Golden, Colo.: Potential Gas Agenc>’, Coloracio School of hl]ne~,

May 1981 )

‘C,. 1., Dolton, et al,, Estlmdtes (~t L~ndlsc(l\’erd Reco~t’rah/e L’(Jntrent]ona] i<esources ot 0]/ dnd ~ds /n the ~~n]ted .$t~tes, (k>(l](lgicd]

Sur\rey C]rcu]ar 860, 11481 and Potent]al ~d~ Agenc-}r ,~”t’tf’+

l{e]ease – Fehruar~ 1~, 14$.3.

“For example, ;ee The Gas Energ?’ Suppl?V Outl(loL lQ&D200L~

American Gas Assoclatlon, lanuary 1Q82

15
16

Figure 2.— Natural Gas Production: Additions to Reserves, and Total Reserves of the Lower 48 States

U.S. natural gas reserves

(As of Dec. 31)

AGA

I

1947 1950

SOURCE American Gas Association,

potentials, and examine

will affect the future

sources.

1955 1960 1965 1970 1975 1980

The Gas Energy S’Upp/V OIJI/ook 1980-2000 January 1982

key technical issues that conventional natural gas. * It focuses first on an

development of those assessment of the conventional gas resource base,

and second, on an evaluation of production poThis technical memorandum presents OTA’s *This material will form one section of OTA’s final report on U.S.

Natural Gas Availability. The memorandum is being released early

evaluation of the prospects for future supplies of in view of the current congressional debate on natural gas.
17

tential for the mid to long term—lo to 20 years

and beyond. The size of the resource will obviously play a critical role in long-term supply and an

important but less widely understood role in the

midterm supply.

The memorandum is oriented primarily towards examining the role played by technical

uncertainties in estimating future gas availability.

Specifically, the memorandum examines the recoverable resource base and future gas production potential under the following conditions:

Demand for gas is high, implying that explorers and producers do not curtail their activities because of fear that their gas will not be

marketable. The current gas “bubble” is assumed to end shortly and not to reoccur, and

drilling rates are assumed to rebound to levels

achieved before the recent slump. Consequently, “pessimistic” scenarios examined in

this study reflect only pessimism about technical prospects for gas discovery and production and do not reflect the possibility that low

gas demand may drive down discovery rates

and production.

Average wellhead prices do not change grossly from today’s levels, implying primarily

that gas sources that today are unequivocally

outside of the “economically recoverable”

range are excluded from OTA’s resource estimates and projections of future production

potential.

New technologies that are not readily foreseeable extensions of existing technologies are

not considered in the analyses.

This orientation clearly requires that the estimates of resources and production potential presented in the report be interpreted carefully. For

example, OTA’s assumptions about price and

technology are likely to yield conservative

estimates of gas resources and production potential. Historically, the recoverable resource bases

for essentially all nonrenewable resources have

expanded as prices rose and new recovery technologies were developed (see ch. 4, “Resource Base

Concepts”). This has certainly been the case for

the gas resource base in the past, and will undoubtedly also be the case in the future. However,

the extent and timing of future expansion of gas

resources is extremely difficult to predict.

In addition, as noted, a continuation of low gas

demand would tend to change future production

potential relative to that projected only on the

basis of the technical potential. A lack of markets

will discourage exploration, new pipeline development, and other determinants of future production potential, although simultaneously it will

slow the drawing down of existing proved reserves, the “ready inventory” for future production.

The remainder of the memorandum is organized in the following fashion:

●

●

●

●

Chapter 3: Natural Gas Basics presents a brief

review of basic natural gas terminology and

concepts.

Chapter 4: The Natural Gas Resource Base

reviews resource assessment methodologies,

describes and critiques several specific gas resource assessments, evaluates a number of

critical resource issues, and presents OTA’s

conclusions about the magnitude of the remaining resource base.

Chapter 5: Gas Production Potential describes four approaches used by OTA to

evaluate the gas production potential to the

year 2000, and presents OTA’s conclusions

about this potential.

Chapter 6: Other Gas Sources—Summary

briefly reviews the prospects for additional

sources of supply to the Lower 48 States—liquefied gas imports and pipeline imports from

Alaska, Canada, and Mexico.
Chapter 3

Natural Gas Basics
Chapter 3

Natural Gas Basics

This chapter briefly describes basic theories and

terminology used within the report—i.e., it briefly

describes what natural gas is, how it is formed,

how it is found and subsequently produced, and

how discoveries are reported. Words in boldface

WHAT IS NATURAL GAS?

As its name implies, natural gas is a naturally

occurring mixture of hydrocarbon and nonhydrocarbon gases found in subsurface reservoirs within

the Earth’s crust. Methane (CH4

), a light hydrocarbon, is the primary constituent of natural gas

and of principal interest to the energy industry.

HOW DOES NATURAL GAS FORM?

There is no universally accepted explanation of

how natural gas formed. Most hydrocarbon deposits of significant size occur in sedimentary

basins, however, and are thought to have originated from the decay and alteration of organic

matter. Hundreds of millions of years ago, seas

that covered a large portion of the land exposed

today were inhabited by tiny plants and animals

that, upon dying, sank to the bottom and were

buried under layers of sediment. In areas of rapid

sedimentation, organic decay was accompanied

by high pressures and temperatures which, over

millions of years, effectively “cooked” the organic

material into petroleum (oil and natural gas).

Hydrocarbons could also have been formed by

other processes: by the anaerobic (without oxygen) digestion of organic materials by bacteria,

and inorganically by the reduction of inorganic

carbon and its oxides at high pressures and temperatures deep within the Earth. The quantity of

recoverable gas thought to have originated by

these processes is generally felt to be small, but

WHERE IS NATURAL GAS FOUND?

Petroleum accumulations occur as reservoirs or

pools—not in caverns or large holes in a rock mass

are defined in the glossary at the end of the technical memorandum. Readers familiar with basic

terminology and concepts of natural gas supply

may wish to skip this section.

Associated heavier hydrocarbons such as ethane,

propane, and butane and impurities such as water,

hydrogen sulfide, and nitrogen occur with the

methane. If the concentrations of these other constituents render the gas unmarketable, they must

be removed prior to use.

some controversy still exists, especially concerning the inorganic processes.

Temperature and pressure conditions have a

critical role in determining the physical state of

the hydrocarbons that result. Natural gas may be

found at all depths, but it originated mostly in

rocks subjected to particularly high temperatures

and pressures over long periods of time. It generally is the only hydrocarbon present at depths beyond 16,000 ft. Liquid hydrocarbons occur at

shallower depths, from about 2,500 to 16,000 ft,

where lower temperatures are characteristic.1

Most crude oil is found between 6,500 and 9,000

ft, with light hydrocarbon liquids occurring at

depths greater than 9,500 ft.2

‘H. Douglas Klemme, Geothermal Gradients, Heat Flow, and Hydrocarbon Recovery. Petroleum and Global Tectonics (Princeton

and Landon: Princeton University Press, 1975), p. 260. Cited in

Jensen Associates, Inc., Understanding Natura) Gas Supply in the

U. S., contractor report to OTA, April 1983.

‘B. P. Tissot and D. H. Welte, Petroleum Formation and Occurrence (New York: Springer-Verlag, 1978), p. 202. Cited in Jensen

Associates, Inc., op. cit.

but in the

ticles that

minute pore spaces between the parcompose the rock. The greater the

21
22

amount of pore space in the rock (porosity), the Sedimentary rocks compose about 75 percent of

larger the quantity of gas or oil that may be con- the exposed rocks at the surface, but only 5 pertained within it. Pools often occur together in a cent of the Earth’s crust (outer 10 miles) . The

field, and multiple fields in similar geologic en- known oil- and gas-bearing areas in the United

vironments constitute a province. States are identified in figure 3.

Gas occurs separate from (nonassociated gas)

and together with oil. When together, it occurs

in solution with the oil (dissolved gas) or as free

gas (associated gas), in a gas cap when no more

gas can be held in solution under the pressure and

temperature conditions of the reservoir.

The search for hydrocarbon accumulations is

narrowed by the requirement for the presence of

organic material in the sediment at the time of

burial. Sedimentary basins are the areas most likely to have contained the organic-rich rocks—

source rocks—required for petroleum formation.

Although source rocks are required for petroleum formation, commercial petroleum accumulations are not usually found in the source rock.

Source rocks are generally too impermeable,

meaning the texture of the source rock does not

allow petroleum to flow easily through the pores

to a producing well. Typically, after the petroleum

was formed, the gases and fluids (oil and formation water) migrated from the source bed to a

more permeable rock, called the “reservoir rock”

(this process is called “primary migration”). The

fluids moved in the path of least resistance ( or

Figure 3.— Known Oil- and Gas-Bearing Areas in the Lower 48 States

Q - Oil and gas fields

— Regional boundaries

o 200 400 Miles

t

o 200 400 600 Kilometers

SOURCE Est/rnafes of Ur?d/scovered Recoverable Convention/ Resources of Oil and Gas in the United States, U S Geological Survey Circular 880, 1981
highest permeability) and continued migrating

within the reservoir rock (secondary migration)

until an impermeable barrier was encountered,

which prohibited further migration into adjacent

or overlying rock units or formations. The petroleum then migrated further along the barrier to

a place of accumulation, called a trap—usually

located at the highest point where the reservoir

rock contacts the more impermeable, barrier rock.

The four requirements for a hydrocarbon accumulation—a source rock, reservoir rock, impermeable barrier rock, and trap—are illustrated in

figure 4.

There are three basic types of petroleum traps:

structural, stratigraphic, and combination (see fig.

5). Structural traps are formed by earth

movements that deform or rupture rock strata,

thereby creating favorable locations for hydrocarbons to accumulate. Such structural features as

faults and anticlines create enclosures that serve

as loci for migrating petroleum. Stratigraphic

traps are created by permeability and porosity

changes characteristic of the alternating rock

layers that result from the sedimentation process.

In stratigraphic traps, pinched-out beds, sandbars,

or reefs serve as reservoirs for migrating petroFigure 4.— Four Requirements for

Petroleum Accumulation

Water layer,

Impermeable barrier:

shale

-Reservoir rock:

h sandstone

—Source rock:

I organic-rich shale

leum. Combination traps result from both structural and stratigraphic conditions. An example of

a combination trap is one that results from a salt

dome intrusion during deposition that alters the

thickness of the strata deposited.

Figure 5.—Trapping Mechanisms

Structural trap—fault

Gas

accumulation

Stratigraphic trap—pinched-out bed

Gas

accumulation

Combination trap—salt intrusion

SOURCE Office of Technology Assessment SOURCE Off Ice of Technology Assessment

HOW IS NATURAL GAS DISCOVERED?

Gas

accumulation

Before an understanding of subsurface geology water-well drilling, and luck. Today there are a

was acquired or rules of petroleum occurrence variety of concepts, exploration methods, and inwere established, petroleum discoveries were struments available to help geologists locate subbased on surface seeps, knowledge gained from surface hydrocarbon accumulations.
24

The type of exploration techniques used varies

between sites and depends on how much is known

about the area being explored. In areas where little

is known about the subsurface, reconnaissance

techniques—which provide limited information

over a large area—are used to identify favorable

areas that warrant more detailed investigation.

Satellite and high-altitude imagery sometimes reveals large geologic features or trends that are surface expressions of subsurface geologic structure.

Magnetic and gravity surveys detect changes in

the magnetic or density properties of the Earth’s

crust and are also used to infer subsurface

structure.

Once a promising area has been identified,

more detailed, higher resolution exploratory

techniques are used to locate individual prospects

for the drill and to project conceptually related

groups of prospects, or plays. The seismic reflection method, which measures and interprets the

reflections of sound waves off of geologic discontinuities, is particularly effective for providing

detailed subsurface information. Drilling is the

final stage of the exploratory effort and the only

sure way to determine if hydrocarbon-filled reservoirs exist in the subsurface.

In some basins, drilling may be performed so

cheaply that predrilling exploration expenditures

for seismic surveys and other analyses are not

justified. These shallow areas are becoming increasingly scarce, and the role of predrilling exploration analysis is increasing in importance, particularly in frontier areas. If these high-cost areas

are to be drilled, operators must be relatively sure

that the drilling expense is justified.

The degree of risk involved in drilling depends

on how much is known about the subsurface at

the drill site, As illustrated in figure 6, a classification scheme has been established to categorize the

exploratory wells based on their relationship to

Figure 6.—AAPG and API Classification of Wells

SOURCE Lahee class [f[cat Ion of wel Is as applled by the Comm Ittee on Statlstlcs of Drl II lnq of the Arnerlcan Assoc[at[on of Petroleum Geoloalsts and the Amer[can

Petroleum Institute Developed by Frederic H Lahee In 1944
2 5

known petroleum discoveries. There are three

basic kinds of exploratory well. A new field wildcat is a well drilled in search of a new field, that

is, in a geologic structural feature or environment

that has never been proven productive. New field

wildcats generally have the greatest associated risk

because they are drilled based on the least preexisting knowledge. New pool wildcats-in search

of pools above (shallower), below (deeper), or

outside the areal limits of already known pools—

are generally less risky because the field in which

they are drilled has been proven productive. Outpost and extension tests are drilled to determine

the bounds of known pools. Development wells

are the least risky because their primary function

is to extract the petroleum from the already

proven pools; they are not exploratory wells.

When an exploratory well encounters petroleum, the quantity of proved reserves is estimated,

and the commercial viability of the reservoir

evaluated. Proved reserves are determined by analyzing actual production data or the results of conclusive formation tests. The proved area is the

area that has been delineated by drilling and the

adjoining area not yet drilled but judged as economically producible based upon available geologic and engineering data. Because of its conservative nature, the initial estimate of proved reserves

based on a field’s discovery well is generally significantly smaller than the quantity of gas ultimately recovered from the field. Wells drilled in

subsequent years may increase the proved area

of the reservoir or lead to the discovery of additional reservoirs within the field.

Each year, the sum of reserve additions attributed to the three types of exploratory wells are

reported by the Energy Information Administration (EIA) as “new field discoveries” (these are the

initial, first-year estimates of a new field’s proved

reserves), “extensions, “ and “new reservoir (pool)

discoveries in old fields. ” (In this memorandum,

this last category of reserve additions is called new

pool discoveries, for brevity. ) Another reporting

category, “revisions,” includes those reserves that

are added or subtracted because of new information about old fields, for example, an indication

that the fields will be drawn down to lower pressures because of a gas price increase, pressure

histories during production that deviate from the

expected values, or the use of measures to increase

recovery. Another category, “Net of Corrections

and Adjustments, ” reports reserve changes from

corrections of previous arithmetic or clerical

errors, adjustments to previously reported gas

production volumes, late reporting of reserve additions, and so forth. * Table 4 shows the changes

in U.S. gas reserves from 1977 to 1981 as reported

in the EIA yearly report, U.S. Crude Oil, Natural

Gas and Natural Gas Liquids Reserves—Annual

Report.

*EIA began its data series in 1Q77 The American Ga\ Aw)ciat]on and American Petroleum Institute als~l pub] ished reser~re +ta -

tistics in basically the same format (without a “corrections and acijustments” category) from 1966 to l~7Q, and in a wlmewrhdt ditferent

format from 1947 to 1Q65

Table 4.— Estimated Total U.S. Proved Reserves of Natural Gas–1977-81

Net of New reservoir Proved Net

corrections Revision Revision Extensions to discoveries New field Total reservesb

change from

& adjustments Increases decreases old reservoirs in old fields discoveries discoveriesb Production 12/31 prior year

Year (1) (2) (3) (4) (5) (6) (7) (8) (9) (lo)

Natural gasc

— —

1976 . — — — — — — — — 213,278’ —

1977 . –2od 13,691 15,296 8,129 3,301 3,173 14,603 18,843 207,413 – 5,865

1978 . 2,429 14,969 15,994 9,582 4,579 3,860 18,021 18,805 208,033 620

1979 ., –2,264 16,410 16,629 8,950 2,566 3,188 14,704 19,257 200,997 – 7,036

1980 ., 1,201 16,972 15,923 9,357 2,577 2,539 14,473 18,699 199,021 – 1,976

1981 1,627 16,412 13,813 10,491 2,998 3,731 17,220 18,737 201,730 2,709

NOTE “Old” means discovered In a prior year “New” means discovered during the report year

aColumn 4 + column 5 + Column 6

bPrlor year Column 9 + Column 1 + Column 2 Column 3 + Column 7 Column 8

~Btlllon cubic feet, 1473 psla, 60 F

Cons!sts only of reported corrections

‘Based on followlng year data ‘n’y

SOURCE Energy Information Admlnlstratlon, U S Crude 0//, Natura/ Gas, and Natura/ Gas LIquIds Reserves— 1981 Annua/ ffepor?, DO EEIA.0216 (811, August 1982
2 6

HOW IS NATURAL GAS PRODUCED?

The way in which gas is produced depends on

the properties of the reservoir rock and whether

the gas occurs by itself or in association with oil.

As illustrated in figure 7, hydrocarbons in the reservoir rock migrate to the producing well because

of the pressure differential between the reservoir

and the well. How readily this migration occurs

is a function of the pressure of the reservoir and

the permeability of the reservoir rock.

Production will continue as long as there is adequate pressure in the reservoir to propel the

hydrocarbons toward the producing well. If gas

is the only propellant, the reservoir pressure

decreases as the gas is extracted and is eventually no longer sufficient to force the hydrocarbons

toward the well. In a water-drive reservoir, water

displaces the hydrocarbons from the pores of the

reservoir rock, maintaining reservoir pressure during production and improving the recoverability

of the hydrocarbons. In most reservoirs, gas recovery is high, generally greater than oil recovery. A “typical” recovery value of 80 percent is

often cited, but the basis for this value is not firm,

and recovery is certainly less in many reservoirs

under current conditions. When gas occurs in association with oil, it can be reinfected into the

reservoir to maintain pressure for maximum oil

recovery. Gas is also reinfected when there are

no pipeline facilities available to transport it to

market.

Once the raw gas is produced from the well,

it is gathered with production from other nearby

wells and processed to remove natural gas liquids

and impurities that could cause problems in the

pipeline. The gas is then sent by pipeline to local

gas utilities who sell it to the end-user. In some

instances, such as those involving large industrial

users, the pipeline will sell directly to the end-user

and bypass the local gas utilitv.

Figure 7.— Production Mechanics

Gas drive mechanism

A

c k

Gas and water drive mechanism

Barrier rock

-Reservoir rock

SOURCE Office of Technology Assessment

.fA “ J
Chapter 4

The Natural Gas Resource Base
Chapter 4

The Natural Gas Resource Base

About the only thing that any estimator can say

with certainty about his (resource) estimate is that

it is wrong.

Richard P. Sheldon

U.S. Geological Survey

The focus of this technical memorandum is on

U.S. natural gas availability for the next few

decades—and, specifically, on the gas supply that

can be provided by production in the Lower 48

States. Some analysts have claimed that the

resource base is not an important constraint to

gas supply during this period because the U.S.

Geological Survey (USGS) estimated resource represents over 40 years of supply at current production levels, which does not count huge resources

of unconventional gas (e. g., tight sands gas and

methane from geopressurized aquifers) and potential imports of liquefied natural gas (LNG) or

pipeline gas from Mexico, Alaska, and Canada.

In OTA’s opinion, the claim that the resource

base is unimportant to “midterm” (1985-2000)

supply is arguable. Most theories of resource

depletion imply that the “easiest” part of the

resource base—for gas, this would be the largest,

most accessible fields—tends to be discovered and

exploited in the early stages of development and

that declines in discovery rates and production

will occur well before the “last” resources are

discovered and extracted. Consequently, the resource estimates of USGS and the even higher estimates of the Potential Gas Committee (PGC) do

not necessarily imply a capability to continue gas

production at current levels for decades to come.

These estimates indicate that we have already produced about 40 percent of the Lower 48 gas resource obtainable within the current price technology regime. The remaining 60 percent will be

more difficult and more expensive to find and

RESOURCE BASE CONCEPTS

An important source of difficulty in interpreting

and comparing resource base estimates is the failure of the estimator to state and explain precisely the boundaries of his estimate—his definition

eventually extract than the already produced portion. The very pessimistic recent estimates of M.

King Hubbert1 imply that the United States may

have produced 70 percent of all the gas it shall

ever produce in the Lower 48. The Hubbert

estimate thus implies that the United States may

encounter an almost immediate dropoff in discoveries and reserve additions, followed shortly

thereafter by sharp reductions in gas production.

Even the more optimistic USGS and PGC estimates do not deny the possibility of significant

reductions in supply within this century. *

Therefore, an understanding of resource base estimates is important to midterm as well as longterm planning regarding natural gas policy.

In this section, OTA has not attempted to create

a new, independent assessment of U.S. natural gas

resources nor to settle on any existing assessment

as the “best. ” Instead we attempted to accomplish

the following four goals:

1.

2 .

3 .

4 .

To give the reader an idea of how natural

gas resource assessments are made.

To describe the problems associated with

general resource assessment methods and

with particular individual assessments.

To define the continuing areas of controversy about the size and characteristics of the

remaining gas resource base.

To convey OTA’s evaluation of these controversies- and of the credibility of some of

the most widely used assessments.

‘M. K. Hubbert, “Techniques ot Prediction as Appl]ed to the Production of 01] and Gas, ” in Oil and Cas SUppl}r hlode]ing, S. 1.

Gass (cd.), National Bureau of Standards Special I’ubllcation 631,

May 1982.

*For a discussion about the production implications of the Hubbert, USGS, and PGC assessments, see ch. 5, Approach Number

4 —Graphing the Complete Production Cycle. ”

of the resource base—and the failure of the client

to comprehend what a resource base is, or what

a particular resource base is.

2 9
30

The well-known McKelvey Box (named after

its originator, the former director of USGS) is a

useful tool in explaining basic resource base concepts (see fig. 8). The McKelvey Box classifies resources according to their economic feasibility of

recovery and the geologic certainty of their occurrence. The outer boundaries of the box define the

total amount of the material—in this case, natural gas—remaining within the crust of the Earth.

The top third of the box (the proportions are NOT

meant to be indicative of magnitude) represents

gas that is economically producible at current

prices using existing technology. The middle third

represents gas that is expected at some future time

to be producible but is currently not economically

producible, either because of the absence of recovery technology or because of economic conditions. The lower third represents gas accumulations under such difficult physical conditions that

they are likely never to be economically produciFigure 8.—The McKelvey Box

SOURCE Adapted from V E McKelvey, “Mineral Resource Estimates and Public

Policy, ” Arnerlcan Sc/entist, VOI 60, No 1, 1972, PP 32.40

ble. Obviously, our inability to accurately project future economic conditions and future technology developments prevents us from knowing

where to place the line between subeconomic resources and “nonresources.”

The left half of the box represents identified resources—’’resources whose location and quantity

are known or are estimated from specific geologic

evidence.”2 The economically recoverable portion

of the identified resources is called “reserves” in

the box, but this is not a universally accepted definition. (However, it is generally accepted that use

of the term “reserves” to designate the total recoverable resource is a poor usage of the term.

Reserves should always refer to gas that is in some

sense within the ready inventory available for production.) Proved or measured reserves are the

most certain portion of the recoverable identified

resource, gas which has been estimated from geologic evidence supported directly by engineering measurements. An actual physical discovery

by drilling is necessary for inclusion within this

category. The remainder of the recoverable identified resource is somewhat poorly defined because

of disagreement about what “identified” or “discovered” means. To USGS, for example, untapped reservoirs in discovered fields belong to

the “discovered” resource,3 whereas to the PGC,

they are “undiscovered.” 4

A critical feature of the components of the resource base is that they are not static, As the production and discovery process continues, gas

flows out of reserves and is processed, distributed,

and consumed, and other gas moves from “undiscovered” to “identified” as geologic knowledge increases. Additionally, improved technology and

economics cause gas to move from the subeconomic to the economic portion of the resource

base. For example, improvements in offshore drilling technology may allow drilling in deeper waters

and more hostile conditions, opening up new territories to development. Higher gas prices may

allow the development of smaller reservoirs that

‘G, L. Dolton, et al,, Estimates of Undiscovered Recoverable Conventional Resources of Oil and Cas in the United States, U ,S.

Geological Survey Circular 860, 1981.

‘Ibid.

4Potential Gas Agency, Potential Supply of Natural Gas in the

United States (as of December 31, 1980), May 1981,
31

were previously uneconomic, or allow known

economic reservoirs to be developed more intensively and drained to lower abandonment pressures.

In the history of development of nonrenewable

resources, the process of advancing technology

and knowledge and of changing economic conditions has not always been smooth. Consequently, assessments of nonrenewable resources have

tended to run in cycles. The discovery of resources

in areas or under geologic conditions where they

had not been expected or the development of new

extraction and processing technologies can generate higher estimates of the remaining resource

which may then taper off as that portion of the

resource base is systematically depleted. For most

resources, analysts assessing the remaining recoverable materials at the end of each cycle have been

convinced that the most recent cycle upturn was

the last and that resource depletion was imminent.

They have been proven wrong time and again. *

Recognizing this, many resource estimators

have confined their assessments to only a portion

of the McKelvey Box, usually the top third and

a small portion of the middle, subeconomic third.

In doing so, they explicitly accept the possibility

that changing economic and technological conditions could make their recoverable resource estimates obsolete. Unfortunately, the stated boundaries of the assessments are seldom very precise,

and it is not always clear that the estimators have

consistently followed their own specified rules for

’011 has uncterg<lne such cycles of apparent depletion followed

by large new’ ctlsc{)verles and drastic upward re~fisions in resource

e~t i m ates TW{J other we] 1 -k n own ma terlal~ that have underg[~ne

si mild r c ycle~ are ura n ] urn and ] ron ore

including and excluding portions of the total physical resource. Furthermore, besides the ambiguity of the boundary definitions, some resource assessments have chosen different boundaries than

the “top third and a small portion” indicated

above. Hubbert, for example, claims to capture

the ultimately recoverable resource-the top twothirds of the box—in his estimate, although he restricts the estimate to “conventional” gas and excludes such sources as methane in coal seams.5

The differences in economic technological

boundary conditions between alternative gas resource assessments is one of several reasons why

comparisons of assessments must be handled with

caution. Table 5 lists some of the common problems encountered in comparing estimates.

‘Hubbert, op. cit.

Table 5.—Why It Is Difficult to Compare

Resource Estimates

●

●

●

●

●

●

●

Geographical areas (or geological limitations, such as

depth) included in the estimate may be different—

especially offshore boundaries.

Assumptions about economic conditions and the state

of technology may be different. Also, these

assumptions are often poorly defined and appear in

some cases to have been applied inconsistently.

Some estimates may have included some

unconventional resources.

Areas that are currently legally inaccessible (e. g.,

wilderness areas) may or may not be included.

Definitions of “undiscovered” may differ; they may or

may not include undiscovered reservoirs in known

fields,

Degree of optimism about estimates (e.g., assigned

probabilities) may differ.

Estimates may or may not correct for liquid content

and for impurities.

SOURCE Off Ice of Technology Assessment 1983

APPROACHES TO GAS RESOURCE ESTIMATION*

Although the extensive literature on oil and gas

resource assessment identifies a wide variety of

estimation techniques, all of the techniques fall

—

● This section is based largely on [J S. Geolt>gical Survej Circular

860, “Estimates t)t Undiscovered Recoverable Conventi{~nal

Resources of Oil and Gas In the United States, ‘ C. 1.. IX}lton, et

al. , 1Q81, and D. A \Yh ite and 1 i. NI. Gehman, hlethods (>f

Estimat]n~ 011 and Ga\ Resources, ” AAI’G Bullet In, J’01. 6.3, NO .

12, December 197Q.

into two basic categories. Geologic approaches

rely on information and assumptions about the

physical nature of the resource: volumes of

sedimentary rock, numbers of geologic structures,

presence of “source” rocks, time profiles of subsurface pressure and temperature, and the like.

Historical approaches rely on the evaluation and

extrapolation of past trends in gas production and

discovery in the assumption that the size and
32

character of the resource base, rather than transitory economic conditions and technological

developments, are the most important factors controlling the discovery and production cycle. If this

assumption is correct, the evidence provided by

the manner in which the development cycle has

unfolded can be used to ascertain the nature of

the resource base.

Geologic Approaches

Geologic approaches run the gamut from

simple—for example, the collection of expert geologic opinion on the size of the overall resource

base—to complex procedures involving probabilistic estimates of the geochemical and geologic factors affecting the formation, migration, and accumulation of gas. The methods listed may be

used in combination.

In geologic analogy, untested areas are examined for comparison with known producing areas.

Comparisons range from simple evaluations of

hydrocarbon source beds or reservoir beds to

evaluation of dozens of factors. Because the use

of analogy is basic to all geologic and geochemical

understanding, this method in some sense is the

basis for all the other methods.

In the Delphi approach, in its simplest form,

each member of a group of geologists evaluates

the geologic evidence available for an area and

estimates the area’s potential resources. These individual estimates are then reviewed by the group,

possibly modified, and then averaged into a single

estimate. This approach may also be used as a

tool to assist other resource estimation approaches, as when experts are asked to jointly

evaluate the hydrocarbon yield of an untested

area in barrels per acre-foot as an input to a

resource assessment using a volumetric yield approach (see below).

Areal-yield and volumetric-yield approaches involve the estimation of the amounts of hydrocarbon per unit area or volume of potentially productive rock in a region and the multiplication

of these estimated yields by the appropriate area

or volume. The yields are generally calculated by

geologic analogy.

Geochemical material balances, elaborations of

the volumetric-yield approach, attempt to account

explicitly for the process of gas generation, migration, and entrapment. Rather than estimating a

simple volumetric yield, for example, this approach might estimate the amount of organic matter in source beds, the fraction converted into

hydrocarbons, the fraction actually able to move

from the source beds into reservoirs, and finally

the fraction of this amount actually trapped and

concentrated and thus available for extraction.

Field number and size approaches attempt to

count or estimate the number of prospective fields

in the area being evaluated and to estimate their

success rate and size distribution in order to yield

an overall area resource estimate. Estimation

methods include actual counting of structural

traps by using seismic surveys, extrapolation from

historic field size distributions (a historic approach, as discussed below), and calculation of

success ratios by geologic analogy. Other levels

of aggregation besides the field are also used; play

analyses, for example, focus on groups of fields

or prospects with several common geologic characteristics.

Some generalizations can be made about these

approaches. The simple methods that use few factors to calculate gas resources all share the risk

that key geologic factors, such as the temperature

history of the rocks, may be left out. The converse is that the more complex methods, such as

geochemical material balances, may assume a

higher level of geologic knowledge than currently exists. Although the breakdown of the resource

assessment into several individual components appears precise, the uncertainty associated with each

component is quite large and the potential for error in the resource estimate is high. For example,

incorporating factors such as pressure and temperature histories into resource estimation allows the

estimator to account directly for the probability

that petroleum actually was formed and survived.

However, because the geology of most areas has

changed significantly over time, it is difficult to

trace these changes to reconstruct the temperature

and pressures that existed during the periods of

hydrocarbon formation, migration, and accumulation.
33

The simpler methods are most useful in the

early stages of development of a basin when few

data are available and the need for expert judgment and intuition is at a peak. The obvious disadvantage, however, is that documentation of the

estimation process is minimal or, in the case of

the simplest Delphi approach, lacking entirely.

The credibility of these estimates, then, rests mainly on the reputation of the experts involved in the

assessment or of the sponsoring organization.

Finally, the geographically disaggregated approaches, such as play analysis, are most useful

when considerable exploration data are available.

Many analysts think highly of these approaches,

perhaps because the approaches deal in units that

most accurately reflect the discovery process and

thus allow participants in the resource assessment

to draw most readily on their experience for geological analogs.

Historical Approaches

A variety of historical approaches to resource

estimation rely on extrapolation of historical

trends in production, reserve additions, and

discovery rates as functions of time, number of

wells drilled, or cumulative feet of exploratory

drilling. Some of these approaches lack explicit

assumptions about geology and simply search for

curves that achieve the best fit to the data. Others

(e. g., some of Hubbert’s approaches) first assume

general models of the production and discovery

process and then adjust the models to fit the data.

A variety of formulations can lead to an estimate of the resource base. One simple example

is shown in figure 9, which plots the rate of discovery of natural gas, in thousands of cubic feet

per foot of exploratory well drilled, versus the

cumulative footage drilled. An exponential or

other function can be fit to the historical data and

extrapolated into the future. After f feet have been

drilled, the area under the curve is equal to the

total amount of gas discovered up to that point. *

The total resource base can then be estimated by

measuring the area under the curve when it has

been extrapolated to the point where all recover-

*Area=J t (amount of gas discovered per foot drilled)

d (cumulative feet drilled].

able gas has been located. This point is assumed

to be:

. when the amount of gas discovered per foot

of drilling falls below some chosen lower

limit, or

● when the cumulative exploratory footage is

judged high enough to have allowed essentially all prospective acreage in the United

States to have been explored.

Although Hubbert’s estimate of gas resources

will be reviewed individually later, historical approaches to gas resource estimation as a class have

some common limitations. First, areas that are not

“mature’ ’-that do not have a substantial drilling or discovery history—are not represented in

the historical data base and can be included in the

assessment only if one is willing to assume they

are part of the development process of a larger

area and are not really independent. Consequently, Alaska is typically not included in the historical approaches, and the offshore areas are sometimes excluded as well. This limitation can be a

problem with geologic as well as geographic categories; there is some question, for example, as

to whether deep gas (below 15,000 ft) should be

included in a “historical” resource estimate.

Second, since the resource estimates are totally dependent on extrapolations of the historical

record, they depend heavily on the accuracy of

this record. In the case of natural gas, this accuracy is probably poor. Through much of its discovery and production history, gas was usually

a byproduct of the search for and production of

oil and in the early years was often considered

to be of very low value at best. Much gas was

flared or otherwise wasted, production records

were not kept, and gas discoveries often went unreported.

Third, all of these methods share the common

assumption of all trend extrapolations: the future

will be a reflection of the past. However, the

“past” in the case of gas exploration and development has had interludes of radical change in the

economic underpinnings and Government regulation of the industry and, to a certain extent, in

the technology and geologic understanding driving the development process. Consequently, the

historical approaches contain the implicit assump-
3 4

Figure 9.— Discoveries of Recoverable Natural Gas in the Lower 48 States v. Cumulative Exploratory Drilling

1,400 I

1,300

1,200

1,100

1.000

4 Expected growth

Reported

12345678 9 10 11 12 13 14 15 16 17 18 19 20 21

Cumulative exploratory drilling (108 ft)

SOURCE David H Roof USGS
35

tion either that the process of change will continue in the same manner in the future or that the

physical nature of the resource base—unchanging

except for changes wrought by development itself—is the main force driving gas development.

In the long run, the physical nature of the resource

base is seen as overwhelming the importance of

volatile and transitory events or forces such as

Government regulations and gas demand and

price in determining the shape of the development

curves. *

Fourth, it is difficult to define the economic,

technologic, geographic, and geologic boundaries

of a resource assessment based on historical

trends. For example, data on the development of

U.S. gas resources tracks a steady expansion of

geographic coverage of exploration and production, an increase over time in the depth of wells,

and a radical improvement in exploration technology. Did historical assessments of the U.S. gas

resource done before Anadarko deep drilling include or exclude this deep resource? Will an assessment based on historical data account for a new

Overthrust Belt type of development? To the extent that the historical curves capture past change,

can they account for future changes? These questions are essentially unresolved. A common criticism of historical approaches is that they do not

adequately capture the effect of new technologies

and other changes. However, there is little agreement on what they do capture: opinions range

from the full capture of future economic conditions’ to the capture only of gas that would be

discovered and produced under the socioeconomic

conditions of the last several decades7—in other

words, from the top two-thirds of the McKelvey

Box to only the top third.

It is worth noting that a substantial “surprise’’—e.g., the unexpected discovery of a new

geologic “horizon’ ’-cannot be accurately pre-

‘In support of this view, It IS worth mentioning that neither the

ma]or techn]cal advances In exploration nor the open]ng of new territories since World War I I were ot sufflclen t 1 mportance to restore

the o]] or gas d]scovery rate to pre-war levels; instead, the d]scovery

rate continued a fairly steady downward drift for several decades,

in seeming disregard of changing conditions and technology,

‘Ibid

‘R, I’ Sheldon, “Est]mates of Undiscovered Petroleum Resources—A Perspective, ” U S. Geolog]ca] Survey Annual Report,

Fiscal Year 1978.

dieted by a historical approach. This is because

a true surprise will not have affected the previous

discovery and production history in any discernible manner. Therefore, the historical method will

yield the same resource estimate no matter how

big the surprise turns out to be. (Although the

geologic approach cannot predict such a surprise,

it can incorporate its effects immediately for future

predictions. )

Fifth, although “historical approaches” seek to

extrapolate trends that are functions primarily of

the resource base and are relatively unaffected by

transient economic effects, the available data may

be too aggregated to allow this. Generally, the

data measure processes that are made up of two

or more components, some of which are sensitive

to market conditions. For example, the finding

rate of new field wildcats may be used to represent the success of the discovery process. * However, finding rate data measure the combined success of at least two quite different kinds of exploration. The high-risk, high-payoff wildcats represent the search for large fields in untried areas and

the exploration of older areas based on new geologic interpretations. The finding rate of these

wildcats is a critical determinant of the long-term

replenishment of proved reserves. The low-risk,

low-payoff wildcats represent the redrilling of old,

formerly uneconomic areas, or the clustering of

exploratory drilling around a successful new

strike. Because drilling statistics do not separate

new field wildcats into different risk categories,

the data on low-risk, low-payoff drilling, which

is very sensitive to market conditions, dilutes and

distorts the data on the drilling activity most relevant to ensuring the future of gas production.

The problem of using a single data series to

measure a process that has two or more dissimilar

components becomes more acute as larger and

larger aggregations, geographical and otherwise,

are used. Compiling the data for individual provinces may be useful because, for example, exploratory drilling on a local scale is more likely to be

either high or low risk rather than a combination

‘Discover y data ~enerall}r is preterred o~er production data ]n

a historical approach because the dlscover}~ cycle IS always a few

years older than the production cycle, Extrapolation to the end of

the cycle consequently is less severe for dlscover}~ than for

production,
3 6

of the two. Thus, a disaggregated approach conceivably may be more successful than a national

one in appropriately interpreting implications of

a changing finding rate. On the other hand, the

reduction in data points may tend to cause data

series for small areas to be very erratic, and aggregation over larger areas may be necessary to

detect long-term trends.

Dealing With Uncertainty

It must seem obvious from past mistakes that

petroleum resource assessment is a risky business.

For example, tracts in the offshore South Atlantic shelf were recently leased to industry for millions of dollars (proceeds from the first two sales,

lease sales 43 and 56, exceeded $400 million’) with

an industry/Government consensus that large volumes of economically recoverable oil and gas were

present, yet drilling results have thus far been negative. 9 Similarly, expected large fields in the Gulf

of Alaska have failed to materialize under the

drill. Conversely, drilling since 1975 in the Western Overthrust Belt has revealed a large, previously misunderstood potential for oil and gas. Even

the calculation of proved reserves is uncertain and

in some instances (e. g., Louisiana and Texas) has

required extensive corrections in later years.

A major reason for the risk in resource assessment is that the presence of economically recoverable concentrations of petroleum requires the

completion of an unbroken chain of events, each

of which is difficult to predict. First, adequate

amounts of source rock containing organic material must be present. Second, the temperature

and pressure conditions must remain within a

range capable of transforming the organic matter into petroleum. Third, geologic conditions

must be right to allow the petroleum, once generated, to migrate. Fourth, permeable and porous

rocks must be in the migration path to serve as

a reservoir. Fifth, a geologic structure must be

present to trap the petroleum so it can accumulate

into commercial quantities. Not only the availability of the required conditions but also their timing are critical. The presence of an adequate trap,

8USGS Open-File Report 82-15, South Atlantic Summary Report

2, May 1982.

‘Ibid.

detectable with seismic or other search techniques,

does not guarantee that the trap was present at

the time of petroleum migration; if it was not, or

if the trap was breached at some time after the

petroleum entered the reservoir, the oil or gas

would have escaped and would probably have

reached the surface and dissipated.

Some estimators either (apparently) ignore uncertainty or acknowledge it only by expressing

their results as an undefined or vaguely defined

range (e. g., “optimistic/pessimistic”). Uncertainty

can be dealt with explicitly and quantitatively in

resource estimations, however. Resource estimates, or the individual factors used in estimating

resources (e. g., volume of sedimentary rock, hydrocarbon yield factor), can be expressed as probability functions instead of point estimates or

ranges. For example, figure 10 illustrates a hypothetical probability function for the undiscovered

recoverable gas resources of a single province. The

curve shows the probability that there are more

than Q undiscovered resources in the province. *

“Probabilistic estimates” such as these cannot be

directly added (or, in the case of estimates for

volumes and yield factors, multiplied) to form ag-

*The probabilit y is not 100 percent at Q = O because there is a

finite probabilit y that the province does not have “more than O

resources; “ in a totally unexplored province, this probability of zero

recoverable resources may be quite large.

Figure 10.— Probability Distribution for Undiscovered

Recoverable Gas Resources in a Province

I
37

gregate resource estimates, such as an estimate of

total U.S. gas resources. Instead, they are added

statistically; one commonly used technique is

called Monte Carlo simulation (see box A). *

Although probabilistic methods are useful for

displaying some of the uncertainties associated

● In Monte Carlo simulation, a value is selected at random from

each of the separate probability functions that are the components

of the resource estimate (e. g., for a nationwide assessment, the components are the individual province assessments; for a volumetric

resource assessment, the components are the volume of sedimentary rock and the hydrocarbon yield factor). These values are then

combined arithmetically to form a single point estimate of the

resource base (for the nationwide assessment, the values from each

province are added; for the volumetric, the values selected for

volume and yield are multiplied ). This procedure is repeated many

times, each time producing a new point estimate, until a probability function for the resource base is formed.

with resource estimation, the language used to

describe the results of these methods is often misunderstood by a lay audience. It is critical to remember that the accuracy of probabilistic estimates is limited by the extent to which the estimators’ model of the physical universe is a correct one. In estimates such as those of USGS, the

“95th percentile” estimate should not be interpreted as meaning that there actually is a 95 percent probability that the resource base is larger

than this estimate. It should instead be interpreted

to mean only that the assessors, with whatever

limitations their geologic “mindsets” and their limited data may impose on them, believe that there

is such a 95 percent probability. This difference

may seem subtle, and it certainly is not kept secret

by the estimators, but it is nevertheless important.

Box A.—Does the Monte Carlo Technique Underestimate Uncertainty?

An analytical problem with the probabilistic estimates of national gas resources is that the Monte

Carlo method, when used to link individual province estimates together, usually assumes that the

individual estimates are completely independent from one another. In lay language, “independence”

of this sort means that any additional information gathered from one petroleum province can in no

way be applied to any other province, and that a change in one province’s estimate won’t affect any

others’ estimates. In other words, independence assumes that so much is known about the geologic

principles underlying petroleum formation and occurrence that the only things to be learned by additional drilling are site- or province-specific.

In reality, few if any geologists would claim such an advanced state of knowledge. Instead, it

seems likely that additional knowledge of a pessimistic nature—discovery that resources in several

provinces actually were leaning toward the low end of the original estimate—can cause estimates in

some other provinces to be revised downwards, and vice versa. For example, geologists are currently uncertain about the number of small fields* in the resource base because past exploration ignored the discovery of such fields (they were too small to be considered producible). If the search

for such fields became highly successful in one or more provinces, this success would probably cause

geologists to reassess the significance of small fields in other provinces as well. Province-to-province

dependence of this sort implies that the “optimistic” (high) national resource estimates probably aren’t

optimistic enough, nor are the “pessimistic” estimates pessimistic enough. In conclusion, the high-low

ranges flowing from Monte Carlo-based probabilistic resource calculations that assume province-toprovince independence are too narrow, that is, they understate the uncertainty associated with combining the individual province estimates into a regional or national estimate. The error introduced

by the actual dependence of the estimates may be reduced, however, by careful choice of province

boundaries and by making the provinces large enough.

*A small field may be defined as one with an ultimate production of less than 10 million barrels of oil, 60 billion cubic feet of natural

gas, or comparakde amounts of oil and gas energy expressed as bamds of oil equivalent (WE), usiw 6,000 cubic feet of gm = equal to 1 barrel of oil.
38

COMPARISON AND REVIEW OF INDIVIDUAL ESTIMATES

Although many readers may be aware only of

the work of USGS and perhaps that of M. King

Hubbert, assessments of the U.S. natural gas

resource base are quite numerous and use a wide

variety of approaches. Table 6 lists some of the

more recent estimates of the “ultimately recoverable resource’’—the total amount of gas that will

be produced. The table also shows estimates of

the recoverable resource remaining as well as the

resources not yet added to proved reserves. The

wide range of mean estimates for the remaining

resources in

trillion cubic

range in the

especially in

the Lower 48 States—244 to 916

feet (TCF)—implies, in turn, a wide

outlook for future gas production,

the longer term.

Many available resource assessments are poorly

documented and cannot be evaluated. OTA has

reviewed some of the more widely known estimates, however, including those of USGS, PGC,

the RAND Corp., and M. King Hubbert.

U.S. Geological Survey

Recent estimates of undiscovered gas resources

by USGS, as presented in 1975 in “Circular 725”10

and more recently in 1981 in “Circular 860,”11 are

IOB M, Miller, et a]., Geological Estimates Of Undiscovered

Recoverable Oil and Gas Resources in the United States, ” USGS

Circular 725, 1975.

I IDo]ton, et al. , op cit.

Table 6.—Alternative Estimates of Ultimately Recoverable and Remaining Natural Gas in the United States (TCF)

Remaining resources

Ultimately recoverable resources

not yet ‘added to

Publication Remaining resources proved reserves,

Estimator date Lower 48 Total U.S. Lower 48, 1983a

Lower 48, 1983b

Mobil . . . . . . . . . . . . . . 1974 — 1,076-1,241-1,456 —

Garrett . . . . . . . . . . . . .

—

1975 — 1,313 —

Wiorkowsky . . . . . . . . .

—

1975 1,221 -1,289-1 ,357a — 595-663-731 421-489-557

Bromberg/Hartigan . . . 1975 966’ — 340 166

Exxon Attainable . . . . 1976 — 917-1,112-1,577 —

Shell . . . ... , . . . . . . . .

—

1977 946 910-1,075-1,260 320 146

IGT . . . . . . . . . . . . . . . . 1980 — 1,288-1,798 —

PGC . . . . . . . . . . . . . . .

—

1983 1,542 1,711 916 742

Hubbert (1). . . . . . . . . 1980 870 — 244 70

Hubbert (2). . . . . . . . . . 1980 989d — 363 189

RAND ... . . . . . . . . . . 1981 902 989 283 109

USGS . . . . . . . . . . . . . . 1981 1,400 1,422-1,541-1,686 774 600

.

‘Approximate cu~ulatlve Lower @ production through 1982 was 631 TCF, of which about 5 TCF IS in underground storage Remaln!ng resource’ Is “Lower 48” (ultimately

brecoverable) column value minus 631 TCF plus 5 TCF

Lower 48 proved reserves assumed to be 169 TCF at 12/31/82 (excludlng underground storage)

~Original esttmate for onshore gas only Total arrived at by addtng USGS (mean) estimate for ultimately recoverable offshore gas (n Lower 48 (235 TCF)

Based on an analysls of finding rates by David Root, USGS

SOURCE Mobil—J D Moody an-d R E Geiger, “Petroleum Resources, How Much 011 and Where, ” Technology Review, March/April 1975 Verbal comments by John

Moody at a FPC presentation, Ap;. 14, 1975

Garrett-R W Garrett, “Average of Some Estimates by Malor Oil Companies and Others, 1975, ” oral presentation at Executtve Conference of the American

Gas Assoc!atton, June 911, 1975, cited In Potential Gas Committee, A Comparison of Est/rnares of U/f/mare/y Recoverable Ouanf/t/es of Nafura/ Gas In the

Un/fecf States, Gas Resource SIudtes No 1, Potential Gas Agency, April 1977.

Wiorkowski-J J. Wlorkowskl, Estlrrratlon of 0// and Natural Gas Reserves Us/rrg H/storica/ Data Series A Cr/t/ca/ Rewew, unpublished manuscnpt, 1975,

c!ted In J J Wlorkowsk!, “Estimating Volumes of Remaining FossIl Fuel Resources A Cr!tical Review, ” In J Am Sfaf Assoc , VOI 76 No 875, September 1981

Bromberg/Hartigan-L Bromberg and J A Hartlgan, Repori to the Federa/ Energy Adm/r?/strat/on, unpublished manuscript, 1975, cited In Wlorkowskl (1981 ),

noted above

Exxon—Exxon Co , U S A Exploration Department “U. S 011 and Gas Potent ial,” March 1976 Oil and Gas Journal, “Exxon Says U S St Ill Has Vast Potential

Mar 22, 1976

Shell—C L Blackburn, Shell 011 Co., “Long-Range Potenttal of Domestic Oil and Gas, ” presented at NAPIA/PIRA Fall Conference, Boca Raton, Fla Oct

19, 1978 0// and Gas Jouma/, “Shell Alaska Holds 58°/0 of Future U S. 011 Finds, ” Nov 20, 1978

IGT—J D Parent A Survey of Un/ted States and Tofa/ World Product/on, Proved Reserves, arrd Rema/n/ng Recoverable Resources of FossI/ Fue/s and Uran/um

Institute of Gas Technology, Chicago, August 1980, c!ted (n Amertcan Gas Association, “Energy Analysls” A Comparison of U S and World Remalnlng Gas

and 011 Resources, ’ Aug 7, 1981

PGC– Potential Gas Agency, News He/ease–February 26 1983

tiubberi (1) (2)—M K Hubbert, “Techniques of Predlctlon as Applied to the Production of Otl and Gas, ” In 0// and Gas Supp/y Mode//rig, S I Gass (ed )

National Bureau of Standards Special Publlcatlon 631, May 1982

RAND—R Nehrlng wtth E R Van Driest II The D~scovery of S/grr/f/cant 0// and Gas F/eIds In the Un/fed States, R 2654/1 USGSJDOE, RAND Corp

January 1981

USGS—G L Dolton, et al Es((mates of Undiscovered Recoverable Convenf/ona/ Resources of 0// and Gas In the Urr/ted S/afes, U S Geological Survey Ctr.

cular 860, 1981
39

probably the most widely used gas resource estimates. The most recent estimate uses a Delphitype approach whereby teams of geologists arrive

directly at resource estimates for individual petroleum provinces through a subjective assessment

of the available geological data and the results of

a variety of estimation approaches (including volumetric, play analysis, and other geologic methods as well as finding-rate analyses and other his -

torical methods).

The estimates are probabilistic, that is, each is

presented as a curve that shows the probability

that the actual resource base is larger than any

particular value (see fig. 10). Thus, the 95th percentile estimate reflects the USGS assessment that

there is a 95 percent probability that the actual

resource base is at least this large. Because only

those resources that are virtually certain to exist

are included, this estimate would be considered

the pessimistic extreme of the range of estimates.

The individual province estimates are added statistically, using a Monte Carlo technique, to

achieve a national estimate. As described previously (box A), the “high-low” range described

by the 5th and 95th percentiles is narrower than

would be the case if the interdependence of individual province estimates could be taken into account. However, the potential problem was described as minor by the experts OTA talked with,

largely because of USGS’s selection of province

boundaries.

The USGS assessment is unusual in that individual probabilistic estimates are available for

each of 137 provinces, providing a very fine level

of detail. Also, detailed information files on individual provinces are open to the public at

USGS’s Denver facility. As with most geologic

estimates, the USGS estimate is not meant to include all resources that may be recoverable at any

time, but is instead limited to the resources that

“will be recoverable under conditions represented

by a continuation of price-cost relationships and

technological trends that prevailed at the time of

assessment (1980).” 12 Consequently, resources that

are currently in fields that are too small, under

too much water, under geologic conditions that

are too difficult, or are otherwise not economical-

“Ibld

ly recoverable are not reflected in the current estimates but could be expected to enter the recoverable resource base in the future if gas prices rise

and technology improves significantly.

In contrast to the approach for estimating resources in undiscovered fields, USGS calculated

the remaining resources in undiscovered pools in

known fields and expansion of the proved areas

of known pools’ by using a simple extrapolation

from historical records of gas-field growth.13 Field

growth is a significant source of gas, and USGS

calculated the resources in this category to be

about 172 TCF, or over one-fifth of the remaining gas resources. Unfortunately, the USGS approach to assessing this source is problematical

because the historical growth rates of known fields

have tended to be extremely variable, and the

characteristics of fields discovered recently, and

calculated by this method to yield the most

growth, are quite different from the fields that

supplied the historical data. In OTA’s opinion,

there is a significant potential for error in this

approach.

In USGS’s 1975 resource estimate, the economic

boundary of recoverable resources also proved

to be a problem; a survey of the assessment team

revealed considerable differences between their

various interpretations of the meaning of the

boundary definition. ” Although OTA undertook

no formal survey for the 1981 assessment, informal talks with analysts close to the assessment

process lead OTA to believe this problem still exists. For example, several analysts believe that part

of the offshore resource in the USGS assessment

is far too expensive to be developed unless gas

prices escalate substantially. If this is correct, these

resources are subeconomic, according to USGS’s

definition, and should not be included in the estimate of recoverable resources.

Another potential problem area in the assessment is the boundary between “conventional” and

“unconventional” resources. The USGS estimate

*These resources are called “inferred reserves In the USGS assessment and are equivalent to the “Probable potential resources” i n

the PGC assessment,

“Ibid, app, F.

“Personal communication with John .Schanz, Congressional]

Research Service.
is of “undiscovered recoverable conventional

resources (our emphasis)” and excludes “gas in low

permeability (’tight’) reservoirs” and other socalled unconventional resources.15 The precise

meaning of the exclusion is unclear, however. In

moving towards lower and lower permeabilities,

there is no general consensus about where “conventional but low permeability reservoirs” end

and “unconventional ‘tight’ reservoirs” begin, and

USGS has not defined a threshold value of permeability to separate the two.

Circular 860 does imply, however, that some

undiscovered gas in low-permeability reservoirs

was excluded from the estimated conventional

resource base even though the gas could currently be defined as economically recoverable. Consequently, all else being equal, the USGS estimate

should be expected to be smaller than estimates

that include all economically recoverable gas

resources.

It also is commonly believed that USGS’s

Delphi technique, described by USGS as relying

on reviews of the results of a variety of approaches, relies primarily on the results of

volumetric analysis. This reliance on the volumetric approach is probably due to data limitations.

The USGS data base, although substantial, is generally limited to public data. 16 Volumetric analysis

has often been associated with relatively optimistic resource assessments.

Potential Gas Committee

The estimates of “potential” gas resources—recoverable resources that have not been produced

or proved—by the PGC represent the gas industry

counterpoint to the USGS estimate. *

Is~(, ]ton, et al. , oP, Cit

16G. Dolton, USGS, presentation at RAND workshop on est imating U.S. natural gas resources, Washington, D. C., Mar. 1-3,

1982.

● PGC lb composed of members and observers from gas producers,

pipelines, and distribution companies and observers from the

American Gas Association, Department of Energy, Gas Research

Institute, and other public and private organizations. The actual

estimating workgroups consist mainly of industry employees and

consultants, but State geological surveys are well represented, and

some of the groups include personnel from Federal agencies and from

universities.

PGC’s most recent estimate of the total U.S.

potential resource—876 TCF for the end of

1982 17—represents a decrease from the year-end

1980 estimate.18 Because this decrease is balanced

by additions to proved reserves during the period,

the old and new estimates are similar in their estimates of total ultimately recoverable resources.

The PGC estimation procedure is generally

structured like a volumetric analysis in that the

PGC analysts separately estimate the volume of

potential gas-bearing reservoir rock and a yield

factor (amount of gas per volume of rock) and

multiply the two to arrive at an initial resource

estimate. The analysis combines aspects of other

geologic approaches, however. It is also strengthened by the separate estimation of gas potential

for 11 distinct geographical areas within the Lower

48 States, for three distinct categories of resource

within the areas according to their state of development, * for offshore and onshore resources, for

resources above and below a depth of 15,000 ft

in the onshore portion, and for resources above

and below water depths of 200 meters to a maximum of 1,000 meters offshore. The estimates “include only the natural gas resource which can be

discovered and produced using current or foreseeable technology and under the condition that

the price/cost ratio will be favorable.’’” These

conditions are similar to those adopted by USGS,

but what constitutes a “favorable price/cost ratio”

remains unclear. The large proportion of deep resources incorporated in the estimate may imply,

however, that PGC has included resources that

will require prices above present market clearing

levels. * *

The PGC volumetric estimation procedure is

considerably more sophisticated than early tech-

“News Release, Potential Gas Agency, Feb. 26, 1983.

Ispotentia] Gas Agency, Potential Supply of Natural Gas in the

United States (as of December 31, 1980), May 1981.

*The categories are “Probable, ” “Possible, ” and “speculative”

resources. Probable gas results from the growth of known fields,

Possible gas is associated with the projection of plays or trends of

a producing formation into a less well-explored area of the same

geologic province, and Speculative gas is from formations or provinces that have not yet proven to be productive.

‘

g Ibid.

* *On the other hand, the actual price requirements for producing deep gas under free market conditions are uncertain, and it is

possible that much of PGC’s deep potential is producible at prices

not far removed from today ’s.
—.

41

niques that were based on total volumes of sedimentary rock. In the PGC analysis, the volumes

of potential gas-bearing reservoir rock are estimated by adding up estimates of individual traps

and trap sizes where sufficient data is available.

According to PGC’s methodology description,’”

techniques such as play analysis and field number

and size approaches are used to construct an areawide volume estimate based on a variety of existing geological data. Yield factors (gas volumes rock volumes) are then calculated by selecting appropriate analogs from producing areas and

adjusting the yields to account for geochemical

factors such as the thermal history of the source

rocks. Finally, the analysts are asked to multiply

the (volume) x (yield) estimates by their assessments of the probabilities that traps actually

exist and that an actual accumulation of gas has

occurred.

The analysts also are asked to separately estimate “optimistic, “ “most likely, ” and “pessimistic”

volumes of gas in a manner similar to that of the

USGS. In contrast to USGS, however, PGC publishes only the “most likely” estimates. The other

estimates are apparently used for review purposes

on] y.

Because PGC publishes only the results of its

analyses and does not release any internal details

of the resource calculations (except for general

methodology descriptions), and because it is essentially a gas industry organization, the credibility of PGC’s resource estimates may be questioned.

In OTA’s opinion, however, the PGC estimates

should be taken as a serious effort at resource

assessment by analysts with excellent access to exploration data. The estimating workgroups, although composed mostly of industry employees,

have a sufficient number of other participants—

and a sufficient divergence of incentives within

different segments of the industry-to prevent any

attempts to subvert the assessment process significantly. Also, the long-term professional history

of the organization (since 1966) and the oversight

of the Colorado School of Mines are substantial

arguments for accepting the PGC estimates as

honest reflections of the professional judgment of

the organization.

2“Ibld

An advantage of the PGC estimates is that the

basic methodology has been applied, with evolutionary changes, for 16 years. Table 7 shows the

eight estimates of ultimately recoverable gas resources in the Lower 48 States produced by PGC

since 1966. The consistency of these estimates is

high. In fact, given the advances in technology

and the major additions to the known boundaries

of conventional gas supply that have occurred in

the past 16 years, * the mildness of the upward

trend in the estimates over this time period implies a movement toward more conservative

estimates. This conservatism is particularly interesting in light of PGC’s resource estimates being among the most optimistic of the major

assessments.

In its 1982 assessment, PGC attempted to isolate

that portion of the estimated potential resource

that occurs in tight formations—tight sands with

permeability levels less than 0.1 millidarcy (conforming to the Federal Energy Regulatory Commission definition for gas eligible for incentive

pricing) and Devonian shales. A series of areawide

estimates were produced for depths above and below 15,000 ft. The “tight” portion of the U.S.

potential gas resource was estimated to be about

20 percent of the total, or 172 TCF.

This estimate is highly significant for two

reasons. First, it demonstrates graphically the

*For example, the addltlon of the \\’estern Overthrust Belt due

]arge]y to advances In selsmlc technc~logy and the addition Of large

amounts of gas trom low-permeable formations due to advances

in fracturing.

Table 7.—Comparison of Potential Gas Committee

Estimates of Ultimately Recoverable Gas Resources

in the Lower 48 States

Ultimately recoverable

Estimate as of yearend resources (in TCF)

1966 .., . . . . . . . . . . . . 1<283

1968 . . . . . . . . . . . . . . . . 1,426

1970 . . . . . . . . . . . . . . . . 1,498

1972 ........, . . . . . 1,446

1976. , . . . . . . . . . . 1,396-1,421-1,446

1978 . . . . . . . . . . . . . . . . 1,550

1980, . . . . . . . . . . . . 1,502

1982 ......, . . . . . . . 1,542a

aApprOXlmate-Apofllon of the difference between the 1980 and 1982 estimates

IS due to discrepancies between the proved reserve values computed by AGA

(used for the 1980 calculation) and the EIA (used for the 1982 calculatlonl

SOURCE Potent [al Gas Agency, Po(ent(a/ Supp/y of Nafural Gas In the Ufrffed

States (as of December 31. 1980) May 1981 and Potential Gas %en -

cy, News Release Feb 26 1983
4 2

long-term growth in the “ultimately recoverable”

gas resource base and offers some support to the

optimistic view that advancing technology can

overcome at least some of the effects of resource

depletion. Second, to the extent that other resource assessors may have excluded tight gas from

their estimates, it may bring the PGC estimate

closer to the “mean” of gas resource estimates in

table 6. Unfortunately, the definitions of the

boundary conditions of most of the assessments

in table 6 are not sufficiently clear to ascertain

whether tight gas that is recoverable under the

PGC boundary conditions were excluded or included. A possible exception, however, is the

USGS assessment, whose stated boundary conditions appear to be more restrictive than PGC’s.

It is probable that some of the tight gas included

in the PGC estimate was not included in the USGS

estimate.

RAND/Nehring

Richard Nehring of the RAND Corp. has produced an assessment of conventional U.S. oil and

gas resources by a method that stresses an evaluation of the discovery of significant fields. z] The

assessment incorporates a variety of approaches:

1. To estimate the growth of reserves in known

fields, a combination of methods were used,

including extrapolating by historical fieldgrowth factors and by more analytical approaches that used available geologic information and known production practices.

2. To estimate the amount of resource remaining to be discovered in known producing

plays, an approach based on extrapolating

historical trends was used. The key to this

approach was the establishment of a data

base containing production and reserve

values, the year of discovery, discover y

method, trap type, depth, and other data for

virtually every petroleum field discovered in

the United States by 1975 larger than class

C (10 million to 25 million barrels-of-oilequivalent). Despite the emphasis on the

z I R Nehring with E, R. Van Driest II, The ~~scovery of Significant Oil and Cas Fields )n the United States, RAND Corp. Report

R-2654 1 -USGS DOE, January 1~81.

historical record, however, the approach

also incorporates geologic methods based on

play analysis.

3. Play analysis was used to estimate the

resources in new plays in mature regions.

4. Depending on the availability of data, a

variety of approaches were used to estimate

resources in the frontier (ranging from volumetric analysis to field number and size

approaches).

The estimates for new plays in mature regions

and frontier areas were “risked” (i. e., the probability that there are no recoverable resources in

the play is taken into account), and the assessments of undiscovered resources were expressed

as probability distributions in a manner essentially

identical to that used by USGS.

The RAND assessment has been criticized because of its alleged failure to define the process

by which its massive data base is translated into

resource base conclusions. In OTA’s opinion, the

description of the methodology that appears in

the RAND report is indeed brief and generalized

and gives no specific examples of the assessment

process. However, this failure is endemic to resource assessments as a class. Even the PGC assessment, which describes its analytical process

in some detail, publishes no backup data and provides only the sketchiest details of the geologic

reasoning behind its regional results. In contrast,

the RAND assessment explicitly defines the historical and geologic reasons for its regional

assessments and identifies—and argues against—

opposing views. This approach allows at least a

partial evaluation of the assessment, whereas most

assessments can be evaluated only to the extent

of either accepting or rejecting the final estimates.

At the core of Nehring’s argument for his quite

pessimistic estimate is the thesis that the geologic

possibilities for finding substantial new oil and gas

resources in the United States have been largely

exhausted. Nehring identifies four major hypotheses about where significant amounts of oil and

gas may yet be found—in fields below 15,000 ft

in depth (for natural gas only); in subtle, difficult-to-detect stratigraphic traps; in small fields;

and in frontier areas, including the Eastern and

Western Overthrust Belts—and argues against
4 3

high optimism in each, with the possible excep- covered petroleum (oil plus gas) resource equal

tion of the frontier areas. The four hypotheses and to that predicted in the 1975 USGS (Circular 725)

Nehring’s countering arguments are summarized onshore assessment. This distribution would also

in box B. A more detailed discussion of these hy- be approximately equivalent to the more recent

potheses is presented later in this chapter. 1981 (Circular 860) USGS assessment, although

the more recent assessment is slightly more optiA second facet to this argument is that this ex- mistic. In the table, the proposed distribution is

haustion of geologic possibilities is reflected in the compared to actual field discovery statistics for

recent (disappointing) history of exploratory drill- 1971 through 1978. The last column shows how

ing. Nehring argues that optimistic assessments long it would take to find the necessary number

simply do not bear up under the weight of the of fields of each size category if the annual disquestion, “Is it likely that we will find as many covery rates of 1971 through 1978 continued for

large fields as this assessment implies must be the life of the resource. In Nehring’s opinion, the

there?” For example, table 8 presents a proposed number of large fields that would have to be disfield size distribution that would yield an undis- covered to fulfill the USGS assessment is too large

Box B.—Rand Assessment’s Arguments Against a Large Undiscovered Oil and Gas Resource Base

Deep Discoveries

• Major argument: Deep sediments are relatively unexplored. The few exploratory wells that have been

drilled have been highly successful.

● RAND rebuttal: Physical and chemical conditions at these depths can be poor for methane stability.

Reservoir porosity is often lacking. The area with deep sediments is a small fraction of total prospective sedimentary area. Most of the potentially productive structures in several basins have already

been tested.

Stratigraphic Traps

Major-argument: Exploration has focused on structural traps, leaving significant opportunities in

subtle stratigraphic traps.

RAND rebuttal: Actually, considerable attention has been paid to stratigraphic traps in the Anadarko,

Permian, and other basins. Aside from the stable interior provinces, multiple stratigraphic traps are

unlikely. Because stratigraphically trapped reservoirs tend to be thin, large fields would cover large

areas and would likely have been discovered. Large traps would be vulnerable to breaching and other

causes of petroleum loss.

Very Small Fields

Ž Major argument: Because small gas fields were previously subeconomic, their discovery went unreported. Many more small fields exist than indicated by historical experience, and they form a sizable

part of the recoverable gas resource.

● RAND rebuttal: Future reliance on small fields is based on assumption only; there is neither historical

nor geologic argument to back it up. Also, because giant and large fields are two-to-four orders of

magnitude larger than fields small enough to have been ignored in the past, there would have to be

many tens of thousands of such fields to make any significant difference.

New Frontiers

● Major argument: Areas such as Alaska, the offshore Lower 48 States, and the Overthrust Belts have

not been extensively explored and offer the potential for many significant discoveries.

• RAND rebuttal: Yes, but the small number of exploratory wells drilled in the Gulf of Alaska, the

Outer Banks of California, the eastern Gulf of Mexico, the Southeast Georgia Embayment, and Baltimore Canyon are sufficient to severely dampen optimism for these areas. Some very promising areas

do remain, however, including the deeper Gulf of Mexico, offshore Ventura Basin, and others.

SOURCE Off,ce of Technology Assessment, based on R Nehnng, The D,scovery of S~gnJfic.nt Oil and Gas Fields m the United Staks, !?-2654/I-Us~s/~E, RAND

Corp., January 1981
44

Table 8.—Field Discovery Implications of USGS Circular 725, Onshore Lower 48 Undiscovered Petroleum Resource

Potential field size

distribution: USGS

Field sizea Circular 725

AAAA (>500/>3,000) . . . . . . . . . . . . . . . . 11

AAA (200-500/1,200-3,000) . . . . . 44

AA (100 -200/600-1 ,200). . . . . . . . . . . . . . 94

A (50-100/300-600) . . . . . . . . . . . . . . . . 199

B (25-50/150-300) . . . . . . . . . . . . . . . . . 375

C (10-25/60-150) . . . . . . . . . . . . . . . . . . 977

D (1-10/6-60) . . . . . . . . . . . . . . . . . . . . . 6,000

E ( <1/< 6) . . . . . . . . . . . . . . . . . . . . . . . 70,000

Actual field discoveries

1971-75 1976-78

0 1

0 0

7 1

7 3

15 8

44 22

4 5 5

b —

3,041 b

Implied time to find

USGS undiscovered resource,

constant annual discovery

rate at 1971-78 average (years)

88

Large but indeterminate

94

159

130

118

66

115

avalue~ ,n ~a~enthesls are size range In mllllons of barrel sof-oil. equivalent (mm boe)/bllllons of cubic feet of gas (BCF)

b197276, Committee on Statistics of Drilling of the American Association of Petroleum Geologists

SOURCE Off Ice of Technology Assessment, based on R Nehrlng, The Discovery of Sigruflcaflt 01/ and Gas F/eIds fn the Urrffed States, RAND Corp report

R.2654/l-USGS/DOE, January 1981 Also, personal communication, Richard Nehring

to be credible. The long “times of discovery” in

the table appear to reinforce this opinion. Unfortunately, none of the reviewed assessments defined a timeframe for complete discovery of the

resource base, and an interpretation of the compatibility of a particular resource base/discovery

rate combination is anything but straightforward.

Also, the cessation of the American Gas Association’s (AGA) reserve data (particularly reserve additions from new field wildcats) in 1979 prevents

an easy check on whether post-1978 new field

discoveries are ahead of discoveries during 1971-

78; if they were, an argument could be made that

the times in table 8 were misleadingly long because

the assumed discovery rate was too low. On the

other hand, the assumption in table 8 of a constant annual discovery rate for new gasfields over

a 50- to 100-year period appears optimistic, even

if the assumed rate is a bit low at the beginning

of the period. This is because discovery rates per

foot drilled appear likely to decline during this

period, and a constant annual discovery rate thus

implies an ever-increasing rate of new field wildcat

drilling in an increasingly hostile and expensive

environment.

One portion of the RAND assessment that now

seems particularly suspect is the median estimate

for field growth. The estimate (67 TCF) was only

about one-third of the field growth estimates of

USGS and PGC, a seemingly surprising difference

considering the substantial amount of geologic

knowledge available. * Recent large reserve addi-

‘However, the recent controversy over the magnitude of additional gas that might be obtainable from old gas decontrol

tions from field growth make it clear that this

estimate was too low. *

Hubbert

As noted earlier, M. King Hubbert is one of a

considerable number of analysts who have used

a historical approach—fitting curves to past trends

in production, reserve growth, discoveries, etc. —

to petroleum resource assessment. However, Hubbert’s estimates must be accorded special attention. In 1962, Hubbert predicted that U.S. oil production would peak in 1969 and decline thereafter.

He then held his ground in the face of substantial

criticism until the peak actually did occur, only

a year later than he said it would. From that time,

his assessments of petroleum trends and resources

have received considerably more attention and respect.

Hubbert’s most recent estimate of the size of

the natural gas resource base was made in 1980.22

He estimates the ultimate cumulative production

of conventional natural gas (Qm ) for the Lower

48 States to be approximately 870 TCF. This is

a remarkably low estimate given cumulative production to date of about 631 TCF and proved reserves of about 169 TCF; * * if correct, it leaves

only 70 TCF remaining to be added to reserves

from the growth of known fields (calculated by

demonstrates that the availability of extensive geologic knowledge

does not guarantee agreement over resources present.

*Nehring acknowledged this problem to OTA in a recent telephone

conversation.

‘

2 Hubbert, op. cit.

* *As of the beginning of 1983. Numbers are approximate because

1982 production and reserve data have not been published.
4 5

USGS to be 172 TCF) and new field discoveries.

In other words, Hubbert’s assessment implies that

the precipitous declines of the early 1970’s in

Lower 48 proved reserves will resume again almost immediately, with subsequent drastic consequences for production rates within only a few

years.

In his 1980 assessment, Hubbert obtained five

separate estimates, using basically three approaches (table 9). In his first approach he derived

equations for the magnitudes and rates of change

of gas production and discoveries by noting some

simple boundary conditions for the production

cycle * and fitting a second order equation** to

these conditions. By further manipulating the

equation obtained by this exercise, Hubbert derived three separate but related methods of

estimating Q ~, two involving the curve of cumulative discoveries and one involving production rate as a function of cumulative production.

In his second approach Hubbert assumed that

the ratio of the discoveries of natural gas to those

of crude oil will tend to remain stable, allowing

the gas resource base to be calculated as a simple

function of the oil resource base.

The third approach involved extrapolating the

declining finding rate for gas out to the point

where exploratory drilling ceases and taking the

—.—

“Cumulative production Q is zero at the beginning of the cycle

and Q ~ at the end: the production rate ~Is zero when Q = O and

also when Q = Q ~ ).

Table 9.— Hubbert’s 1980 Estimates of Ultimately

Recoverable Gas Resources in the Lower 48

Method of estimation Q@ (TCF)

1. Extrapolating the plot of production

rate as a function of cumulative production . 810

2. Estimating the approach of cumulative

discoveries to Qm as time approaches co . . 871

3. Finding the equation of cumulative

discoveries versus time . . . . . . . . . . . . . . . . . . 840

4, Using oil resource estimate and

assuming stable gas/oil discovery ratio. . . 876-896

5. Fitting and extrapolating the

curve of discoveries per 108 feet

of exploratory drilling . . . . . . . . . . . . . . . . . 989

SOURCE Off Ice of Technology Assessment, based on M K Hubbert “Tech.

nlques of Production as Applied to the Product Ion of Oil and Gas, ”

I n 0(/ and Gas Supp/y Mode//rig, S I Gass (ed ), National Bureau of

Standards Special Publication 631, May 1982

area under the curve, as discussed in the earlier

section on historical approaches to resource estimation (see fig. 8).

Hubbert’s work has been the subject of numerous critical appraisals.23 This discussion will not

attempt to review the appraisals but will incorporate some of their key points.

Of Hubbert’s five estimates, the first three involve the assumption that the curves of declining production and proved reserves will be the

mirror image of the curves of the (increasing) first

portion of the resource development cycle. This

derives from Hubbert’s satisfaction with the “fit”

of the simple quadratic equation he uses to apcriticism associated with all historical approaches—that the future does not have to look

like the past, and more often than not doesn’t—

Hubbert never explores the possibility that he

could achieve an equal or better fit with a different

equation and thereby calculate a different Qm.

Critics have shown, for example, that the resource

base values obtained from fitting a curve to oil

production data are sensitive to the type of curve

used, and that Hubbert’s assumed curve is not the

best choice.” Although Hubbert’s curve for oil

discovery is more satisfactory, it maybe that the

less mature gas discovery curve is also flawed. *

The assumption of the fourth estimate, that the

ratio of gas discoveries to oil discoveries will remain stable, appears to be very weak. The great

majority (85 percent) of gas discoveries today are

not associated with oil, and it is the consensus of

many geologists that a large portion of the remaining gas resource lies below 15,000 ft in a physical

23 For examp]e, L, S, Ma Yer cites three: D. V. P. Harris, “Conventional Crude Oil Resources of the U. S.: Recent Estimates,

Methods for Estimation and Policy Consideration, ” &fateriafs and

Society 1, 1977; N. Uri, “A Reexamination of the Estimation of Undiscovered Oil Resources in the U.S., ” DOE/TM/ES /79-03, 1979,

EIA; L, Mayer, et al., “Modeling the Rates of Domestic Crude Oil

Discovery and Product ion,” report to the EIA, Princeton University, Department of Statistics, 1979. (In comment on J, J. Wiorkowski,

“Estimating Volumes of Remaining Fossil Fuel Resources: A Critical

Review, ” J. Am. Stat. Assoc., September 1981)

“E. g., J. J. Wiorkowski, 1981, “Estimating Volumes of Remaining Fossil Fuel Resources: A Critical Review, ” J. Am. Stat. Assoc.,

September 1981, vol. 76, No. 875,

*The reasoning here is that the oil discovery curve gives more

satisfactory results than the oil production curve because discovery

is more advanced in its overall cycle. The less advanced, or less

“mature, ” the curve, the less satisfactory will be the results.
4 6

environment hostile to the preservation of oil. A

method predicated on stable gas/oil ratios would

appear to guarantee an overly pessimistic gas resource base estimate.

In the last estimate, Hubbert fits an exponential curve to a historical plot of finding rate (the

ultimate volume of gas to be produced from fields

discovered by 108 ft of exploratory drilling) versus cumulative exploratory drilling, by requiring

the curve to pass through the last data point and

by requiring the area under the fitted curve to

equal the area under the historical data plot (see

fig. 8). This estimate has several serious problems.

First the curve does not fit the data because it virtually ignores the “form” of the data and concentrates instead on the last data point.25 Second, the

estimate is very sensitive to this last data point,

yet the magnitude of the point is the sum of a

value (reported new field wildcat discoveries) that

may vary with economic conditions* and with the

ZSH~rrlS, 197P, ~JJ. C]k ~ ● For example, a period of high-risk exploratory effort—responding

to economic conditions that favor this sort of activity—will tend

to yield high discovery rates, whereas one of lower risk effort responding to different conditions generally will yield lower rates. This

is important here because Hubbert’s analysis is dependent on the

finding rate being a function only of the physical resource base and

its state of depletion,

state of depletion of the resource base plus a second value (reserve growth after the initial reporting period) that is, at best, a gross approximation. * Third, as with the first three estimates,

Hubbert makes no attempt to explore the possibility that he could achieve a better “fit” with a

different curve. His choice of a negative exponential curve is an assertion, made several times but

unsupported by reasoning in his text.

An interesting observation about this last estimate is that despite the fact that the fitted curve

is well under the trend line of the last several units

of drilling—an ingredient for an overly conservative estimate—the estimate is considerably higher

than the four other estimates in table 9.

● The procedure used to estimate reserve growth utilizes the average growth rate over many years, However, the year-to-year historical growth rates have tended to be quite volatile, so the average

growth rate for a single year or single period of 10” ft of drilling

is at best a rough approximation. Furthermore, there are reasons

to suspect that the long-term trend of reserve growth may now be

turning downwards, causing a further error in an estimate assuming an unchanging trend.

RECONCILING THE DIFFERENT ESTIMATES

Which of these resource assessments are to be

believed? In approaching this question, OTA used

three criteria:

1.

2.

3.

Is there a consensus, or even a “central

tendency, ” in the scientific community?

How credible are the methods used by the

assessors, in the abstract and in actual performance?

What do the different assessments imply in

terms of geology and future discoveries? Are

these implications credible?

Is There A Consensus?

In OTA’s judgment, the range of opinion in the

scientific community about the size of the natural

gas resource is too wide to represent a significant

consensus. Not only are there the obvious divisions along the lines of the various estimates, or

simply between “optimistic” and “pessimistic, ”

there is also an important division between scientists who believe in a particular estimate or range

of estimates and those who do not believe that

the state of knowledge is adequate enough to allow any reliable estimate to be made. Furthermore, some scientists believe that those estimates

that invoke current technology and economic relationships—the great majority—are simply irrelevant, whether or not they are correct within the

constraints of these assumptions. These scientists

believe that both the inexorable advance of technology and rising prices that reflect resource scarcity will constantly push outwards the boundaries

of the recoverable resource base. As noted previously, the history of resource estimation in general tends to support this view; cycles of predic-
4 7

tions of scarcity followed by radical upward revisions in resource assessments appear to be common for nonrenewable resources (see box C). On

the other hand, the USGS oil and gas resource

estimates of the past decade and a half sustained

some very substantial downward revisions as

estimation procedures became more sophisticated.

Tables 10 and 11 summarize some of the key

arguments used by the optimists and pessimists

in explaining their positions on the probable size

of the gas resource base. Because each of the arguments has merit, it is obvious that an unambiguous answer to the question, “How large is the

U.S. gas resource base?” is not likely. Selection

of a “best” estimate is further confused by the

observation that some major disagreements exist

even among assessors who appear to have the

same general outlook (see box D), and some of

the more important disagreements occur in areas

where considerable geologic data exists to aid the

resource assessments (and where, consequently,

the most agreement might be expected).

Given what OTA would term a lack of consensus, is there at least a “central tendency?” What

Box C.—A Very Brief History of Petroleum Exploration

The history of petroleum exploration in general, and exploration for natural gas in particular, has

been one of continuous movement toward new discovery horizons and resulting reappraisals of resource

potential. The “movement” encompasses new geologic theories and “ideas,” new exploration and production technologies, and new geographic areas.

During the first half-century of exploration following Drake’s initial discovery in 1859, exploratory

drilling was essentially random drilling, drilling at oil seeps, or drilling in areas where previous strikes

had been made. Then a succession of geologic insights began to open up new horizons for exploration:

first, the understanding that anticlines, some with surface manifestations, could serve as traps for petroleum; then, the discovery that petroleum deposits could exist in traps on the flanks of salt domes;

next, the recognition of the petroleum potential of sand lenses and stratigraphic traps; and finally, the

insight that petroleum could exist in recoverable quantities underneath thrusting plates, leading to the

opening up of the Overthrust Belts to exploration and eventual large discoveries.

Another discovery “horizon” was the growing sophistication of the tools of the trade: the advent

of the gravity meter and magnetometer, allowing the locating of geologic anomalies that might signal

the existence of structural traps; the addition to the explorer’s tool kit of refractive and then reflective

seismology, which permitted the detailed mapping of geologic structures; the introduction of rotary drilling

and advanced drill bits that allowed deeper horizons to be explored; the growing use of fracturing technologies, which opened up another geologic horizon in petroleum-bearing rock of low permeability;

and the engineering triumphs of offshore drilling technologies.

At the same time, exploration and development moved into new regions, sometimes driven by the

new technologies (e.g., the continental shelves) or new ideas (e.g., into Texas after realization of the

importance of salt domes) and sometimes driven simply by the need for new supplies and dwindling

prospects in the mature regions. Thus, exploration began in the Appalachian region but moved inexorably into Ohio and Kansas, into California and the Mid-Continent Region, to the onshore Gulf of

Mexico, and spilled out into the Offshore, moved to the Overthrust Belt, and drove to deeper horizons

in the Anadarko.

This history of constant movement to new horizons provides grist for the mill of both the resource

optimists and the pessimists. The optimists focus on the seemingly continuous ability of explorationists

to find new geologic concepts and to develop new technologies that allow them to expand the petroleum

resource base over and over again. The pessimists focus on the questions: Just how long can this go

on? How many additional places are there to look? As noted earlier in the section on “Resource Base

Concepts,” this history and the ongoing controversy in the search for petroleum is a paradigm for the

development of many nonrenewable resources.

SOURCE: Dr John .%hanz, Senior Specialist in Energy Resources Policy, Congressional Research Service.
4 8

Table 10.— The Optimist’s View of Gas Resources Table 11 .—The Pessimist’s View of Gas Resources

●

●

●

●

●

●

●

Just a few short years ago nobody had heard about the

Overthrust Belt and the Tuscaloosa Trend; now

everybody has jumped in. The pessimists have always

been wrong about resource shortages.

Increased prices for gas and better exploration

techniques have opened up a huge new resource in

small fields. Past estimates of the number of small

fields relied on data from a time when a small field

was likely to be abandoned as a dry hole.

We haven’t been looking for natural gas for more than

a few decades, so a mature basin for oil—with little

prospects for significant new finds—isn’t necessarily

mature at all for gas. This is especially true because

the conditions that led to gas are often hostile to the

formation and preservation of oil, and thus the

presence of these conditions would have tended to

keep explorers away. A key example of this effect is

the deep gas resource.

A good part of the lower finding rates of the recent

past was due to the substantial increase in low-risk,

low-yield drilling. The lower rates therefore do not

necessarily imply “resource depletion. ”

Most resource estimates—including optimistic ones

such as those of USGS and PGC—represent only

snapshots in time, reflecting current economics and

technology. The resource base estimates will tend to

grow over time as prices rise and technology

advances.

The decline in proved reserves of the past decade,

interpreted by many as a sign of resource depletion,

actually represents merely a rational response to high

discount rates, that is, a reduction in inventory to the

minimum amount necessary to sustain production.

Recent price increases have opened up a large

potential for new reserves from the growth of older

fields. This new gas will come from closer spaced

drilling, the extension of fields to lower permeability

areas that were previously uneconomic, the lowering of

abandonment pressures, and well workovers.

SOURCE Office of Technology Assessment.

is an acceptable range of estimates for the size of

the recoverable resource base that excludes “unconventional gas”* and gas that cannot be exploited profitably at gas prices in the same range

as today’s and with technology that is well within

reach in the next few decades? OTA believes that

a substantial majority of scientists concerned

about the gas resource base would feel comfortable somewhere within * * a range that included

Nehring’s estimate as the extremely pessimistic

minimum and the PGC estimate as not quite the

● Gas from very tight formations, geopressurized zones, coal beds,

and Devonian shales. However, gas that arguably could be placed

in these categories but that is commonly produced today, would

be considered conventional.

* “Many would no doubt disagree strongly with values near one

extreme or the other, however.

●

●

●

●

●

●

We have drilled too many holes in the Lower 48 States and

tested too many ideas to believe there is much room for

brand new natural gas horizons.

If there’s so much gas right here in the Lower 48, why are

we testing the Iimits of hostile environments i n the Arctic

and continental slopes?

The geologists who make industry’s resource estimates

tend to be the most successful ones, those who have a

built-in bias toward optimism because of their experience.

We have already found most of the ‘(easy,” giant fields.

The future is in the smaller reservoirs, and there doesn’t

appear to be enough of these to provide the amount of

resources the optimists say is there.

The depletion effects apparent in exploratory drilling

finding rates are actually understated because the advance

of exploration technology, by increasing the success rate

of exploratory drilling, has tended to hide the onset of

depletion.

The higher resource estimates, when translated into the

number of fields of various sizes that must be discovered

to yield this much gas, look very shaky when compared

to the numbers of these fields that we have actually been

discovering lately.

SOURCE Office of Technology Assessment

maximum, but close to it, This range is about 280

to 915 TCF for the remaining conventional gas

resource (including proved reserves and the

growth of known fields) recoverable with readily foreseeable technology and given today’s

economics, for the Lower 48 States.

OTA believes that the minority who might like

the range extended would consist mainly of those

who believe that the upper end should be higher.

Furthermore, OTA suspects that a thorough review of the production implications of the lower

end of the range—as discussed in the next chapter—would tend to push many scientists away

from this end of the range. * It should be added,

however, that some of those who are considerably

less optimistic than PGC, and even USGS, are major oil and gas producers—e.g., Exxon*

are very familiar with most of the areas

supposed to supply the United States with

timistic” levels of new gas discoveries.

* —who

that are

the “op-

*As shown in chapter 5, a 280-TCF remaining resource implies

that the year 2000 production of Lower 48 conventional gas, recoverable with existing or foreseeable technology and at the current cost/price relationships, cannot be much greater than 4 TCF/yr.

**OTA has been told informally by Exxon geologists that Exxon’s most recent internal estimates of the U.S. gas resource base are

considerably below those of USGS and PGC. The major disagreements are with estimates for the Lower 48 onshore gas potential.
4 9

Box D.—Are the USGS and PGC Gas Resource Assessments Really Similar?

Two widely referenced gas resource assessments—those of the USGS and the PGC—have similar estimates for the ultimately recoverable gas in the Lower 48 (1,400 TCF and 1,542 TCF, respectively) and

are often used to illustrate what some feel is a wide consensus for an optimistic gas future. Are these

two assessments really so similar? The table below compares the regional assessments

gas from both groups, * based on the PGC reporting areas.

Onshore Offshore

PGC reporting area PGC USGS PGC USGS

A . . . . . . . . . . . . . . . . 41 11 16 24

B 13 21 30 3

c ::::::::’:::: :::::::.:: 3 6

D . . . . . . . . . 39 24

E&G . . . . . . . . . . . . . . . . . . . . 34 101 52 69

H . . . . . . . . . . . . . . 159 124

43

J-S . . . . . . . . . . . . . . . . . . . . . . . 34 33

L 16 19 18 7

Total** ::::::..:.:::::::::::::: 44 2 390 116 102

of undiscovered

The table shows some substantial disagreements about where the major undiscovered gas resources

lie, but it also shows that, on the average, the region-by-region assessments agree quite well,

Important areas where the two agencies differ are:

●

●

●

●

●

sets.

J-N–the mid-continent region (Kansas, Oklahoma, parts of Texas), where PGC is far more optimistic about deep gas.

E&G onshore—the gulf coast.

A—the Eastern Appalachian States.

B offshore—Mississippi, Alabama, and Florida, where PGC remains optimistic about gas in the

eastern Gulf of Mexico.

D—Arkansas, north Louisiana, and central Texas.

The average level of agreement can be checked by conducting a linear regression of the two data

This yields a correlation coefficient of 0.74, which is a good agreement for two resource assessments

conducted somewhat independently of each other.*** Also, removing the two worst disagreements—

the offshore gulf coast and mid-continent estimates—increases the correlation coefficient to 0.92, a high

value.

Consequently, the differences in no way “discredit” either of these assessments. The differences do

illustrate, however, the substantial disagreements that can exist between two groups considered optimistic,

and thus they illustrate the considerable uncertainty associated with these resource assessments.

● The PGC values exclude “Probable” resources, which include new pools in discovered fields. Strictly speaking, PGC defines these pools as

undiscovered; USGS does not, and includes them in its “inferred reserves” category.

**Excludes cumulative production, proved reserves, and growth of known fields,

● **The estimators have too much access to the same studies and estimates, and to each other, to allow a claim of strict independence between

the two assessments.

How Credible Are the Methods?

How credible the methods are is generally dif- based on historical, extrapolative approaches; in

ficult to determine because few resource assess- addition, USGS makes available to the public its

ments using geologic approaches reveal many open-file reports and data. OTA did not attempt

details of their assessment processes. Generally, to review the extensive USGS backup informamore details are available for the assessments tion because of time and budget constraints. His-
torical approaches have been reviewed in a number of reports,

26 and for the most part OTA chose

to use them instead of conducting a totally independent review.

In general, OTA is skeptical of historical approaches to resource assessment when they are

based on national data and when they are the sole

means of estimation. The substantial data problems associated with natural gas exploration (especially during those years when gas was valued

as little more than a byproduct of oil production),

the broad range of activity covered by any single

data series, and the distorting effects of Government controls are important sources of this skepticism.

The most important estimate based strictly on

a historical approach is Hubbert’s because he has

gained substantial credibility from his successful

predictions of declining U.S. oil production. As

discussed earlier in this chapter, OTA notes substantial problems with Hubbert’s approach and

believes that his extremely pessimistic estimate

(870 TCF) of ultimately recoverable conventional

gas is too low.

Of the assessments using geologic approaches,

only the assessments of USGS and PGC are reviewable in any sense because details of the others

are not public information. In OTA’s opinion,

both assessment processes are serious attempts to

wrestle with a most difficult problem. One problem with both assessments is the failure to include

the detailed assumptions behind, and implications

of, the assessment, thus precluding much opportunity for useful feedback from those outside the

assessment process. The USGS assessment may

also be hampered by lack of access to proprietary

industry data; PGC, on the other hand, apparently has access to excellent data but appears to ignore the insight that might be gained from analyses of discovery trends (i. e., the historic approach).

Are the Physical Implications of the

Assessments Plausible?

Most gas resource assessments do not provide

descriptions of either the direct physical implicaZt.FOr ~X~mp]e, Wiorkowski, OP. cit.

tions of their resource estimates (e. g., the number

and size of fields implied by the estimate) or, conversely, the initial physical model used to derive

the estimate. Nevertheless, some physical implications can be drawn directly from the estimates.

This is especially true when the estimates are separated into components: onshore and offshore

(quite common), deep and shallow (e.g., the PGC

assessment), and individual regions or even

smaller provinces (USGS divides the United States

into 137 separate provinces). Consequently, it is

clear that PGC believes that the deep resource below 15,000 ft represents a massive source; fully

39 percent of the onshore undiscovered resource

of the Lower 48 States is projected to be deep gas.

In a similar vein, USGS clearly appears to have

given up on the eastern Gulf of Mexico but has

great hope—as does PGC—for another “frontier”

area, the Western Overthrust Belt.

Rather than carrying out a detailed “translation” of each assessment, OTA chose to examine

two basic physical issues that appear to cut across

virtually all of the assessments. These issues, as

stated by Nehring,27 are:

Ž Does the assessment imply a substantial

break with past and recent discovery trends

and patterns?

● If the assessment does imply such a break,

what is the explanation for it? Is it credible?

A Break With Past Trends?*

The most obvious ties between past trends and

the magnitude of the resource base are the analyses performed in the “historic approaches” to

resource assessment. In general, these approaches

have given relatively pessimistic results when used

with U.S. gas production and exploration data.

For example, all four of the estimates using pure

data-tracking techniques (two by Hubbert, one

each by Wiorkowsky and Bromberg/Hartigan) in

table 6 are below the USGS estimate, with three

z TR Nehring, The DjSCoVery of Significant Oi] and Gas Fields in

the united States, op. cit.

*Readers interested in past trends in petroleum exploration may

also wish to read Exploration for Oil and Gas in the United States:

An Analysis of Trends and Opportunity, by John J, Schanz, Jr. and

Joseph P. Riva, Jr,, of the Congressional Research Service (CRS

report No. 82-138 S, Sept. 16, 1982).
..

of the four at least 400 TCF below. In addition,

the RAND estimate, which is at least partly dependent on past discovery trends, is nearly 500

TCF below the USGS estimates.

This series of pessimistic resource estimates

based on trend analysis, when coupled with the

very low rates of reserve additions in the Lower

48 States from 1968 to 1978 (average yearly AGA

reserve additions were 9.6 TCF v. average production of 20.6 TCF yr), represent a strong initial

argument that the more optimistic resource estimates do represent a break with past trends, while

the pessimistic estimates do not. However, as

noted in the discussion of historical approaches

to resource assessment, the available data used

to measure trends in exploratory success (or trends

in other factors that may be used to form judgments about the probable size of the resource

base) tend to measure multiple rather than single

processes; for example, measures of the success

of drilling for new fields are, in fact, measuring

a range of activities from the high-risk testing of

new geological ideas to the low-risk redrilling of

formerly uneconomic dry holes. Consequently,

none of these trends can be interpreted in an unambiguous manner. The discussions in chapter 5

about the factors that affect the various components of reserve additions give a sense of the complexity of individual trends and of the difficulties

in interpreting the trends.

51

Trends in the discovery of new fields appear

likely to be most closely associated with the remaining recoverable resource base; these trends

are examined in the following paragraphs.

Table 12 displays the returns to new field

wildcat drilling in the onshore Lower 48 States

from 1966 to 1981. The patterns displayed in the

table demand careful deciphering. The gas volumes found per successful gas new field wildcat

show a startling decline during the period, from

18.56 billion cubic feet (BCF) per well in 1966 to

1.85 BCF per well in 1979 (use of EIA data moderates this trend somewhat, but the EIA and AGA

data are not strictly comparable). This means that

the average field size found by a successful gas

wildcat declined by a factor of 10 during 1966-79.

Because the larger fields in a basin are generally found early in the discovery process, a sharply declining average field size is often interpreted

as a sign that the discovery cycle is winding down.

However, the data shown in the table are collected

from multiple basins, and during the time period

in question, the pattern of gas exploration may

have been influenced by increased gas prices and

other factors. For example, it is widely believed

that deliberate exploration for small gas targets

(e.g., in areas where past exploration identified

then uneconomic gas deposits) increased sharply

Table 12.– Returns to New Field Wildcat Drilling in the Onshore Lower 48 States, 1966-81 (BCF/well)

New field discoveries Percent of new field

Per new field Per new gasfield discovery wells

Year Per all NFWs discovery well discovery well that find gas

1966 ::: ., . ...: .’ 0.46 4.56 18.56 25

1967 . . . . . . . . . . . . . . . . 0.42 3.96 11.93 33

1968 . . . . . . . . . 0.24 2.66 10.25 27

1969 . . . . . . . . . . . . . . 0.24 2.66 7,47 36

1970 . . . 0,29 3.01 8.20 37

1971 . . . . . . 0.16 1.67 3.70 45

1972 . . . . . . . . . . . . . . . . . 0.24 2.11 4.46 47

1973 . . . . . . . . . . . 0.34 2.30 3.89 59

1974 ... . . . . . . . . . . . . 0,24 1.60 2.88 56

1975 . . . . . . . . . . 0,22 1.47 2.91 51

1976 . . . . . . . . . . 0.18 1.02 1.85 55

1977 . . . . . . 0.20 (.32)a

1.15 (1 .86) 2.23 (3,61) 52

1978 . . . . 0,17 (0.36) 1.07 (2.27) 1.96 (4,17) 55

1979 . . . . . . . . . . . . 0.20 (0.26) 1.07 (1 .40) 1,85 (2.48) 58

1980 . . . . . . . . . . . (0.27) (1 .37) (2.69) 51

1981 . (0.34) (1 .88) (3.95) 48

aAGA data (EIA data)

—

SOURCE R Nehr!ng ‘Problems in Natural Gas Reserve, Drilling, and Discovery Date, ” contractor report to the Off Ice of Technology Assessment, 1983
52

during this period. Such an increase in the willingness of explorationists to go after small targets

would tend to reduce field size averages even if

high-risk exploration for large fields maintained

a steady success record. Consequently, the decline

in average field size may not fairly represent the

actual condition of the resource base.

The record of returns to wildcat drilling per well

drilled tends to support this view. These returns

per well drilled have exhibited only a slight decline

since 1968; the success rate, which varies from a

low of 2.3 percent in 1968 to a high of 10.8 percent in 1979, essentially compensates for the declining field size. In other words, while each gas

wildcat well completed returned far less gas in

1979 than in 1966, the actual number of wildcat

wells drilled to find each trillion cubic feet of gas

did not increase very much during this period.

This relatively optimistic result should be tempered, however, by the observation that the percentage of wildcats aimed deliberately at gas targets probably increased during this period. Consequently, it is likely that the actual gas-directed

effort—as distinct from the total petroleumdirected effort—that was needed to find a unit of

gas probably did increase during the period.

Although the data in table 12 look more optimistic than might have been initially expected, the

history of natural gas development implies that,

in order to sustain successful levels of reserve additions for the long-term, efforts must be made

to open new geologic horizons and find the large

fields that are the cornerstone of reserve growth

in later years. Consequently, it is useful to examine the pattern of discovery of different-sized

fields.

The American Association of Petroleum Geologists (AAPG) publishes the primary public record

of the discovery of petroleum fields by size and

discovery year, and this record may be used to

examine patterns of discovery. The record must

be used cautiously, however, because AAPG appears to have undercounted the number of fields

discovered. * For example, from 1971 to 1975,

*Part of this problem may arise from simple disagreements over

field boundaries; the EIA data base, for example, treats the Hugoton

field as three separate large fields, whereas other analysts might count

it as one. Also, field reserve estimates are not consistent across data

bases.

AAPG reports only 49 gas discoveries of a size

greater than 60 BCF. In comparison, the RAND

data base reports 141 fields in this size range during the same time period.28 Consequently, the

AAPG data should be examined for trends rather

than absolute magnitude, and even the trends may

be skewed if undercounting and other problems

were not consistent over time.

Table 13 presents the historical record of new

gasfield discoveries by field size, for 1945-75, as

compiled by AAPG. * In parallel with the trends

shown in table 12, the percent of significant (size

class A through D) gasfields in all gas discoveries

decreased over the 30-year period, while the effort required to find a significant field increased

through the 1960’s but then declined to earlier

levels.

The data in the table can be used to examine

the discovery trends of larger fields. Figures 11

and 12 show trends in, respectively, the number

of fields discovered as a percentage of new field

wildcats drilled, and the number of fields

discovered per year. Figure 11 shows that the apparent effort (in wells drilled)** required to find

fields of size C or larger, B or larger, and A grew

sharply during the early 1950’s but then leveled

off between 1955 and 1975. However, these trends

would look considerably more pessimistic if “total

footage” rather than “wells drilled” were the

measure of effort. This is because the average

depth of new field wildcats grew steadily during

this period, from 4,007 ft in 1946 to 6,071 ft in

1975.

29

Figure 12 shows that, starting about 1950, the

number of moderate-to-large gasfields declined

steadily through 1975. These larger fields may be

particularly important for continued reserve additions because of the general belief that the larger

fields generate the majority of field growth (from

extensions, new pool discoveries, and revisions).

z9R. Nehrjng, pfob]erns in Natural Gas Reserve, Dn”lling, and Discovery Data, contractor report to OTA, 1983.

*The record stops in 1975 because AAPG classifies fields as gas

or oil fields only after the passage of 6 years past the discovery report.

* *“Apparent” because some of the wells were aimed deliberately

at small targets and should not be included in the “effort” involved

in finding large fields. As noted, however, there is no way to separate

data about these wells from the overall data.

“R. R. Johnston, “North American Drilling Activity in 1981,”

AAPG Bulletin, vol. 66/11, November 1982.
53

m

o

-

. . .

.

.

.

.

.

. .

. . .

. . ,,
54

Figure 11.— Number of Gasfields Discovered As a Percentage of New Field Wildcats Drilled,

u

al

=.—

.5

.4

by Field Size Grouping

Field sizes (BCF): A >

B

c

D

00

1 1 m

1946 1950 1955 1960 1965 1970 1974

SOURCE Off Ice of Technology Assessment, based on data from table 16 in R R Johnston, “North American Drllllng Activity in 1981 ,“ AAPG Bu//ef/n, VOI 66/11, November

1982

Figure 12. —Number of Gasfields Discovered per Year, by Field Size Grouping

1946 1950 1955 1960 1965 1970 1974

SOURCE Off Ice of Technology Assessment, based On Ma from table 16 In R R Johnston, “’North Amertcan Drltllnq Activity In 1981, AAPG f3u//ef/n VOI 66/11, November

1982
55

The impression gained from table 12 and figures

11 and 12—that finding rates for the small-tomoderate sized fields have held up very well and

even increased, but that rates of finding the larger

fields have declined somewhat over the past few

decades—is reinforced by an examination of Lower 48 gasfield discoveries of 1 TCF and larger.

Such discoveries were scattered throughout the

1916 through 1966 period, with particularly large

discoveries* in 1916 (Monroe, La., 9 TCF), 1918

(Hugoton, Kans./Tex./Okla., 36 TCF and panhandle, Tex., 31 TCF), 1921 (San Juan, N. Mex.,

18 TCF), 1928 (Jalmat, N. Mex., 6 TCF), 1934

(Katy, Tex., 7 TCF), 1936 (Carthage, Tex., 6

TCF), and 1952 (Puckett, Tex., 4 TCF).30 However, according to the 1977 International Petroleum Encyclopedia,31 no gasfields larger that 4

TCF were found between 1953 and 1967, and no

gasfields larger than 1 TCF were found between

1967 and 1975. * *

The trends in discovery up to the middle 1970’s,

although rendered somewhat ambiguous by the

nature of the data, appear to support two conclusions. First, they show that exploration trends

for gas have not nearly been as much a cause for

pessimism as have oil exploration trends; in short,

they do not show why the resource pessimists such

as Hubbert predict such a radical drop in new discoveries. The rate of discovery of significant fields

(fields of sizes A through D) did not experience

the kind of steep decline that would seem to be

a prerequisite for predicting—as the Hubbert resource estimate does—that undiscovered resources

now total only 100 TCF. Second, the trends indicate that the type of fields usually associated

with opening up major new horizons were not being discovered and that more and more of the new

fields appeared to be coming from further along

in the discovery cycle. The limited number of

● Some ot these fields— Hugoton, Panhandlef San Juan —are considered multlple fields by some analysts, one field by others, Also,

there ]s considerable varlatlc~n In reserve esttmates from one source

to another

‘ ‘Oil and [;as Resources Ilata System, Energy Information Admlrustrat]on; and J. hfcCaslm (ed ), lntemat~ona) ~efroleurn Enqrclopecfia, v()]. 10 (Tulsa, OLla I’etroleum Publishi ng Co , 1Q77)

“hlcCa51in, ,)p ci t

* *It is poss]ble, however, that further growth ot t]elds that were

IwIOWI the 1 TCF Ie\el In I Q77 could have m(~ved them [ntt, the

~re~ter than I TL F category in later >rear~

giant fields discovered in this period gives some

cause to question the relatively optimistic estimates of USGS and PGC.

As to recent trends, the recent upsurge in total

reserve additions has been the common centerpiece in arguments that the “resource optimists”

have been right all along. Questions are raised

about whether recent large discoveries in the deep

Anadarko Basin and in the Overthrust Belt signify

a reversal of the long-term, more pessimistic

trends.

In OTA’s opinion, responsibility for the reserve

additions of the past few years—and therefore the

implications for future reserve additions and

production—cannot be assigned to a particular

cause without a detailed investigation, at the level

of individual fields and entrepreneurs, of the precise nature of the increases. Such an investigation

would attempt to determine whether the new reserve additions represent a true turnaround in the

exploratory process or a one-time surge of reserve

development caused by the sudden movement

from the subeconomic into the economic range

of a limited inventory of known prospects and

an acceleration of the normal pace of field development. OTA has not seen any convincing analyses arguing one side or the other.

As for the Overthrust Belt and Anadarko, the

future of these areas is uncertain. The Overthrust

Belt did produce some very large new fields in the

late 1970’s (the Whitney Canyon/Carter Creek

and East Anschutz Ranch fields appear to have

resources greater than 1 TCF), and its potential

is substantial, However, despite continued searching, no new giant fields have been discovered in

the past few years. In the Anadarko, the recent

declines in prices for deep gas may have moved

some gas from “economic” to “subeconomic,”

although the earlier superheated market for this

gas and the resulting distortions in prices and production costs make it difficult to predict where

the economic/subeconomic boundary might lie

in the future. Also, recent engineering difficulties

and rapid pressure declines in some fields imply

that some overestimates may have been made in

calculating reserves and estimating resources.

In conclusion, in OTA’s opinion the gas

discovery trends of the past several decades, while
56

not supporting the most pessimistic of the recent

gas resource estimates, also do not support the

relatively optimistic estimates of PGC and, possibly, USGS.

Some Alternative Explanations

The (until recently) moderately pessimistic

discovery trends and optimistic resource base estimates can be reconciled by two possible arguments:

●

●

It is not the resource base but the market

distortions caused by Government regulations that have caused discovery trends to be

disappointing. Exploratory incentives have

been skewed toward low-risk, low-payoff gas

prospects.

The historical trends do represent the depletion of traditional sources of natural gas.

Now, however, improved technology and

higher prices will allow explorers to find large

quantities of gas from:

—small fields;

—reworking of older fields;

—new frontiers, including deep gas; and

—subtle stratigraphic traps.

The Causes of Past Trends

Is it the nature of the remaining resource base

that has been the primary influence on historical

declining trends in new field discoveries, or was

it instead the economic and regulatory environment that provided the controlling influence?

Does the relatively low rate of discovery of large

new gasfields during the last decade and a half

reflect resource depletion, or are these rates an

artifact of the erratic price and regulatory history

of natural gas? If gas resources are substantially

depleted, it appears unlikely that gas finding rates

and discoveries of large new fields will rebound

to levels that would sustain high production rates.

If the economic/regulatory history of gas is the

cause, then optimism about future production potential may be well founded, assuming that economic and regulatory conditions can be made favorable to the gas discovery process.

The basic argument that low finding rates for

new fields and other warning signals do not reflect

resource depletion centers around the idea that

the rigid price controls of the period before passage of the Natural Gas Policy Act of 1978

(NGPA) locked drilling into lower cost and risk

areas that do not coincide with where the major

gas potential resides. The “culprit” for this is said

to be the method used by the old Federal Power

Commission (FPC) to calculate allowable “area”

and “national” gas prices. FPC assumed that future exploratory and development costs would be

similar to past average costs, and by basing the

allowable price on this assumption, essentially

guaranteed that drilling would be confined to

areas where costs were expected to be low.

A past proponent of this view has been the

American Gas Association. AGA has conducted

a series of studies32 comparing total gas well completions to estimates of gas resource potential* in

the Outer Continental Shelf, Alaska, the shallow

Lower 48 area, and deep (below 15,000 ft) horizons. Their September 1979 analysis, which includes drilling data through 1977, concludes that

“the drilling data suggested that the decline in

proved reserves was not due to a depletion of gas

sources but rather to a lack of economic incentives for drilling under an artificially constrained,

regulated environment [emphasis added]. “33 This

conclusion was based on the poor correlation of

gas well completions to gas resource potential detected in the study** (see the first two circle charts

in fig. 13). However, a more recent (January 1981)

analysis added a comparison of gas well expenditures to gas resource potential (third circle chart

in fig. 13). Noticing a good correlation of expenditures to resource potential,*** AGA omitted the

earlier conclusion and attributed the imbalance

between drilling and potential to “the much lower

cost-per-well and cost-per-foot figures for the

shallow, Lower 48 wells.”34 The very high drillJZThe ]atest is ACA, “cas well Drilling Activity and Expenditures

in Relation to Potential Resources, ” Gas Energy Review, vol. 9,

No. 1, January 1981.

● The measure used for “Resource Potential” was PGC’s estimates

of potential supply.

“AGA, “Drilling Activity and Potential Gas Resources, ” Gas

Energy Review, vol. 7, No, 11, September 1979.

**Of course, an alternative reason for the poor correlation could

be that gas entrepreneurs do not agree with AGA’s view about where

the resource potential lies.

* **Except for Alaska, where lack of a transportation system blocks

gasfield development,

MAGA “Gas Well Drilling and Expenditures . .,” Op. cit.
57

Figure 13.—Gas Potential, Gas Well Completions, and Expenditures—1978

1,019 TCF 13,306 gas wells $4,978.9 million

Potential Gas well completions Gas well expenditures

NOTE Shallow and ‘deep refer to Lower 48 States onshore potential IS based on PGC’s estimates of the undiscovered gas resource

SOURCE Gas Wel I Drllllna Actlvitv and Ex Dendltures I n Relatlon to Potential Resource [n Gas Energy Rev/ew VOI 9, No 1 (Arlington Va Amer!can Gas Assocla -

t mn January 1981 I

ing costs and risks of the high gas potential frontier areas necessitate a very cautious attitude

toward drilling, whereas the lower costs in

developed onshore areas encourage closely spaced

development drilling and exploratory drilling for

small reservoirs and other marginal targets.

A corollary to the argument about the effects

of low allowable gas prices is used to explain why

the sharp price increases of the past several years

have not improved the rate of new field discoveries. According to this view, drilling priorities

will not immediately be corrected by rising prices

because the long period of controls has created

a large backlog of low-risk, previously marginal

exploration prospects that are now commercially viable. Until this backlog is reduced, the argument goes, exploratory drilling will stay away

from the high-risk, high-payoff wells that could

find the large fields35 that now only appear to be

scarce. Furthermore, because price increases expand the boundaries of the “economically recoverable” resource base and thus add to the inventory of low-risk prospects, it is claimed that the

trend toward low-risk, low-payoff drilling is likely

to continue if prices continue rising.36

‘sJensen Associates, Inc., “Early Effects of the Natural Gas Policy

Act of 1978 on U.S. Gas Supply, ” report to the Off Ice of Oil and

Natural Gas, U.S. DOE, April 1981,

“R, P. O’Neill, “Issues in Forecasting Conventional Oil and Gas

Production, “ in Oil and Gas Supply Modeling, National Bureau of

Standards Special Publication 631, May 1982.

High-risk, high-payoff drilling may be expected

to yield low success rates. Consequently, the

sharply improved success ratios of both total exploratory drilling and new field wildcat drilling

during the past decade and a half, shown in table

14 and figure 14, has been used to support the

thesis that drilling is skewed toward the low-risk

targets. The overall success rate of these drilling

categories may be affected by a variety of factors,

however, that cannot be separated out. For example, substantial progress in improving exploration techniques and computer technology during

this period undoubtedly acted to increase success

rates, but to an unknown degree. * Also, the success rate is automatically elevated by the decrease

in minimum acceptable field sizes and gas flow

rates associated with increased gas prices; small

fields and low-permeability reservoirs that in the

past would have been considered “dry” are now

being developed as producers. Therefore, it is

quite conceivable that an increase in overall success rates could be accompanied by an increase

in high-risk drilling if the other factors affecting

success rate were strong enough to overcome the

negative effects of the shift in risk.

In addition to arguments about the effects of

price controls, some analysts point out that

*The extensive investigation of the effects of new technology by

the National Petroleum Council in 1965 could find no credible quantitative measurement of these effects.
20

Table 14.—Oil and Gas Drilling Success Rates

(discoveries as a percentage of exploratory drilling effort)

Exploratory wells “Wildcats”

Year Completed Total Rate Completed Total Rate

1966 . . . . . . . . . . . . . . 1,894 10,313 18.40/o 635 6,158 10.3 ”/0

1967 . . . . . . . . . . . . . .

1968 . . . . . . . . . . . . . .

1969. . . . . . . . . . . . . .

1970 . . . . . . . . . . . . . .

1971 . . . . . . . . . . . . . .

1972. . . . . . . . . . . . . .

1973. . . . . . . . . . . . . .

1974. . . . . . . . . . . . . .

1975. . . . . . . . . . . . . .

1976. . . . . . . . . . . . . .

1977. . . . . . . . . . . . . .

1978. . . . . . . . . . . . . .

1979. . . . . . . . . . . . . .

1980. . . . . . . . . . . . . .

1981 ........, . . . . .

1982. . . . . . . . . . . . . .

1,518

1,440

1,700

1,271

1,088

1,285

1,519

2,009

2,143

2,449

2,686

2,728

3,024

3,574

4,585

4,847

8,878

8,879

9,701

7,693

6,922

7,539

7,466

8,619

9,214

9,234

9,961

10,677

10,484

11,916

15,168

16,470

17,1

16.2

17,5

16.5

15.7

17.0

20.3

23.3

23,3

26.5

27.0

25.6

28,8

30.0

30.2

29.4

544

442

535

493

436

566

701

805

876

986

1,004

983

1,162

5,271

5,205

5,956

5,069

4,463

5,086

4,989

5,652

1,340 7,034

1,423 8,052

1,400 7,912

SOURCE American Petroleum Institute, “Quarterly Review of Drilling Statistics”

Figure 14.— New Field Wildcat Success Rate, 1966-81

—

6,104

5,840

6,101

6,505

6,413

o

1966 1967 1968 1969 1970 1971 1972 1973 1974 1975

Year of reported discovery

10.3

8.5

9.0

9.7

9.7

11.1

14.1

14.2

14.4

16.9

16.5

15.1

18.1

19,0

17.7

17,7

—— .

1976 1977 1978 1979 1980 1981

NOTE Gas success rate data not available after 1975 because gasfields and oilfields are separated out only after a 6-year review by AAPG

SOURCE Office of Technology Assessment, based on data from American petroleum Institute, QUa~OW ROVleW of Drllhng Stat!st!cs
——-

59

maintenance of high levels of proved reserves in

relationship to production would not be compatible with good business practices. According to this

argument, high-interest rates made it sensible for

gas producers to reduce their standing inventory—i.e., proved reserves—by maximizing deliverability and reducing exploration. Consequently, from the drilling low point of 1971 to

1982, developmental drilling rose by a factor of

3.66 (18,929 wells drilled v. 69,330), whereas total

exploratory drilling rose by only a factor of 2.38

and new field wildcats rose by only 1.77.37 Carrying this argument further, the economic incentive to increase reserves will occur only when the

cost of reducing R/P ratios—of adding to the deliverability of current reserves—outweighs the

cost of adding new reserves.

Although the argument about the lack of an

economic incentive to increase reserves is a fair

one, it does not take into account the incentive

for exploration provided by a number of factors,

including the perception in the industry that the

rapid declines in reserve levels were dangerous and

should be halted if possible, the continued profitability of most larger gasfields even at low prices,

and the former inseparability of gas and oil exploration, which allowed gas discovery to benefit

from exploration incentives provided by oil.

The argument about the real cause of the downward trends of past decades is difficult to resolve

because the opposing sides are generally arguing

less about the data themselves than about their

interpretation. Both sides agree, for example, that

onshore gas exploration has become increasingly oriented to prospects with less “dry-hole” risk

but with smaller reservoirs with poorer producing characteristics. Those arguing for resource depletion believe, however, that this trend has occurred primarily because that is the nature of the

remaining resource base; those arguing for a more

optimistic view of resources argue that the trend

reflects a natural market response to early controlled prices, recent price increases, and high discount rates that favor production over inventory.

Undoubtedly, both arguments are valid to some

degree; the problem is in determining the relative

importance of each.

‘

-American Petroleum Institute, ‘Quarterly Review of Drilllng

Statistics. ”

Potential Major Sources of Additional Gas

Small Fields.—One basic argument revolves

around the question of whether or not a sizable

resource—large enough to support continued high

rates of production—lies in fields containing 60

BCF of gas or less. The source of the argument

lies in the shape of the field size distribution curve.

Historically, the cumulative number of gas and

oil fields are distributed according to size in a manner shown in figure 15. In this figure, the size

classes 1 through 20 (on the x axis) are scaled so

that the upper limit of size class 20 is one-half the

upper limit of 19, and so on. As shown in the figure, the cumulative number of fields increases

with decreasing size class as a geometric series,

down to about size class 13 (or class D in the

AAPG notation), and then rapidly levels off. At

least a portion of this “truncation,” or leveling-off,

of the field size distribution is undoubtedly due

to past economics; many small finds were too

small to be economically developed and consequently were reported as dry holes rather than

added to the historical record as a class D or E

field. Because pipeline gathering systems are required in order to develop gasfields no matter

what the field size, and also because the price (per

unit of energy) of gas has historically been lower

than that of oil, the minimum field size suitable

for development is larger—and thus the truncation described above is more severe—for gas than

for oil. The crux of the current argument is, simply, what will the shape of the field size distribution curve look like when the effects of higher gas

prices run their course? An important corollary

to this argument is, how expensive will it be to

discover and develop these small fields, and, consequently, how many of them can appropriately

be included in the recoverable gas resource base?

Proponents of the thesis that small fields represent a very sizable resource argue that the trend

observed for fields larger than size class D— i.e.,

a progressive increase in the number of fields discovered in each size class as one moves from the

larger field sizes to the smaller—will be continued

into the small field sizes below class D once these

fields are made the target of intensive exploratory

efforts. This argument maintains that the tailing-
60

Figure 15.— Size Distribution of Discovered Oil and Gas Fields in the Lower 48 States

—

20

—

19 18 17 16 15 14 12

bcf

AAAA >3000

AAA 1200-3000

AA 600-1200

A 300-600

150-300

60-150

D 6-60

E <6

11 10

Field SIze

8

Intervals

-

7

bcf

76,800-153,600

38,400- 76,800

19,200- 38,400

9,600- 14,200

4,880- 9,600

2,400- 4,800

1,200- 2,400

600- 1,200

3oo- 600

150- 300

75- 150

37.5

9,38- 18,75

4,69- 9.38

2.34- 4.69

1,17- 2.34

.59- 1.17

.29- .59

.15- .29

65432 1

off of the curve in figure 15 is almost entirely the — costs are higher, which would be expected if the

result of economics and that there are no geologic

reasons for the drop in the number of very small

fields. Scheunemeyer and Drew, 38 in examining

field size distributions in the Gulf of Mexico and

the Denver Basin and at three depth intervals in

the Permian Basin, show that the “truncation

point” of the field size distribution moves to larger

field sizes when exploration and development

“J. H. Scheunemeyer and L. J. Drew, “A Procedure to Estimate

the Parent Population of the Size of Oil and Gas Fields as Revealed

by a Study of Economic Truncation, ” Mathematical Geology, vol.

15, No. 1, 1983.

truncation were economically determined. Also,

they note that the point moved to smaller field

sizes after gas prices rose and the minimum profitable field size became smaller.

A straightforward argument against the “small

fields thesis” is that estimates of large resources

from small fields cannot be based on more than

an assumption or extrapolation—because no petroleum basin has experienced the intensity of

drilling that would be required to find the postulated number of small fields. This argument appears to be a powerful one, but it works equally
61

.—

well against those who might deny the possibility of large numbers of small fields. It probably

is not possible at this time to estimate credibly

the ultimate number of small gasfields remaining

to be discovered in the United States and the resources these fields represent.

A second argument that has been presented is

that, in some basins, the field size truncation does

not appear to be generated by economics and is

more likely to have been caused by geology—

the simple lack of sufficient small fields. For example, Nehring39 identifies subduction and delta

provinces, * that account for more than one-quarter of U.S. oil and gas resources, as an example

of basins where the number of fields in each size

category begins to drop at a size level considerably

above any historical field size minimum. Nehring argues that only a portion of U.S. provinces

act according to Scheunemeyer and Drew’s thesis

and that there are four distinct groupings of field

size distributions, ranging from one with a rapid

increase in the number of fields with decreasing

field size (similar to those discussed by Scheunemeyer and Drew), to one with a single peak at

about size class D, to one with little increase in

the number of fields at field sizes below A or B.

A third argument notes that it takes about 1,000

class E fields to equal three class A fields,40 and

that even a sharp increase in the number of small

fields discovered may not be of major significance

to the overall resource base. Figure 16 shows the

known field size distribution, as in figure 15, and

two projected distributions for the ultimately recoverable resource base—one that assumes

a doubling of the approximately 24,000 fields

known as of 1975, with most of the increase at

39R. Nehring, The Discovery of Significant Oil and Gas Fields in

the United States, R-2654 ~ l-USGS ‘DOE, RAND Corp., January

1981, pp, 78-94. Excursus, The Distribution of Petroleum Resources

by F]eld Size in the Geologic Provinces OF the United States,

● Subduction provinces are small, linear basins located along the

converging margins of plates. They account for about 11 percent

of U.S. oil and gas resources in the RAND assessment. The three

largest are the San Joaquin, Los Angeles, and Ventura provinces

on the west coast. Delta provinces are small-to-medium sized,

circular-shaped, and derived from ma]or continental drainage

centers. The one producing delta province In the United States is

the Mississippi Deltar which accounts for about 17 percent of U.S.

oil and gas resources in the RAND assessment,

‘“R. Nehring, Problems in Natural Gas Reserve, Drilling, and Discovery Data, op. cit.

the smaller sizes, and a second that assumes a

much larger increase at the smaller field sizes,

essentially by assuming that the truncation of the

number of fields at smaller sizes is entirely an effect of economics and that the actual number of

fields continues to increase logarithmically with

decreasing field size. * The first projection produces 48,000 fields, the second about 115,000. Of

critical importance is the difference in resources

between the two projections, all of which arises

from different assumptions about how the existing

truncation of small fields will “fill in” with future

discoveries; it is about 7 percent of the total

resource base represented by the second projection. Extrapolating to the gas resource base (and

assuming the “central tendency” range of 902 to

1,542 TCF of ultimately recoverable resources),

the assumption that the ultimate number of small

gasfields found will be much larger than indicated

by the historical field size distribution might lead

to an increase in OTA’s estimates of potential gas

resources of approximately 60 to 110 TCF.

A fourth argument notes that the small size of

the fields makes them only marginally economic

at best. For gasfields, especially, many of the

fields in the projected distributions may not be

economic at current and projected gas prices and

therefore may not belong in the recoverable resource base at this time. * * In partial support of

this argument, USGS studies the effect of gas price

and other economic variables on recoverable gas

resources in the Permian Basin indicate considerable sensitivity of the size of the remaining resource to these variables. Table 15 presents estimates of the amount of exploratory drilling that

could profitably be pursued and the gas resources

that would be discovered by this drilling as a function of wellhead price. If the model used by the

study is correct, the size of the recoverable resource in small fields is sharply sensitive to price

(also rate-of-return), although the sensitivity

declines at gas prices above $5 to $6 per MCF.

● The projected distribution is drawn by assuming that the number

of fields in each size interval smaller than 100 million BOE (0. ~ TCF)

is so-percent greater than the number of fields in the next larger

interval.

‘ *In other words, the}’ are subeconomic resources in the NlcKelvey

Box (fig 8).
6 2

Figure 16.— Known and Projected Size Distributions of Discovered Oil and Gas

Fields in the Lower 48 States

40,000

30,000

20,000

10,000

5,000

1,000

500

100

50

20

0

—

—

—

20 3 18 17 6 15 3 12 11

bcf

AAAA >3000

AAA 1200-3000

AA

A

D

E

8

600-1200

300-600

150-300

60-150

6-60

<6

Intervals

4

5

6

7

14

15

16

17

18

bcf

76,800-153,600

38,400- 76,800

19,200- 38,400

9,600- 14,200

4,880- 9,600

2,400- 4,800

1,200- 2,400

600- 1,200

300- 600

150- 300

75- 150

37.5-

1875-

938- 18.75

4.69- 9.38

2.34 4.69

1.17- 2.34

.59- 1.17

.29- .59

.15- .29

Field size

Table 15.—Potential Recoverable Gas Resources

From New Discoveries in the Permian Basin

(assumed 15 percent of return)

Wellhead price Exploration wells New discoveries

$/BOE ($/MMBtu)a

drilled (thousands) (TCF)

10 (1.50) . . . . . . . . . . 5 4.98

15 (2.40) . . . . . . . . . . 12 9.17

20 (3.20) . . . . . . . . . . 18 11.38

25 (4.00) . . . . . . . . . . 24 13.02

30 (4.80) . . . . . . . . . . 29 14.12

35 (5.60) . . . . . . . . . . 34 15.13

40 (6.40) . . . . . . . . . . 38 15.81

@OllarS per barrel of 011 equivalent (dollars per million Btu).

SOURCE Geological Survey Circular 828—Future Supply of Oil and Gas From

the Permian Basin of West Texas and Southeastern New Mexico, Interagency 011 and Gas Supply Project, 1980

New Gas From Old Fields.—Over the lifetime

of a field, from initial discovery to depletion, estimates of the field’s ultimately recoverable resources generally increase with time as normal development probes the full extent of the field and

as improved technology and rising prices bring

subeconomic portions of the field into the economically recoverable range. * Although the effects of improved technology and prices have long

been acknowledged as critical for increasing oil

● Reserve estimates in some fields will decrease with time. Small

fields are generally considered to be more susceptible than large fields

to such reserve “shrinkage. ”
6 3

recovery, gas recovery rates have long been considered to be very high under most conditions and

thus somewhat insensitive to price and technology.* Consequently, increases in reserve estimates

from known gasfields were generally considered

to be primarily an effect of the normal process

of exploring for new pools and enlarging the

proved area of known pools. This view is now

being challenged, as reserve additions are being

credited to lowering of the abandonment pressure

of depleting reservoirs, to extension of field

boundaries into areas of low permeability, to well

stimulations and well reworking, and to infill drilling to well spacings lower than the old norm of

640-acre spacing (see box E). For example, from

1969 to 1979, ultimate recovery in the HugotonPanhandle field (discovered around 1920) in Kansas, Oklahoma, and Texas Railroad Commission

District 10 increased from 71.0 to 84.0 TCF, * * and

ultimate recovery in the Blanco-Basin fields

(discovered from 1927 to 1950) in the San Juan

● However, the r~te of recovery is extremely sensitive to these factors, as is the economic threshold of development for a field.

● ● This field is not considered a single field by all analysts, nor

are its reserve levels completely agreed on. As noted previously,

these are not uncommon problems, especially with large fields.

Basin increased from 15.2 to 21.7 TCF.41 Although

growth rates of known fields have varied considerably across different geographic areas, these

substantial increases in known recovery from

quite old fields are well beyond what might have

been predicted by the historic data on growth of

old fields.

Industry opinion about the importance of “new

gas from old fields” is quite varied. One reason

for this variation of opinion is the anecdotal

nature of much of the available evidence and the

very mixed experiences of different companies.

For example, one source reports claims of 40-percent increases in proved reserves with infill

drilling,” while another, based on interviews with

14 major production and pipeline companies, reports that infill drilling has “not provided the large

reserve additions needed to reverse the long-term

decline in proved reserves, ” and that “relatively

small reserve additions were believed to have been

provided by extension of the economic life of pro411bid.

‘Zpersona] communication, William Fisher, University of Texas

at Austin, Feb. 9, 1982.

●

●

●

●

Box E.—Sources of “New Gas From Old Fields”

Lowering of abandonment pressure. —Wells are abandoned when operating and maintenance costs

are not balanced by sufficient revenues from gas sales. Because gas-flow rates can generally be associated

with wellhead pressures, an “abandonment pressure” can be specified for a given gas price. When

gas prices rise, the abandonment pressure is lowered and total recovery efficiency of the reservoir

is increased.

Infill drilling. —The original premise of requirements for wide-well spacing was that gas reservoirs

were sufficiently homogeneous so that very high-recovery efficiencies could be obtained with only

a few wells, except in fields that had low permeability. More recently, it has been recognized that

many reservoirs are heterogeneous in character and are compartmentalized, i.e., composed of relatively small, discontinuous interlaid pockets of gas-bearing rock. Drilling at higher density can intercept pockets that would otherwise not have been drained at traditional wide spacing.

Fracturing and acidizing. —These well-stimulation technologies, which have wider application with

increased gas prices, are used to speed gas flows and can add to resources by allowing completion

of wells in low-permeability sands that otherwise would have been considered as “dry.” They do this

by allowing a higher recovery during the limited life of the well (at low-flow rates, the well may not

last long enough to allow full recovery) and by opening up new “pay zones” too small to be economically

developed by a new well.

Well workovers. —Marginal wells may also be abandoned because of water encroachment, physical

aging of well equipment, and accumulation of sand in the well bore. At higher gas prices, well workovers

to correct these problems become possible.
64

ducing reservoirs (by lowering abandonment pressures) .“43

Unfortunately, it is difficult to translate this

anecdotal evidence into credible estimates of past

increases in recoverable resources available from

this “new gas” effect. No collected set of data

separates out this effect because the associated

changes in reserve estimates are combined with

the growth caused by normal development in the

“revisions” and “extensions” data now published

by EIA. Also, as discussed in chapter 5, the pace

of “normal” development has quickened with rising prices and improved seismic technology, preventing any attempt to measure the effect as the

difference between current and historical rates of

field growth.

Attempts have been made to measure future

growth of older fields that might be caused by

higher prices. For example, a recent report has

claimed that an increase in the price of “old

gas’’—gas controlled to prices well below marketclearing levels—could make an additional 52 TCF

available: 27 TCF from lower abandonment pressures, 18 TCF from additional infill drilling, and

7 TCF from a combination of fracturing and other

well-stimulation treatments, well workovers, and

other measures. 44 This estimate is, to our knowledge, the highest of any released to date.

A major controversy surrounding this and

other studies involves the extent to which the “additional” resources may already have been added

to reserves or else may be developed at current

prices (and, consequently, may already be a part

of the “economic” portion of the recoverable

resource base).

New Frontiers, Including Deep Areas.—Even

though recent exploratory drilling in the frontier

areas has had mixed success and several severe

disappointments, considerable areas of untested

or inadequately tested sedimentary rock remain

that may hold considerable potential. Even extreme pessimists view areas such as the deepwater

Gulf of Mexico, the Anadarko Basin, and the

“Jensen Associates, Inc., “Early Effects of the Natural Gas Policy

Act ,, op. cit.

“C. S, Matthews, Increase in United States “Old Gas” Reserves

Due to Deregulation, Shell Oil Co., April 1983.

Western Overthrust Belt as having considerable

potential. However, it is also inarguably true that

areas such as the Gulf of Alaska, eastern Gulf of

Mexico, the Southeast Georgia Embayment, and

the Baltimore Canyon have been expensive failures

45 thus far. Unfortunately, it is not easy to

document the opinions of the major oil companies—who traditionally are leaders in frontier exploration—because few details of their most recent resource assessments are available to the public. It is clear, however, that some of the majors,

notably Exxon and Shell, are pessimistic about the

overall Lower 48 potential and the Lower 48 onshore frontier areas. Given the speculative nature

of these resources, the range of credible estimates

of frontier undiscovered gas must be considered

quite wide.

An important part of the controversy over the

resource potential of frontier areas involves the

economic viability of the potential resources

rather than their physical presence. For example,

much of the intense deep-drilling activity of the

early 1980’s in basins such as the Anadarko appears to have been a direct response to the very

high prices for deep gas (as much as three times

the market-clearing price) resulting from the pricecontrolled market. Prices for deep gas and other

categories of gas entitled to special incentive pricing under NGPA have now dropped sharply, and

drilling activity has dropped sharply as well. Consequently, some analysts question whether these

expensive resources still belong in the economically recoverable resource base. Similar questions

have arisen over some of the gas under the deep

waters of the continental slope, now included in

the USGS assessment and others.

The appropriate placement of these resources

inside or outside of the recoverable resource base

is complicated by several factors. First, uncertainty about the precise geologic conditions of these

resources combined with the recent rapid fluctuations in drilling costs create substantial uncertainty

about the cost of producing the resources using

today’s technology. Second, the present hesitancy

of the industry to drill for these resources may

not necessarily reflect the resources’ lack of longterm economic viability but rather the current lack

45R. Nehring, “The Discovery of .,., ” op. cit.
65

of gas demand and regulatory uncertainties about

decontrol, Third, uncertainty is added by ambiguities in the common definitions of “recoverable

resource base, ” some of which, e.g., allow the

possibility of technological improvements that

are in line with trends prevailing at the time of

the assessment (this is USGS’s boundary condition). This greatly complicates the evaluation of

resources whose production may involve technological difficulties. Because of these factors, in

OTA’s opinion the boundary between economic

and subeconomic, and consequently the magnitude of the recoverable resource base, is not well

defined for the frontier resources.

Stratigraphic Traps.—Over the cycle of gas exploration, structural traps have tended to be the

most favored drilling prospects. As possibilities

for finding new large structures have declined,

many explorers have shifted their strategy toward

locating subtle stratigraphic traps, i.e., potential reservoirs whose main trapping mechanism

is a gradation of the reservoir rock into layers of

rock of low permeability laid down by the sedimentation process. Resource optimists expect to

find large amounts of resources in these traps,

There are two major arguments against such

expectations. First, there have been significant past

efforts aimed at finding stratigraphic traps, especially in the Anadarko, Permian, Denver, and

Powder River basins. ” Second, it is argued: 1)

that very large stratigraphic gasfields are unlikely to have remained undiscovered in the explored

basins of the Lower 48 States because of the fields’

large areal extent and the very high density of

drilling in these basins, and 2) that most of the

stratigraphic traps remaining to be discovered will

be small. Nehring47 also cites geologic arguments

against the possibility y of finding many large new

stratigraphic traps, including the vulnerability of

such traps to degradation or dissipation and Nehring’s contention that the presence of multiple

structural trapping possibilities in basins outside

of the stable interior provinces makes it unlikely

that many stratigraphic traps will exist outside of

these provinces, the source of most past discoveries.

‘61bld ,T1bld

These are strong but not conclusive arguments.

New efforts to locate stratigraphic traps can use

seismic exploratory techniques not available to

the earlier efforts. It is possible, though speculative, that several sizable traps that were “invisible” to earlier techniques could now be located.

Similarly, arguments about drilling density are

valid but must be tempered by the depth limitations of much of this earlier drilling and the

clustering of such drilling around areas considered

prospective by earlier standards.

Even if the arguments against finding large

stratigraphic traps are correct, there remains

significant uncertainty about the number of

smaller fields that might exist and the actual

potential for finding and exploiting these fields—

the same uncertainty that affects assessment of the

resource potential of small fields in general. Key

factors affecting the potential for producing significant quantities of gas from these fields include

gas prices and reductions in the costs of effective

exploration techniques.

Conclusions

Based on the previous discussion, OTA accepts

the possibility that discovery trends may have

been sufficiently distorted by past regulatory and

economic conditions and that sufficient resource

possibilities exist in small fields, growth of old

fields, and other sources to allow us to accept the

estimates of PGC as possible, but very optimistic--a reasonable upper bound to the probable

magnitude of the conventional gas resource base.

On the other hand, we consider the extremely pessimistic estimate of Hubbert to be unlikely, and

to a lesser extent we are also skeptical of the

RAND estimate. Both come very close to the analogy of “running into a brick wall. ” Looking ahead

to chapter 5, we can see that the Hubbert estimate

implies a “conventional gas” production rate of

about 3 or 4 TCF in 2000, an astoundingly low

value. The RAND estimate implies that there will

beat best only a handful of new exploration plays

in the Lower 48, that these will be only moderate

in size (2 to 10 TCF), and that there will be no

really large “surprises” left; we believe this is possible, although quite pessimistic. However, the

RAND assessment appears to have underestimated the potential for reserve growth in known
66

fields, and it apparently has excluded some gas

in low-permeability reservoirs that is currently

economically recoverable. Therefore, we consider

a credible lower bound to be somewhat higher

than the RAND estimate.

In conclusion, our best guess—and we chose

this word carefully—is that a reasonable range for

the magnitude of remaining conventional natural

gas resources, recoverable under technological

and economic conditions not far-removed from

today’s, * is about 400 to 900 TCF as of the end

of 1982. This is not really a very wide range, given

● Including gas in low-permeability reservoirs that otherwise

sat tsfies the condit I ons. This recognizes the ambiguous boundary

between “conventi[~nal” and ‘unconventional” gas in such reserv{>irs,

the basic uncertainty associated with resource assessment, but it is a wide range with respect to

future production potential. The two ends of the

range have very different implications about how

difficult it is going to be to continue to replenish

our current inventory of gas reserves over the next

decade or two, and they have profound implications about what the role of natural gas in our

energy economy will be in 2000. OTA believes

that if the lower end is correct, reserve additions

will fall off drastically within a few years, with

production rates dropping in response. On the

other hand, the upper range implies the potential for a very positive future for conventional gas

production during this century. The next chapter

explores these production issues in greater detail.
Chapter 5

Gas Production Potential
Chapter 5

Gas Production Potential

—.. .—

There are a variety of alternative approaches

to estimating the future gas production potential

of the United States, including the use of complex computer programs using econometric, process engineering, or system dynamics approaches

to model separately the gas exploration, development, and production processes. Although during the course of this study OTA examined several complex models in detail, we have chosen to

use four relatively simple techniques to project

future production potential. This approach reflects the high costs of using the complex models

and some doubts we entertain about the expected

accuracy of these models as forecasting tools.

These doubts do not necessarily extend to the usefulness of the models as policy analysis tools;

often, these models offer the valuable ability to

test alternative policies under carefully controlled

conditions. Some of the major natural gas supply models will be discussed in a background

document to this technical memorandum.

Of the four approaches used by OTA to project the mid- to long-term (1990 and beyond) production potential for natural gas in the Lower 48

States, three focus specifically on the potential for

continued additions to U.S. proved reserves. The

addition of new reserves to the U.S. gas system

is the primary determinant of future gas availability. The importance of new reserves can be illustrated quite simply by drawing the production

that would likely result from the failure to add

to reserve levels and reliance instead on current

proved reserves as the sole “inventory” for production to draw on (see fig. 17). Assuming a constant reserves-to-production (R/P) ratio of 8.0,

beginning in 1984, production would immediately begin to drop

2 trillion cubic

century. *

with shocking rapidity to about

feet (TCF) by the end of the

‘Conceivably, the initial reduction in production could be slowed

by drilling additional development wells, effectively lowering the

R ‘P ratio. The end result of this strategy would be, however, an

even more rapid production collapse occurring a few years later than

that shown in figure 17.

Of the three approaches focusing on continued

additions to U. S, proved reserves, the first projects future reserves by examining historical trends

in all components of reserve additions (new field

discoveries, extensions, new pool discoveries, and

revisions), examining the underlying causes of the

trends, and extrapolating into the future based on

OTA’s expectations of future conditions. In this

extrapolation, we have drawn heavily on the insights gained in our examination of gas resource

base assessments. The second approach projects

only new field discoveries and then applies a

“growth factor” to these discoveries based on

historical experience with the growth of new fields

and OTA’s judgment about how the growth rate

may have changed. The third approach is based

on a geologist’s* region-by-region examination

of available gas resources and past exploratory

success. In all three cases, production rates are

*Joseph P, Riva, Jr., Congressional Research Service

Figure 17.— Natural Gas Production From 1981

m ■

1982

Lower 48 Proved Reserves

.

.

1985

R/P = 8.0 beginning in 1984

.

1990

Year

SOURCE Off Ice of Technology Assessment

1995 2000

69
70

calculated from reserve data by projecting future

levels of the R/P ratio.

The fourth approach borrows a method used

by M. King Hubbert in 1956, tying future production directly to available resources by drawing freeform plots of the complete natural gas production cycle in such a manner that the cumulative production conforms to existing resource base

estimates—in this case, to the estimates of Hubbert, the U.S. Geological Survey (USGS), and the

Potential Gas Committee (PGC).

In each of the four approaches, ranges of production potential are estimated based on alternative assumptions about the magnitude of the resource base, efficiency of the exploratory process,

and other factors.

OTA’s use of four approaches, and alternative

assumptions within the approaches, reflects our

skepticism of our own and others’ ability to project future gas production rates with any precision. A “most likely” or “best” projection was

deliberately avoided because we believe that such

a projection, beyond 5 years or so into the future,

would be futile. Our purpose in this section is to

illustrate the plausible range of possible future

production rates and the general effects on production estimates of different interpretations of

the causes of past trends and different assumptions about future conditions. The first approach

is our slight favorite, but only because its level

of disaggregation forces the analyst to deal more

explicitl y with the underlying causes of past

events. This approach is discussed in the greatest

detail.

At the end of the chapter, a variety of gas production forecasts by public agencies, private companies, and institutions are presented and discussed.

APPROACH NUMBER I—PROJECTING TRENDS IN THE

INDIVIDUAL COMPONENTS OF RESERVE ADDITIONS

The first approach separately projects trends Factors Affecting New Field Discoveries

in reserve additions from new field discoveries, The rate of annual additions to reserves from new pool discoveries and extensions, and revisions. new field discoveries depends on a variety of factors, but most importantly on:

New Field Discoveries

The discovery of gasfields represents the single

most important force necessary for building a sustainable natural gas supply because a new gasfield

not only adds to current reserves but also provides a source of considerably larger additions to

future reserves through field growth after the

discovery year. Reserve additions attributable to

extensions and new pool discoveries and, to an

extent, to revisions, are all, in fact, the inevitable ●

consequence of previous new field discoveries.

Therefore, if new field discovery rates increase or

decrease, then at some point in the near future,

reserve additions from extensions and new pool

discoveries will almost certainly increase or decrease in a like manner.

The undiscovered resource base. —Th e

physical nature of the resource base—including the amount of resources remaining to be

found, the distribution of field sizes, the locations of fields, the distribution of types of

geological traps (more or less difficult to pinpoint with available exploration techniques),

and other physical attributes— is considered

by some to be the single most important determinant of future new field discoveries.

Exploration technology.—The rapid advance

of exploration technology, e.g., computeraided seismic technology, affects drilling success rates and, consequently, overall discovery rates. Also, technological improvements

have opened up to commercial exploitation

some areas whose complex geology had pre-
71

—

●

●

●

●

viously prevented acceptable success rates.

Consequently, these improvements have expanded the recoverable resource base. Development of the Western Overthrust Belt is

an important example of this effect.

Drilling and production technology.—Improvements in production technology}? create

an expanding recoverable resource base and,

in turn, an increase in targets for the drill.

For example, massive hydraulic fracturing

technologies allow exploitation of fields in

sands of low permeability that previously

would have been subeconomic. Improvements in offshore drilling technology allow

exploitation of gasfields in deeper and more

hostile waters.

Current and perceived future gas prices and

other economic variables. — Such variables

affect the propensity to drill and determine

where to draw the line between a producible well and a dry hole. In some cases, the

higher prices allow the use of well-stimulat ion techniques that would otherwise be too

expensive, allowing successful production to

be achieved from a well that would otherwise have had too low a flow rate. Additionally, the minimum acceptable reservoir size

for production has grown smaller. The relative prices of gas and oil are important also

because these will determine whether drilling will be preferential y aimed at targets

where gas or oil are more likely to be found.

Schedules, financial terms, and other aspects

of leasing. —These also determine the number

of attractive targets available for exploratory

act iv i t y.

Industry willingness to take risks.—All of the

above factors and others play a role in determining the propensity of the exploration segment of the industry to assume the risks of

wildcat drilling in unproved areas where

much of the gas resource potential is thought

to exist. Because this type of drilling often

involves hostile environments and large capital requirements, much of this drilling is the

domain of the major integrated oil companies

and the large independents. Consequently,

those factors that strongly affect the cash

flow, capital availability, and economic incentives for this group of companies are particularly likely to affect the industry’s propensity for risk-taking.

● Historic prices and exploratory experience. —There always exists an inventory of

new field prospects known to explorers

through past exploratory activities but undrilled or (in the case of “dry holes” ) uncompleted because of economic conditions or the

availability of more promising prospects else-

,

where. The key determinants of the size and

character of this ink’enter]’ are past exploratory experience and price profiles. The nature

of the inventory is, in turn, an important determinant of new field discovery rates in the

short-term, especially during the period following a change in price levels or regulatory

controls.

Historical Variation of New Field Discoveries

During the 14 years of American Gas Association (AGA) data availability,* the annual additions of new field discoveries in the Lower 48

States have remained fairly steady, if somewhat

cyclic, varying between a high of 2.9 TCF and

a low of 1.3 TCF. (See fig. 18, which also shows

the Energy Information Administration (EIA) data

for 1977 to 1981. ) Since 1967, the last year in

which AGA estimated that total reserve additions

exceeded product ion, the average of new field

discoveries has been 2.0 TCF. Similarly, nonassociated new field discoveries have been equally

steady, with a 14-year average of 1.7 TCF. Con--

sequently, new field discoveries played a surprisingly small direct role in annual reserve additions

during this period; * * they averaged less than 20

percent of all annual additions from new discoveries and extensions and never exceeded 25 percent in any year.

Although the reserve additions reported as new

field discoveries remained steady during this

period, the size distribution of the fields discovered did not. As shown earlier in table 12, the

average size of new gasfields became considerably

smaller (reported year-of-discovery reserves of

*.4ctuall\’, ACA has compiled reser~’e add]t][)n~ data since 1Q47,

but on]}’ began separate}’ estimating new tield dl~co~’erles In 1 Q07

‘‘Clearl} the} d]d not pla}’ a small Inci]rect role since man} of

the neti p~)~)l disc[lveries and extens]<lns in this pericd repre~ented

de~’elopment (It the [lelds d]w(lvered earl ]er In the period
72

—— -- - -.— .

Figure 18.–Additions to Lower 48 Natural Gas Proved Reserves: New Field Wildcat Discoveries, 1966-81 (BCF)

0

1966 1967 1968 1969 1970 1971 1972 1973

— ———

1974 1975 ‘ 1976 1977 1978 1979 1980 198 1

Reporting year

SOURCES: Office of Technology Assessment, based on data from Energy Information Administration, U S. ~hde C L Natural Gas, ar?d Natural Gas Liquids Reserves-1967

Armua/ Rt?port, DOE/ElA4216 (61), August 1982 and American Petroleum Institute, American Gas Association, and Canadian Petroleum Association, Reserves

of Crude Oil, PJatura/ Gas Liquids, and Natural Gas in the United States and Carrada as of >ecem w 3” 1979, VOI 34, June 1980

1.85 billion cubic feet (BCF) per successful new

field wildcat in 1979 v. 18.56 BCF per successful

new field wildcat in 1966). Furthermore, the lower

average did not imply only a reduction in discoveries of giant fields; although this did occur,

another change involved a very large increase in

the number of very small class E fields* brought

into production.

Because of the smaller size of newly discovered

fields, a steady expansion of successful exploratory wells was required just to maintain the rather

low annual discovery rate of the period. For example, completions of new field (gas) wildcats in

the onshore Lower 48 increased from 126 in 1968

to 671 in 1979. Because of the substantial improvements in success rates (see fig. 13) for all new field

wildcat drilling (from 8.5 percent in 1968 to 19.0

percent in 1980), however, actual drilling rates did

not have to increase in proportion to the rate of

completion. From a low of 4,463 wildcat wells in

1971, drilling reached 6,413 wells in 1979 and

8,052 in 1981.

The more recent (1977 to 1981) EIA new field

discovery data fig. 18) show considerable yearto-year variation with no apparent trend and are

made even more difficult to interpret because of

the break with the AGA data series. However,

the EIA estimates of new field discoveries were

higher during 4 of the 5 years of record than any

AGA-recorded discovery rate from 1966 to 1979.

Of interest is the source of these discoveries. Although areas like the Western Overthrust Belt and

deep Anadarko Basin have been in the forefront

of media coverage, most new field discoveries

continued to come from more traditional gasproducing areas -- onshore and offshore (Gulf of

Mexico) Louisiana and Texas. For example, during both 1980 and “1981 these two States provided

two-thirds of the total magnitude of reserve

additions from new field discoveries in the

Lower 48. 

*Class E fields contain less than 6 billion cubic teet of recoverable

gas.

2U. S. Crude Oil, hat ural Gas, and Natural Gas Liquids Reserves,

1980 and 1981, EIA Annual Reports, DOE/EIA-021680 and 81, OCtober 1981 and AuHuL.t 1982.
73

Implications

The following key issues pertaining to new field

discoveries remain essentially unresolved:

Ž Can the 1968-79 trend in new field discoveries—essentially a steady cycling around an

average of 2 TCF/yr or so—be continued

well into the future? If optimists about the

gas resource potential of small fields are correct, a continuing strong exploratory drilling effort should be able to maintain this level

for a number of years. If the pessimists about

small fields—and about the remaining resource base in general—are correct, reserve

additions from new field discoveries might

drop within a few years.

● Do the higher EIA estimates of 1977-81 new

field discoveries represent an actual increase,

or are they the result of the change in reporting methodology? Does the EIA methodology place more of a newly discovered field’s

ultimate reserves into the first-year reserve

estimate, leaving less room for secondary (extension and new pool wildcat) discoveries?

If the EIA values represent a true increase in

new field discovery rates, the sustainability

of a high rate (perhaps 3.5 TCF/yr) of new

field discoveries would seem to depend either

on the availability of new giant fields or on

extremely high rates of exploratory drilling

and the availability of massive numbers of

small fields, supported by either or both

strong price incentives and continued improvements in exploration technologies (especially in terms of lowering the cost of

detailed geological surveys).

The comparison of the three overlapping years

of EIA and AGA data in figure 18 is tantalizing

because the difference between the two data sets

is considerably smaller in 1979 than in 1977 and

1978, and the EIA methodology changed in 1979.

Some analysts have chosen to use AGA data until either 1978 or 1979, and EIA data thereafter,

assuming that the two series are essentially continuous. However, the coincidence between the

1979 EIA and AGA estimates for new field discoveries may be an accident; the two data sets

differ considerably for all of the other reserve addition categories in 1979.

The failure to resolve the above issues implies

that a credible range for future new field discovery

rates would be quite wide. Although defining the

range is a matter for subjective judgment, OTA

would put the range at about 1.5 to 3.5 TCF/yr

for the next 10 to 15 years, assuming that exploratory drilling remains active for the period. *

The range for the next 2 or 3 years should be narrower, however, perhaps 2.0 to 3.5 or 2.5 to 3.5

TCF/yr. The reasoning for these judgments is as

follows:

●

●

●

The high end of the range for the immediate

future is based on the distribution of new

field sizes. Because the current high discovery

rate has not depended on discovering giant

fields—notoriously erratic occurrences—but

on employing a very large number of exploration teams to discover many medium-sized

and small fields, the physical ability of the

system to maintain its recent new field discovery rates should logically be quite high

unless the gas “bubble’ ’-and the current

slump in drilling and all other exploratory

activity—continues.

To obtain the lower end of the 10- to 15-year

range, we assumed that the 1970’s AGA data

more accurately reflect the likely future and

that continuing resource depletion will lead

to poorer prospects and a slump from the

average of 2.0 TCF/yr during that period.

Also, it was assumed that the major reasons

for the higher EIA values are methodological

and do not reflect an actual increase over

discovery rates reported by AGA. Consequently, the 1.5 TCF/yr reflects AGA conventions and probable followup field growth.

The discovery levels actually recorded by

EIA would be expected to be higher than this

value, but the reserve growth caused by extensions and new pool tests would then be

lower than would be predicted by pre-EIA

historical experience.

The higher end of the lo-year range assumes

that the EIA data accurately reflect a major

upward shift in the finding rate (volume of

● Drilling is now in a substantial slump. The ranges of reserve additions discussed here would be unrealisticall y high if the current

“bubble” in gas deliverability y and the related difficulties in marketing

new gas were to continue,
74

gas discovered per unit of exploratory activity). Additionally, it is assumed that continued improvements in exploration and production technologies allow further increases

in finding rates and/or that exploratory drilling rates are increased. This end of the range

is alined with a large resource base.

Extensions and New Pool Discoveries

As already noted, a new field is generally not

sufficiently defined in its year of discovery to

allow the “new field discoveries” portion of reported reserve additions to represent all or most

of the actual recoverable resource in that field.

In the years following discovery, additional exploratory wells are drilled to delineate the full extent of the resources present in the field. Wells

that probe the boundaries of reservoirs or fields

in order to establish their productive area are

called extension wells or extension tests. Wells that

search for additional reservoirs within already

discovered fields are called new pool tests or new

pool wildcats. The reserve additions from extension wells and new pool wildcats represent the

results of a secondary or followup discovery process for new fields.

Factors That Affect Extensions

and New Pool Discoveries

As with new field discoveries, the major determinants of extensions and new pool discoveries

are the magnitude and nature of the “target” (in

this case, not the undiscovered recoverable resource base, but only that portion of the remaining resource associated with discovered fields), the

technology available to find the gas, and the nature of the incentives to drill:

● The target. —The “resource base” for extensions and new pool discoveries is the inventory of discovered but incompletely delineated fields. Limited data from the late 1960’s

and 1970’s indicate that the major part of new

field growth has occurred within the first 5

years after discovery. Consequently, unless

incentives for gasfield development are

lacking, * the magnitude of extensions and

*The current gas “bubble” provides a disincentive for field

development.

●

new pool discoveries should be strongly and

positively tied to recent new field discoveries.

Additionally, measures that increase current

new field discoveries should soon lead to increases in extensions and new pool discoveries as the new fields are further developed.

Aside from the total gas volume represented by the “target,” that is, the inventory

of discovered fields, the geological characteristics of the fields will also play an important role in determining future extensions and

new pool discoveries. For example, older

fields that were incompletely developed because a substantial portion of their in-ground

resource was subeconomic* at the time of discovery are now good targets for new exploratory efforts. The size and complexity of

newly discovered fields will partially determine the relationship between the initial yearof-discovery reported reserves and the later

extensions and new pool discoveries that

signify further development of the fields.

Because the discovery wells of smaller, less

complex fields can generally “prove” a high

percentage of their total resource, these fields

may offer less opportunity for this later development than was the case with the generally large, complex fields of earlier decades.

Technology. —The same technological factors that affect new field discoveries affect

extensions and new pool discoveries. Computer-assisted seismic technology is considered especially important in allowing extension wells and new pool tests to be drilled

with high success rates. Fracturing technologies, by opening up previously uneconomic

reservoir margins and tight reservoirs in

already discovered fields, expand the target

resource available.

Advancements in exploratory technology

have other, varied effects, however. For example, advanced seismic techniques, by offering a highly accurate picture of the potential of new fields shortly after discovery, may

encourage a larger proportion of the ultimate

recoverable gas to be drilled and “proved”

in the initial year-of-discovery, leaving less

room for followup discoveries. Advanced

● Because of the small size or low permeability of the reservoirs

or the low quality of the gas.
—

75

seismic techniques also may help compress

the remaining field delineation into a shorter

span of time, leading to increases over expected levels in extensions and new pool

discoveries* for a few years after discovery

of the field, followed by a later decrease in

expected levels of these reserve additions.

Historical Variation of Extensions

and New Pool Discoveries

Figure 19 and table 16 illustrate the variation

of extensions and new pool discoveries** in the

Lower 48 States from 1966 to 1981. Extensions

● That is, increases over the discovery rates projected by using

historical data.

● *As noted previously, new pool discoveries are reported as “new

reservoir discoveries in old fields” in the AGA and EIA reserve

reports.

have consistently played the major role in total

reserve additions. After declining in the mid to

late 1960’s, they remained stable around 6,000

BCF/yr from 1969 to 1976 and began to move upwards thereafter. As with the other categories of

reserve additions, the shift to EIA data complicates an interpretation of the past few years. According to that data, however, extensions by

themselves produced reserve additions of 10 TCF

in 1981, equaling or surpassing total reserve additions in most years of the 1970’s.

Some of the underlying causes of these trends

may be understood by examining the trends in

extensions of individual PGC reporting areas.3 Extensions tend to be concentrated in only a few of

~From R. Nehring, “Problems in Natural Gas Reserve, Drilling, — and Discovery Data, ” contractor report to OTA, 1983.

Figure 19. —Additions to Lower 48 Natural Gas Proved Reserves: Extensions

and New Pool Discoveries, 1966-81 (BCF)

14.000 I

I

12,000

11,000

10,000

9,000

8,000

7,000

6,000

5,000

4,000

3,000

2,000

1,000

n

1-

U

1970 1975

Year

AGA data EIA data

1980

SOURCE Office of Technology Assessment
76

Table 16.—Additions to Lower 48 Natural Gas

Proved Reserves: Extensions and New Pool

Discoveries 1966-81 (BCF)

New pool

Year Extensions discoveries Total

1966 . ....8,767 3,110 11,877

1967 . ....9,472 2,420 11,892

1968 . ....7,037 1,426 8,463

1969 . . . . . 5,800 2,043 7,843

1970 . ....6,146 3,363 9,509

1971 . ....6,375 3,361 9,736

1972 . ....6,154 3,096 9,250

1973 . ....5,931 1,970 7,901

1974 . ....5,693 1,952 7,645

1975 . ....5,926 1,649 7,575

1976 . . . . . 5,337 1,994 7,331

1977 . . . . . 6,569 (8,056)’ 2,144 (3,301) 8,713 (1 1,357)

1978 . . . . . 6,720 (9,582) 1,964 (4,277) 8,684 (13,859)

1979 . . . . . 7,112 (8,949) 1,690 (2,566) 8,802 (1 1,515)

1980 . . . . . (9,046) (2,577) (11,623)

1981 . . . . . (10,485) (2,994) (13,429)

‘The values in p’renrfleses are from EIA data; all other values are AGA rese~e

data.

SOURCE. Energy Information Administration, U.S. Crude 0//, Natural Gas, and

Natura/ Gas Liquids Reserves— 1991 Annua/ Report, DO13EIA4216 (61),

August 1962; and American Petroleum Institute, American Gas Association, and Canadian Petroleum Association, Resewes of Crude 0//,

~atura/ Gas Liqu/ds, and Natural Gas in the United States and Canada

as of December 31, 1979, vol. 34, June 1960

these areas. Before 1968, field growth (primarily

in relatively deep fields) in the Permian Basin provided a major fraction of total U.S. extensions—e.g., 43 percent in 1966. A sharp decline

in Permian Basin reserve growth in 1968 was the

primary reason for the general decline in extensions at the same time. The increase in extensions

nationwide, beginning in 1977, resulted primarily from increases in:

●

●

●

●

Western Overthrust Belt development;

development of the deep Anadarko Basin;

tight gas sand development in northeast

Texas, Arkansas, and Louisiana; and

Texas gulf coast development, including offshore fields, the South” Texas Lobo Trend,

and tight sands in the Austin Chalk.

Implications

Although the shift in data collection from AGA

to EIA complicates interpretation, the sum of extensions and new pool discoveries has apparently been increasing from about 1976 to the present.

In the AGA data, however, the increase only takes

these “followup” discoveries back toward the

levels achieved during the brief surge in new pool

discoveries that occurred in the early 1970’s. The

EIA data show a considerably higher level of “followup” discoveries at about the levels that AGA

estimated for 1966 and 1967.

In order to understand the recent variations in

extensions and new pool discoveries, it is generally

necessary to track the new field discoveries that

serve as the “inventory” for the secondary exploration process. There is no obvious trend in

the national new field discovery pattern (fig. 18)

that would explain the recent higher level of secondary discoveries; AGA new field discovery data

in the period immediately before this apparent

surge in secondary discoveries show no similar

increase. Consequently, in order to understand

fully the causes of the recent surge, it probably

is necessary to undertake a detailed examination

of data at the level of individual fields. This is

beyond the scope of OTA’s study. However, some

reasonable hypotheses can be fashioned based on

the available data.

One possible explanation for the recent increases in extensions and new pool discoveries is

that the increment over “normal” levels represents

the delayed development of fields discovered earlier but not developed for economic reasons. The

dip in new pool discoveries from about 1973-76

(fig. 19), which occurred despite an earlier period

of steady new field discoveries that normally

should have maintained steady levels of extensions

and new pool discoveries, supports this explanation.

Some field-specific data also support a “delayed

development” cause for part of the increases. For

example, recent extensions in the Austin Chalk

fields in southeast Texas appear to be tied to old

fields that were marginally economic when discovered and had never undergone major development before recent price increases encouraged a

reexamination. Because these fields were not

“new,” recent discoveries were probably recorded

as extensions and new pool discoveries, even

though there was little in the way of previously

recorded new field discovery “inventory” to trace

as the statistical cause of these secondary discoveries.

Similarly, another of the areas providing a substantial fraction of the increased extensions—the

Western Overthrust Belt—probably also followed
77

a delayed pattern of development. In this area,

there was little incentive to delineate immediately the first new fields discovered because there was

no means to transport the gas. Consequently, a

substantial inventory of new fields could have

built up until a point was reached where it became

clear that the area contained sufficient reserves

to justify a pipeline. Attaining this level of reserves

would have introduced an incentive for field delineation, and secondary exploration would have

then proceeded to cause a surge in extensions.

An additional cause of the recent higher recorded levels of secondary discoveries could be

an acceleration in the pace of field-size delineation and development. Such an acceleration

would result in the field size growth that in the

past might have been spread out over a 60-year

span being compressed into a shorter time period,

with higher levels of annual reserve additions during this shorter period. Accelerated field size

growth would be an expected consequence of

higher gas prices, although the recent problems

of reduced gas demand would tend to have the

reverse effect, that of slowing down the pace of

growth.

To summarize, two possible causes for recent

increases in extensions and new pool discoveries

are an accelerated field development pace and the

delayed development of earlier new field discoveries whose development was (at least in part) initially uneconomic. If these are indeed the primary

causes of the increases, this has important implications for future reserve additions. First, the faster

pace of development means that fewer opportunities for field growth will be available in the later

years of development; this should tend to decrease

future reserve additions unless the rate of new field

discoveries increases. Second, unless additional

opportunities for growth from older fields are

available, this source of “inventory” for extensions

and new pool discoveries is unlikely to allow continuation of the currently high-reported levels of

reserve additions. Although continuing technological advances and future gas price increases

could offer some potential for sustaining reserve

additions from older fields, the actual potential

for reserve additions from this source is controversial. * In any case, most of any additional

reserve growth from older fields seems likely to

be attributed to infill drilling and other causes that

will be reported as positive revisions rather than

as extensions and new pool discoveries.

Recent and future discoveries of new fields still

provide the primary source of inventory for future

extensions and new pool discoveries. Consequently, future reserve additions from extensions and

new pools depend heavily on the meaning of the

sharply higher levels of new field discoveries

reported during 4 of the past 5 years by EIA. As

discussed in the “New Fields” section, OTA suspects that part of the reason why EIA’s compilation of new field discoveries is substantially

greater in magnitude than the levels shown by

AGA is that the EIA data captures some of the

reserves that AGA would have reported as second-year extensions, new pool discoveries, or

positive revisions. If this is correct, the “growth

factor” that should be applied to EIA’s new field

discovery data to account for field growth after

the year of discovery will be smaller than the

growth factor applicable to AGA data. For this

reason, we do not believe that continuation of

high levels of extensions and new pool discoveries

is probable under current conditions.

Aside from the effects of the change in reporting, there are other reasons to believe that future

levels of extensions and new pool discoveries may

drop, First, much of the field growth in the past

has come from the giant fields that took years to

develop. A large percentage of recent new field

discoveries, however, are small, class E (less than

6 BCF of recoverable gas) fields that will require

little additional exploratory drilling past the initial wildcat. Second, the suspected acceleration

in the pace of field development implies that some

of the development that might in the past have

taken place in the second year (and that would

have been reported as extensions and new pool

discoveries) now takes place in the first and will

be reported as part of the “new field discoveries”

reserve additions. Finally, the high- capital requirements for developing new fields in hostile

environments—an increasing part of the remaining resource—demand a more thorough initial

‘As discussed in ch. J “New G,IS From old Fit’]ds.

., 1. — -J : Q - q -. — >
78 — —

estimate of reserves, possibly leading to lower

(statistical) growth later on.

To conclude, OTA does not believe it is likely

that recent reserve additions from extensions and

new pool discoveries of 12 to 14 TCF/yr will be

sustained in the future even if the gas “bubble”

ends and its negative effects on drilling cease. Instead, we project a range of 6 to 11 TCF/yr as

an average over the next 10 to 15 years, except

that for 1983-85 we project a range of 8 to 12

TCF/yr. The sole possibility of a higher long-term

rate of reserve additions from this source lies with

the discovery of several new, complex, super giant

gasfields with large growth potentials; however,

this possibility appears low.

Revisions

Revisions indicate changes in the volume of

proved reserves that result from new information

gained by drilling and production experience and

corrections made to earlier estimates during the

reporting year.

The AGA and DOE/EIA reporting of revisions

is not identical because EIA has a separate category of “adjustments and corrections” that includes adjustments for changes in data samples,

corrections of reporting errors, inclusion of late

responses, and other factors. Theoretically,

AGA’s revisions should be equivalent to the sum

of EIA’s revisions, adjustments, and corrections.

However, the data-gathering and analysis methods used by the two surveys are radically different, and their reserve and reserve addition estimates in the 3 years of overlap do not show good

agreement. Consequently, they are not equivalent, although in displaying historical trends AGA

revisions will be compared to EIA revisions plus

adjustments and corrections.

Factors Affecting Revisions

Generally, revisions occur because of uncertainty associated with estimating the extent of the

underground reservoir rock within a trap, the porosity and permeability of that rock, water saturation, pressure, and other physical reservoir characteristics that affect the cumulative volume of

production over the life of the reservoir. Revisions

tend to be a “catchall” category of reserve additions and deletions, and the many sources of revisions are difficult to separate out of the data.

These sources include:

1.

2.

3.

4.

5.

6.

7.

new knowledge gained by normal development drilling and production experience

(e.g., changes in reservoir pressure-decline

trends that indicate that earlier estimates

were incorrect);

numerical errors in the original compilation

of reserve estimates;

discoveries for which reporting had been

delayed;

development drilling on a closer spacing that

“discovers” new reserves; *

changes in production economics that lower

or raise the abandonment pressure of a reservoir or that allow or prevent the use of wellstimulation techniques that increase recovery

efficiency;

knowledge gained from extension tests that

indicate a decrease in the estimated proved

area of a reservoir or field (an increase would

be recorded as an extension); and

miscellaneous statistical corrections and adjustments to the data.

Sources 2, 3, and 7 are considered “Adjustments

and Corrections” by EIA and are reported separately.

Historical Variation of Revisions

From 1966 to 1981, net revisions were easily

the most volatile of any of the four types of reserve additions. In the data reported by AGA for

the contiguous 48 States, revisions varied from

i-6,256 BCF in 1967 to –3,546 BCF in 1973. In

the EIA data for the same area, revisions plus

adjustments and corrections varied from – 2,911

BCF in 1977 to +4,346 BCF in 1981. Consequently, the year-to-year changes in revisions were the

primary determinant of the year-to-year changes

in gross reserve additions during the past 16 years.

As shown in figure 20, a series of substantial posi-

‘New reserves “discovered ‘ by a devel{}pment we]] w[luld be

recorded as a revision ii the gas is located in a poc Let within the

established boundaries of a reservc~ir yet is phy~icall>’ isolated tr(~m

the reservoir’s main clralnage sy~tern and WOLI1(I not otherwiw be

prOcluceL1.
79

———— —

Figure 20.— Additions to Lower 48 Natural Gas Proved Reserves: Revisions As Reported,a 1966-81 (BCF)

7,000

6,000 —

5,000 —

4,000 —

3,000 —

2,000 —

1,000 “

o ~

-1,000 —

-2,000 —

-3.000 —

-4.000

—

—

1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981

AGA data Year EIA data

I

aNOTE EIA plots for rewslons t adjustments and corrections

SOURCES Off Ice of Technology Assessment based on data from Energy Information Admlnlstratlon U S Crude 0//, Natura/ Gas and Nafura/ Gas LIquK/s Reserves– 1981

Annua/ Reporf, DO EIEIA-0216 (81) August 1982 and American Petroleum Institute Amertcan Gas Assoclatton, and Canadian Petroleum Assoclatlon, Reserves

o f Crude 0// PJatura/ Gas L (quids and Natural Gas /n fhe Um fed States and Canada as o f December 31, 1979 VOI 34, June 1980

tive revisions in the mid-1960’s changed to net

negative revisions in almost every year in the

1970’s, particularly in the onshore contiguous 48

States. As discussed later, understanding the role

of these revisions is important in interpreting reserve changes during this period.

The largest negative revisions in the 1970’s were

reported in onshore south Louisiana and Texas

Railroad Commission Districts 1, 2, 3, 4, and 6.

Together, they contributed a total of over 30 TCF

and proved to be remarkably persistent, continuing throughout the 1970’s in both the AGA and

EIA data. They were concentrated in older fields

that had been producing for one to three decades

before the revisions began.

The negative revisions in these six areas appear

to be causally related to a situation that encouraged optimism in reserve calculations. During the

1930’s, 1940’s, and 1950’s, exploration for natural

gas in and adjacent to the gulf coast was highly

successful. As a result, much more gas was discovered than could be produced, given the small

size of the national natural gas market at the time.

The transmission companies, having contracted

for reserves with a productive capacity substantially exceeding what they could market, developed a system for prorating production among

operators on a basis of remaining reserves (i. e.,

the larger an operator’s reserves, the more gas the

transmission companies would buy). This created

a strong incentive for the operators to provide the

most optimistic estimates of reserves they could

justify. By 1970, following years of increasing production and gradual depletion, the operators were

beginning to realize that reserves were overstated.
8 0

The size, timing, and geographic distribution of

the reported negative revisions that followed

depended primarily on when each major operating

company recognized the problem and how they

decided to revise their estimates downward,

choosing to take them all at once or spreading

them out over several years.4

Implications

An argument can be made that the historical

record, erratic as it seems, supports the idea of

generally positive revisions in the long-term. This

is based on the view that the large but localized

negative revisions of the 1970’s appear to have

far more positive. 5 For example, if the gulf coast

revisions were subtracted from the total Lower

48 revisions, as shown in figure 21, the “amended

revisions” would appear to support a projection

of positive future revisions. On the other hand,

an examination of the sources of revisions indicates that extreme caution should be used in forecasting the direction of future revisions.

Of the seven sources of revisions listed previously, the second and seventh are essentially random. The others either will always yield positive

revisions, will always yield negative revisions, or

may have a bias in one direction or the other. The

first source, drilling and production experience,

ended. The trends in revisions for

side the source area for the negative

—.. ..—

‘Ibid,

Figure 21.—Additions to Lower 48

the areas out- would be random if there were no incentives to

revisions seem be either pessimistic or optimistic in reserve

5T. J. Woods, “On Natural Gas Trends, ” Gas Research Institute,

1982; “R. Nehring, contractor report to OTA, op. cit.

Natural Gas Proved Reserves: Revisions As Amended,a 1966-81 (BCF)

7,000 ]

6,000 —

5,000 —

4,000 —

3,000 —

2,000 –

1,000 —

o —

-1,000 —

-2,000 —

-3,000 —

1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981

AGA data Year EIA data

aNoTE: EIA ~lOt~ a~~ for revi~i~ns + adjustments and corrections.

SOURCE Off Ice of Technology Assessment
81

calculations. However, the requirement to raise

capital for field development or to meet minimum

reserve requirements for a new pipeline are powerful incentives for optimistic reserve estimates. A

tendency toward optimistic estimates would result

in mostly negative revisions from drilling and production experience. The large negative revisions

of the 1970’s in the gulf coast and adjacent provinces appear to have resulted from just such a

tendency.

The fifth source, changes in production economics, also could be random in that gas prices

could rise faster (yielding positive revisions) or

slower (negative revisions) than the costs of

operating fields and enhancing production. Although rigid price controls or the competition of

low-priced alternative fuels could conceivably

lead to negative revisions from this source, it

seems more likely that most such revisions would

be positive, especially if gas becomes scarcer. In

support of this argument, the growth in reserves

attributed to well reworking, infill drilling, and

lowered abandonment pressures—growth that

would be reported as positive revisions—is seen

by some analysts as an extremely important component of future reserve additions (see ch. 4, section on “New Gas From Old Fields”).

Of the remaining sources of revisions, the third

and fourth will always yield positive revisions,

and the sixth always will yield negative revisions. *

The confusing mix of “positive,” “negative,”

and “random” sources of revision make it extremely difficult to predict how revisions will

behave in the future. Also, revisions data do not

indicate which previous years’ data are being

revised. Consequently, it is difficult to know the

causes of past revisions—a necessary prerequisite

for intelligent forecasting. For these reasons, some

analysts disregard revisions entirely in their trend

analyses and implicitly assume they will not be

a significant component of future reserve additions.

A reasonable range of average yearly revisions

for the next 10 to 15 years appears to be O to 2

‘The sixth, knowledge gained from extension tests, yields only

negative revlslons because an increase in reserves caused by this

~ource would be reported as an extension

TCF/yr, with the positive tendency based on

OTA’s belief that there may be some significant

potential from the growth of older fields due to

lowered abandonment pressures, infill drilling,

and the like.

Reserves= to= Production Ratio

Because the reserves-to-production ratio (R/P)

measures the rate at which gas is produced from

discovered reservoirs, it represents the analytical

link between projections of new discoveries and

forecasts of gas production.

Factors Affecting R/P

At the level of the individual production firm,

the selection of a production rate—and, consequently, the selection of the R/P—represents an

economic tradeoff between the cost of drilling additional wells and installing additional gas-gathering and processing facilities (i. e., the cost of increasing production), on the one hand, and the

cost of holding reserves in the ground, on the

other, Consequently, factors such as exploration

and development costs, present and expected future gas prices, and interest rates all affect the

R/P. For example, increases in current prices will

theoretically lead to faster production, while expectations of real increases in future prices can

cause production to be delayed.6

In oil production, it is well known that too fast

a production rate—too low an R/ P—can cause

a premature decline in production and a loss of

potentially recoverable reserves. For example, in

a reservoir whose pressure is supplied mainly by

water that displaces the oil as it is produced (a

“water-drive” reservoir), an overly rapid rate of

production can cause the encroaching water to

flow around less-permeable sections of the reservoir, leaving behind the oil in these sections.

When the water reaches the well, the added costs

of water separation and disposal can cause premature abandonment.7 

‘Douglas Bohl and Michael Toman, “Understanding Nonrenewable Resource Supply Behavior, ” Sciertre, VO]. 219, Feb. 25, 1983.

“I>. A. StocLil (cd.}, Our lndustrj Petroleum (London: British

Petroleum Co. ltd., 1977).
82

Because gas flows more easily than oil, there

is far more leeway in gas production, and production rates frequently can vary over a wide

range. There are, however, the same kinds of

physical limits to gas production as to oil production, Although some loss of ultimately recoverable

gas from the well may be acceptable to the producer in exchange for a more rapid payback (from

the higher flow rate), the potential for large losses

will serve to limit flow rates.

Aside from the obvious economic factors and

physical limitations to avoid resource loss, several

other factors affect R/P:

●

●

Technology. —The major technology affecting R/P may be rock-fracturing methods.

The use of massive hydraulic fracturing and

other fracturing techniques can open up lowpermeability rock and cause marginal wells

with low-flow rates to become rapid producers. The availability of sophisticated seismic

exploratory techniques has reduced overall

drilling costs—enhancing the incentive to

drill additional wells to expand production—by increasing the success ratio; it also

has helped improve the placement of successful wells to maximize production.

Geology. —The rate of gas flow is directly dependent on the permeability of the gas reservoir formation and on its pressure and

thickness. Although fracturing can partly

compensate for low permeability, wells in

tight gas formations generally produce much

more slowly than do wells in more permeable

rock because the fractures do not reach all

of the tight reservoir rock. Similarly, gas in

deep over-pressure formations will for short

periods of time produce far more rapidly

than in shallow, low-pressure formations;*

in fact, the high pressures in such formations

have caused severe technical problems in

fields such as the Fletcher Field in southwestern Oklahoma, where wells and drilling

equipment have been destroyed by failure to

control the enormous pressures built up deep

—

● However, once the “propping effect” of the gas under pressure

is removed by partial production, the permeability of the reservoir

may be reduced to “tight-gas” levels, and productions will slow.

underground. 8 Also, field size distributions

may affect R/P because smaller fields, which

will be of increasing importance in future

reserve additions, may be produced faster

than large, complex fields.

Field Maturity. —Early in a field’s lifetime,

R/Ps are typically very high because the major focus is on reserve delineation rather than

development; during this period, pipeline and

gas-processing capacity may be nonexistent

or minimal and markets may be undeveloped. As pipeline capacity is added and sales

contracts signed, the R/P will decrease rapidly. As the field tends toward depletion, the

R/P may rise again as gas pressures drop and

as drilling gravitates to the marginal, lowpermeability formations. However because,

the R/P will equal 1.0 in the last year of a

field’s production, the R/P will decrease during the very last years of the field.

Conservation Regulations. —Some gasproducing States directly regulate production-related variables such as well spacing

and flow rates. These regulations are intended to promote efficient development of

reserves to prevent loss of ultimate recovery.

Their origin lies in the disruption caused by

the discovery of the east Texas field in 1930

and the large oversupply and resulting wasteful gas-production practices that followed. ’

Market Demand. —When the market is

demand-limited (deliverability exceeds demand), as it is today, the R/P no longer provides a measure of gas-production capacity.

Low demand can raise the R/P.

Reserve Requirements. —The substantial capital requirements of gas transmission and

distribution systems has led the transmission

and distribution companies as well as Government regulatory agencies to pursue longterm contracts requiring high R/P’s and high

reserve requirements for pipeline approvals.

These requirements do not apply, however,

to mature areas where pipeline capacity is

already in place.

“’Fletcher Area Underscores Perils in Deep Gas Reservoirs, ” Oil

and Gas Journal, Feb. 7, 1983, p. 25,

‘R. E. Megill, An introduction to Exploration Economics (Tulsa,

Okla.. Petroleum Publishing Company, 1971).
83

Historical Variation of R/P*

The early years of gas discovery in this country were marked by lack of a gas-distribution network, substantial discoveries of gas as a lowvalued or even unwanted byproduct of oil exploration, and the eventual discovery of enormous reserves (e. g., the 1922 discovery of the

giant Hugoton field in Kansas) that overwhelmed

existing demand. The combination led to very

high R/Ps in the 1920-40 period, followed by an

era of continued decline.

In the early years of the post-World War II

growth, as new pipeline systems were constructed,

previously unproductive proved reserves were developed. This activity increased the level of production without adding substantially to the volume of proved reserves, thus lowering the R/P.

Later in the 1960’s and 1970’s, when the natural

gas market had become supply constrained, production was again maintained by further development and a lowering of the R/P. At this time,

however, the ability to obtain greater production

from a given volume of proved reserves was improved by a geographical shift in production to

the Gulf of Mexico and encouraged by economic

changes that favored more rapid extraction rates.

The decline in R/P from 1946 to 1981 for the

Lower 48 States is shown in figure 22. The AGA

data cover the period 1946 through 1979, while

DOE EIA includes only the 5 years from 1977

through 1981. * *

The AGA data show strong year-to-year declines in the R/P over virtually the entire 34-year

period of available data. Recently, the rate of

decline eased from an average of over 0.8 per year

between 1966 and 1974, to an average of 0.5 per

year during the 1975-79 period. DOE/EIA estimated dry gas data show a further easing of the

decline rate to about 0.2 per year between 1977

and 1981.

Currently, the lowest R/P for the nonassociated

gas of a major producing State is 6.6 in Louisiana.

‘ Based <~n Jensen Associates, Inc., Understanding Natural Gas

Suppl}r ~n the U. S., April 1983, contractor report to OTA

● ‘These displayed ratit~~ are developed using the year-end reserves

estimate tor the year prior to the production period This approach

to calculating the R P stems from a bellef that production in a given

year is more Ilkely to be representat l;’e of reserves that are available

at the beglnnlng t~f the year

Figure 22.— Reserve-to-Production Ratios

for Natural Gas in the Lower 48 States

Year

SOURCE Off Ice of Technology Assessment based on data from Energy Infer

matlon Adml ni st rat!on, U S Crude 0(/, Nafura/ Gas and Na(ura/ Gas

LIqJIds Reserves— 7981 Artnua/ Reporl. DOEIE!A-0216 (81) August

1982, and American Petroleum Institute, American Gas Assoclat!on

and Can ad Ian Petroleum Assoc!at!on Reserves o‘ Crude 0(/ Natural

Gas Liquids, and Natural Gas Irr the Urr/fed Stat~s and Canada as of

December 31, 1979 VOI 34, June 1980

The lowest R/P for any geographical subdivision

published by the 1981 DOE/EIA reserves report

was a 4.0 for the State domain of the Texas offshore. The total Texas and Louisiana offshore,

representing 33 percent of Lower 48 State production, stood at 6.5 in 1981. With the Gulf of Mexico excluded, the balance of the Lower 48 States

had a 1981 R/P of 9.8. Contrasting strongly with

the lower R/P’s of the gulf coast would be that

of 17.2 for the heavily depleted reservoirs of Kansas and 20.1 in Wyoming, where field development for newly discovered reserves was incomplete in 1981.

Implications

These examples of R/Ps for different areas of

the United States during 1981 may indicate that

the Lower 48 State R/P could move further downward in future years if gas supplies were found

in areas with combinations of high-reservoir permeabilities and economics that favor extensive

field development. * This is in fact what happened

—

* Sc~me opinion exists, howeter, that some of the lower R 1)s are

due to underreporting of reserves rather than to extremely rapid

production It true, this might Indicate less potential for iurther

lowering the national R P
84

throughout the 1970’s as the Gulf of Mexico

became an increasingly large component of the

total supply. Between 1973 and 1981 the gulf’s

share of production grew from 20 to 33 percent.

An additional factor that might tend to push

the R/P downwards is a continuation of current

discovery trends towards smaller field sizes. It is

widely believed that smaller fields will be delineated, developed, and produced over shorter periods of time than was historically the case with

the mix of field sizes discovered until now.

On the other hand, some factors could cause

the R/P to reverse and begin to climb upward.

Future production trends may tend to increase the

shares of gas from tighter, lower permeability reservoirs and other sources more expensive to develop, which could lead to slow rates of production from proved reserves. For example, both the

deep Tuscaloosa trend and the Western Overthrust Belt are expected to have relatively high

R/Ps; field development and gas-processing costs

for these areas are too high to allow rapid depletion at current gas prices .10 In addition, the R/P

might tend to increase if future reserve additions

were below annual production rates because the

production capability (as a percentage of remaining reserves) of reservoirs tends to decline with

their age, * and a rate of reserve additions that is

below replacement levels will lead to an increasing average age for U.S. gas reservoirs .11

It is important to note that the balance between

demand and supply will also play a critical role

in determining the R/P. Because the purpose of

this evaluation is to examine the potential for gas

supply if gas is highly sought after, gas production—and, consequently R/P—is assumed to be

based on a supply-limited situation.** This situation would tend to intensify the incentives to develop fields rapidly and to maximize production

(minimize R/P). Rapid field development should

IOE F Hardy . . and C. p. Neil], testimony to the Subcommittee

on Fossil and Synthetic Fuels, Committee on Energy and Commerce,

U.S. House of Representatives, June 1, 1981.

*Up to a point. During the last few years of a reservoir’s life, its

RP must decrease because, in the last year, it will be 1.0. The last

year’s production will use up the entire remaining reserve.

1‘Ibid.

● *That is, a situation where additional supplies at prevailing prices

would be easily absorbed.

not be expected, however, if the current gas “bubble” of oversupply continues. In this case, field

development and production are likely to be

slowed.

In conclusion, expected R/Ps in 15 to 20 years

may range from values below today’s levels—perhaps 7.0, or even somewhat lower—to levels

slightly higher than today’s—perhaps 9.5. Part of

the future trend will be caused by the geologic

nature of new discoveries and their geographic environment. These factors can be manipulated

somewhat but are more likely to be imposed by

the random success of future exploration. Because

the R/P is also strongly affected by the willingness

to drill development wells and to take other (expensive) production-enhancing measures, large increases in gas prices would tend to drive the R/P

down to its lower limit. The lower value obviously can occur only with high gas demand, an assumption of this study. If gas demand were poor,

the R/P could exceed 9.5 for a while. Eventually, however, the lack of exploration incentives

would move proved reserves back into balance

with production requirements.

Production Scenarios

Table 17 summarizes the ranges of reserve additions and R/P’s projected for Lower 48 natural

gas development, Tables 18 and 19 present production and reserves projections that represent the

two extremes of the ranges in table 17. The first

projection assumes an optimistic exploration

future and rapid production of newly found

reserves—predicated upon high gas prices, high

demand, and an avoidance of large reserve additions in low-permeability areas that are hard to

develop rapidly. The second projection assumes

low finding rates and an increase in low-permeability reserves where production rates are limited.

Because each projection represents a convergence

of events of relatively low probability—e.g., the

lowest rates of new field discoveries, extensions

and new pool discoveries, zero revisions, and an

upturn in R/P—the projections should be viewed

as approximately bounding the range of production and proved reserve levels, rather than as identifying likely values.
85

Table 17.—Summary of Projections of Components of Reserve Additions and R/Ps

New field discoveries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1983-85 2.0-3.5 TCF/yr

1986-2000 1.5-3,5 TCF/yr

Extensions and new pool discoveries. . . . . . . . . . . . . . . . . . . . . 1983-85 8.0-12 TCF/yr

1986-2000 6,0-11 TCF/yr

Revisions, ., . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1983-2000 0-2.0 TCF/yr

R/P . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2000 7,0-9.5

Scenario 1A: reserve additions. . . . . . . . . . . . . . . . . . . . . . . . . 1983-85 17.5 TCF/yr

1986-2000 16.5 TCF/yr

R/P . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2000 7.0

Scenario 1B: reserve additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1983-85 10.5 TCF/yr

1986-2000 7.5 TCF/yr

R/P . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2000 9.5

SOURCE OffIce of Technology Asses~ment

—

Table18.— Lower 48 States Natural Gas Production and Reserves 1981-2000 (in TCF)

SCENARIO 1A: Optimistic Exploration, Rapid Production

Year Production Reserve additions Proved reserves R/Pa

1981 (actual). ,, . ., .....,..,,.. 18.5 21.5 168.6 9.0

1982 (approximate). . . . . . . . . 17.3 19.2b

170,7 9.75

1983 ..,..,, . . 18.0 17,5 170,2 9.50

1984, . . . . . . . . 18.9 17,5 168,8 9.0

1985 . . . . . . . . . . . . . . . . . . . . . . . . . 19.2 17.5 167.1 8.8

1986 . . . . . . . . . . . . . . . . . . . . . . . . . 19,4 16.5 164.2 8.6

1987 . . . . . . . . . . . . . . . . . . . . . . . . . 19.3 16.5 161.4 8.5

1988 . . . . . . . . . . . . . . . . . . . . . . . . . 19.5 16,5 158,4 8.3

1989.., . . . . . ., . . . . . 19.6 16,5 155,3 8.1

1990 . . . . . . . . . . . . . . . . . . . . . 19.4 16,5 152.4 8.0

1991 . . . . . . 19,3 16.5 149.6 7.9

1992 . . . . . . . . . . . . . . . . . . . . . . . . . 19,2 16.5 146.9 7.8

1993, ..,..,.., . . . 19,1 16.5 144.3 7.7

1994 . . . . . . . . . . . . . . . . . . . . . . . . . 19.0 16.5 141.8 7.6

1995 . . . . . . . . . . . . . . . . . . . . . . . . . 18.9 16,5 139.4 7.5

1996 . . . . . . . . . . . . . . . . . . . . . . . . . 18.8 16.5 137,1 7.4

1997., . . ..., . 18.8 16.5 134.8 7.3

1998., . . . . . ..., . . . . . . . . . 18.7 16.5 132.6 7,2

1999 . . . . . . . . . . . . . . . . . . . . . . . . . 18,7 16.5 130,4 7.1

2000 . . . . . . . . . . . . . . . . . . . . . . . . . 18.6 16.5 128.3 7,0

Cumulative production after 1982 = 342.4 = 44% of USGS remaining resource.

aRIP calculated by dvldlng previous year’s (yearend) reserves by production in the Ilsted year

bAmerlcan Gas Assoclatlon “Preliminary Flndlngs Concerning 1982 Natural Gas Reserves:’ EnergyAna/ys[s, Apr 29, 1983

SOURCE OffIce of Technology Assessment
86

Table 19.–Lower 48 States Natural Gas Production and Reserves 1981-2000 (in TCF)

SCENARIO 1 B: Pessimistic Exploration, Slowed Production

Year Production Reserve additions Proved reserves R/Pa

1981 (actual). . . . . . . . . . . . . . . . . .

1982 (approximate). . . . . . . . . . . . .

1983 . . . . . . . . . . . . . . . . . . . . . . .

1984 .., . . . . . . . . . . . . . . . .

1985 . . . . . . . . . . . . . . . . . . . . . . . . .

1986 . . . . . . . . . . . . . . . . . . . . . . . . .

1987 . . . . . . . . . . . . . . . . . . . . . . . . .

1988 . . . . . . . . . . . . . . . . . . . . . . . . .

1989, . . . . . . . . . . . . . . . . . . . . . . . .

1990 . . . . . . . . . . . . . . . . . . . . . . . .

1991 . . . . . . . . . . . . . . . . . . . . . . . . .

1992 . . . . . . . . . . . . . . . . . . . . . . . . .

1993 . . . . . . . . . . . . . . . . . . . . . . . . .

1994 . . . . . . . . . . . . . . . . . . . . . . .

1995 . . . . . . . . . . . . . . . . . . . . . . . . .

1996 . . . . . . . . . . . . . . . . . . . . . . . . .

1997 . . . . . . . . . . . . . . . . . . . . . . . . .

1998 . . . . . . . . . . . . . . . . . . . . . . . . .

1999, .....,.., . . . . . . . . . . . .

2000 . . . . . . . . . . . . . . . . . . . . . . . . .

18.5

17,3

18.0

18.1

16.9

16.4

15.4

14.6

13.8

12.9

12.4

11,8

11,2

10.8

10.5

10,0

9.8

9.5

9.2

9.0

21.5

19.2b

10.5

10.5

10.5

7.5

7.5

7.5

7.5

7,5

7.5

7.5

7.5

7.5

7.5

7.5

7.5

7.5

7.5

7.5

168.6

170.7

163.2

155.6

149.2

140.3

132.4

125.3

119.0

113.6

108,7

104.4

100.7

97.4

94.4

91.9

91.9

87.6

85.9

84.4

9.0

9.75

9.50

9.3

9.2

9.1

9.1

9.1

9.1

9.2

9.2

9.2

9.3

9.3

9.3

9.4

9.4

9.4

9.5

9.5

Cumulative production after 1982 = 230 TCF = 300/0 of USGS remaining resource.

aR/p calculated by dlvldlng previous years (yearend) reserves by production In the listed Year

bAmencan Gas Assoclatlon Prelrmlnary Flndlngs Concerning 1982 NatLral Gas Reserves, Ener9YArra/Ysls W 29 1983

SOURCE OffIce of Technology Assessment

APPROACH NUMBER 2–PROJECTING NEW POOL DISCOVERIES,

EXTENSIONS, AND REVISIONS AS A SINGLE GROWTH FACTOR

The preceding approach is designed to allow

a projection of future gas reserves based on

separate estimates of new field discoveries, extensions, new pool discoveries, and revisions. An

alternative method is to project only new field discoveries and apply a “growth factor” to these discoveries that combines the effects of the other

three categories of reserve additions.

USGS has used afield-growth approach to calculate the amount of gas remaining to be discovered in the inventory of identified fields.12 In

that application, a curve was constructed that alescribes the reserve growth in initial discoveries that

occurs after the year of discovery, averaged over

all discovered fields nationwide and over 9 of the

14 discovery years where appropriate data were

available (1966-79). This curve, illustrated in

figure 23, shows a 60-year growth in reserves to

about four times the initial (discovery year) estimate of gas volumes discovered. The curve shows

that most of this growth occurs in the first 5 years

———

“U.S. (kological Survey Circular 860, app. F.

Figure 23.—The Growth of Year-of-Discovery

Estimates of the Amount of Recoverable Natural

Gas Discovered in the Lower 48 States

after the discovery year. In the USGS calculation,

the curve was applied to the initial discoveries

reported in every discovery year, assuming that

reserve growth patterns of recently discovered

fields would be the same as the patterns of much

older discoveries. The gas volumes calculated in

this manner—gas that is difficult to classify as
discovered or undiscovered—are called “inferred

reserves” by USGS.

This method may be extended to project how

the first-year estimates of reserve additions from

future new field discoveries will grow in the years

following the discovery year. However, certain

adjustments have to be made. First, a growth factor calculated by tracking “initial discoveries” data

must be increased if it is to apply directly to new

field discovery data. This is because the discovery

data13 includes not only new field discoveries, but

also “certain hydrocarbon accumulations which

are significant from the standpoint that advances

in exploration technology resulted in the discovery

of such reservoirs."14 Consequently, the year-ofdiscovery values are larger than those of “new

field discoveries, ” and the later expansion is lower

because some technology-based expansions are excluded. Adjusting the calculated growth factor to

account only for growth of new fields may raise

the factor by about 20 percent.

Second, for the method to be credible, the assumption that the historical growth curve will

continue to be valid must be relaxed somewhat.

Many of the factors affecting the growth of recoverable reserves in newly discovered fields have

changed; consequently, it appears likely that the

growth curve has changed as well. The development of a credible forecasting procedure depends

on defining a new curve or family of curves that

logically fit these changed conditions.

Table 20 lists the arguments—some speculative—that support an increase or decrease (over

historical levels of field growth) in the ultimate

magnitude of reserve growth in new fields. *

USGS’s estimate is not the only available estimate of field growth. Table 21 presents three other

estimates, with ultimate growth ranging from 3.5

to 6.3 times the initial year-of-discovery estimate.

Table 20.—Argumentsa for the Question, “Will

the Reserve Growth in New Fields Be Larger or

Smaller Than the Growth Recorded in Previously

Discovered Fields?”

A. New fields will grow more

1.

2.

Recent increases in real gas prices are leading to

greater recovery factors for gasfields—from closer

spacing of development wells, extensions into lesspermeable margins of reservoirs, exploitation of

smaller pools, lowering of abandonment pressures, and

reworking of older wells. Together, they increase the

ultimate recovery (reported cumulative production at

field abandonment).

The historical growth factor does not accurately reflect

the actual field growth. The large negative revisions

in onshore south Louisiana and Texas have artificially depressed reported field-growth rates, Because

these revisions were due to a unique set of circumstances, they are unlikely to recur, and reported growth

rates should increase.

B. New Fields Will Grow Less:

1.

2.

3.

4.

5.

Part of the reason that the levels of new field discover.

ies reported by EIA were higher than those reported

by AGA during the 3 years the two reports overlapped

is probably that EIA reported reserve additlons during

the discovery year that AGA did not report until the second year, Therefore, when ElA-reported trends are used

to project future new field discoveries, the growth factor used should be smaller than the historical average,

which was derived from AGA data

The historical growth factor was derived from data

developed during a time when giant gasfields dominated gas reserves, Giant fields with multiple pools

take many years to develop and are generalIy believed

to have greater relative growth than small fields. Present and future field sizes wiII be smalIer and should

be expected to have smalIer growth factors and faster

development,

Improvements in seismic and other exploration technology, as well as in reservoir engineering, allow

clearer initial delineation of field boundaries and other

field characteristics and more accurate first-year reserve estimates, This should leave less room for

growth.

Increased gas prices have led to acceleration of field

development. Some of the development that might previously have taken place i n the second year now takes

place in the first year and IS reported as part of the initial new field discovery reserve data

High capital requirements to develop new fields in

hostile environments—an increasing feature of today’s

resource base— require a more accurate first-year

estimate of reserves, leading to lower “growth” later

on.

-——-—— a Some of I hese arguments are s pec u I at tve For e x arn ple, I r) B 1 OTA has not

determ( ned the cause of the AGA/EIA dlfferenr es n reported new f!eld

discoveries

SOURCE Office of Technology Assessment

In order to use the “growth-factor” approach

to project future gas production, Jensen Associates, Inc., an OTA contractor, constructed a simple model that applied growth curves similar to
88

Table 21 .—Alternative Estimates of Growth Factors

for Initial Reserve Estimates for Gasfields

Author Suggested growth factors

1. USGS (Root) (1981) . . 4.0, all fields

2. Haun (1981) ... . . 4.0, fields younger than 48 years

5.0, fields older than 48 years

3. Hubbert (1974) . . . . . 3.5, all fields

4. Marsh (1971) . . . . . . . . 5.0, fields younger than 28 years

6.3, fields older than 28 years

1 D H Root, “Es~matlon of Inferred Plus Indicated Reserves for the United

States, ” app F In G L Dolton, et al , Estlrnates of Urrdlscovered Recoverable

Converrf~orra/ Resources of Oi/ and Gas ~rr fhe Un/fed Sfafes, U S Geological

Survey Circular 660, 1981

2 J D Haun, “Future of Petroleum Exploration In the United States, ” AAPG

Bu//ef~n 656(10), 1981

3 M K Hubbert “U S Energy Resources, A Review as of 1972, ” S Res 45, ser

No 93.40 (92.75), Committee on Interior and Insular Affairs, U S Senate 1974.

cited In Haun, ibid

4 G R Marsh, “How Much 011 Are We Really Flndlng “ 0// and Gas Journa/. Apr

5, 1971, cited In Haun, op clt

SOURCE Office of Technology Assessment

that in figure 23 to both known fields and to projected levels of new field discoveries. A growth

curve that reached a factor of 4.0 in 60 years was

applied to all pre-1982 discoveries, while curves

with 30-year growth periods were applied to discoveries from 1982 on. The period of 30 years was

selected to reflect OTA’s belief that the pace of

field development has quickened. The choice is

a guess because data sufficient to calculate a new

timetable are not available. The uncertainty in the

ultimate value for the growth factor is reflected

in a range of values from 3.0 to 5.0. In OTA’s

opinion, 5.0 represents an optimistic upper-bound

on future growth in new fields.

Tables 22 through 24 present the results of three

scenarios representing the search for reasonable

upper- and lower-bounds on future gas production. * For each scenario, the “growth-curve”

methodology was applied only to nonassociated

gas. Associated gas was projected separately by

applying a gas-to-oil production ratio of 1.3 MCF

per barrel of crude oil to the EIA’s 1981 oil production forecast. 16

..—

*The production projections in the three tables should be viewed

as s] ightly pessimistic. This is because they are based on projected

1982 nonassociated reserve additions of 8.7- 10.2 TCF, whereas

preliminary reports (based on the annual reports clf the major oil

and gas companies ) indicate that actual 1 Q82 add i t ions may ha vc

been significantly higher, perhaps as high as 15 or 16 TCF.

IOU, S, Department of Energy, 1 ~81 Annual Repc)rt to Congress,

VOI, 3, p. 62.

Table 22.–Lower 48 States Natural Gas Production and Reserves, 1982-2000 (in TCF)–

Scenario 2A: Very Optimistica

Total gas Nonassociated gas Assoc./dissolved .- — —

Year product ion Product ion Reserve additions Proved reserve R/P gasb production

1982 . . . . . . . . . . . . . . .

1983 . . . . . . . . . . . . . . .

1984 . . . . . . . . . . .

1985 . . . . . . . . . . .

1986 . . . . . . . . . . . .

1987 . . . . . . . . . . . . . .

1988 . . . . . . . . . . . . . . . . . . .

1989 . . . . . . . . . . . . . . . . . . . .

1990 . . . . . . . . . . . . . . . . . . .

1991 . . . . . . . . . . . . . . . .

1992 . . . . . . . . . . . . . . . .

1993 . . . . . . . . .

1994 . . . . . . . . . . . . . . . . . . . .

1995 . . . . . . . . . . . . . . . . . . . .

1996 . . . . . . . . . . . . . . . . . .

1997 . . . . . . . . . . . . . . . . . . .

1998 . . . . . . . . . . . .

1999 . . . . . . . . . . . . . . . . . . . .

2000 ... . . . . . . . . . . . . . . .

18.7

18.2

18.0

18.0

18.3

18.6

18.9

19,3

19,5

19,7

19,8

19.8

19,7

19,6

19.3

19.1

19.0

18.8

18.7

15.7

15.3

15.2

15.2

15.5

15.8

16.2

16.5

16.8

17.1

17.3

17.3

17.2

17.2

16.9

16,8

16.6

16.5

16.4

10.2

11.7

13.0

14.8

15.5

15,8

15,9

16,0

16.0

16,1

16,2

16,2

16,3

15,3

15.4

15.4

15.4

15.5

15.5

132.8

129.2

127.0

126.6

126.7

126.6

126.3

125.7

124.9

123.9

122.8

121.7

120.8

119.0

117.4

116.0

114.8

113.8

112.9

8.8

8.7

8.5

8.3

8.2

8.0

7.8

7.6

7.5

7,3

7.2

7.1

7.1

7.0

7.0

7.0

7.0

7.0

6.9

3.0

2.9

2.9

2.8

2.8

2,7

2,7

2.7

2.7

2.6

2.6

2.5

2.5

2.4

2.4

2.4

2.3

2.3

2.3

Cumulative production after 1982 = 342.4 TCF = 44°/0 USGS remaining resource.

Note Rows and columns may not add exactly due to rounding

—.

aAssumpt Ions Nonassoclated gas new field discovery rate = 3,000 BCF/yr

Growth factor = 50

Addltlonal growth from price rises for old gas = 1000 BCF/yr from 1985 to 1995

bAssoclated/d, ssolved gas—gas found In the same resewolr with oil

SOURCE Jensen Associates Inc contract submission to the Of ftce of Technology Assessment, 1983
89

— .

Table 23.— Lower 48 States Natural Gas Production and Reserves, 1982-2000 (in TCF)—

Scenario 2B: Pessimistica

Total gas Nonassociated gas

Year

——

product ion Product ion Reserve additions Proved reserve RIP

1982. , . 18.7 15.7 8.7 131,3 8.8

1983 . . . ... 18,0 15.1 8.4 124.6 8.7

1984 ., ., 17.4 14,6 8.3 118.4 8.5

1985 ,.. . . . . . . 16.9 14,1 8.3 112,6 8.4

1986 . . . . . . . . . 16,4 13.6 8,2 107.2 8.3

1987 .. ..,.., 15.9 13.2 7,6 101.7 8.1

1988 ., ., : : : : : : : : : 15.4 12.7 7.6 96.6 8.0

1989 . . . . . . . . . . . . 15,0 12.3 7,7 92.0 7.9

1990 ., . . . 14.6 11,9 7,7 87.7 7.7

1991 . . . . . . 14.2 11,6 7.7 83.8 7.6

199 2 13.8 11.2 7.7 80.3 7.5

1993 . . . . . . 13,4 10.9 7,7 77.1 7,4

1994 . . 13.0 10,5 7.7 74.4 7.3

1995 . . . . . . . . 12.6 10,2 7.2 71.4 7.3

1996 . . . . . . . . 12,2 9.8 7.2 68.8 7.3

1997 . 11.8 9.5 7.1 66.5 7,3

1998 ..,,.., . . . . . . . . 11,5 9.2 7.1 64.4 7.2

1999 . . . . . . . . . . . 11,2 8.9 7.1 62.6 7.2

2000 . . . . . . . . . . 11.0 8.7 7.1 61.0 7,2

Cumulative production after 1982 = 254 TCF = 330/0 USGS remaining resource.

Note Rows and columns may not add exactly due to rounding

aAssumptlons Nonassoc,ated gas new fle(d discovery rate 1,500 BCF/yr

Growth factor 40

Add!tlonal growth from prrce rrses for old gas 500 BCF/yr from 1985 to 1995

bAs~oc,ated dissolved gas–gas found In the same reservo!rwlfh ol(

SOURCE Jensen Associates Inc contract submlss!on to the Offlceof Technology Assessment, 1983

Assoc./dissolved

gas b production

3.0

2.9

3.0

2.8

2.8

2,7

2,7

2.7

2,7

2,6

2.6

2.5

2,5

2.4

2.4

2.4

2.3

2,3

2.3

.

Table 24.–Lower 48 States Natural Gas Production and Reserves, 1982-2000 (in TCF)–

Scenario 2C: Very Pessimistica

Total gas Nonassociated gas Assoc./dissolved

Year production Production Reserve additions Proved reserve R/P ga s

b productio n

1982 . ....;.... . . . . . 18. 5

– – 15.5 8.7 131.3 8.9 –

3.0

1983 . . . . . . . . . . . . . . . . . . . . 17,7 14.8 8.0 124.7 8.9 2.9

1984 . . . . . . . . . . . . . 16.9 14.0 7.5 118.1 8.9 2.9

1985 . . . . . . . . 16.1 13.3 6.4 111.2 8.9 2.8

1986 . . . . . . . . . . . 15.3 12,5 6.1 104.9 8.9 2.8

1987 . . . . . . . . . . . . . . . . . . . . 14.5 11.8 5.4 98.5 8.9 2.7

1988 . . . . . . . . . . ..,, 13.8 11.1 5.4 92.8 8.9 2.7

1989 . . . . . . . . . . . . . . . 13,1 10.4 5.4 87.9 8.9 2.7

1990 .,.., . . . . . . . . 12.5 9.9 5.5 84.4 8.9 2.7

1991 . . . . . . . . . . . . . . 12.0 9.4 5.5 79.6 8.9 2.6

1992 . . . . . . . . . . . . . . . 11,5 8.9 5.5 76.1 8.9 2.6

1993 . . . . . . . . . . . . . . 11.1 8.6 5.5 73.1 8.9 2.5

1994 . . . . . . . . . . . . . 10.7 8.2 5.6 70.5 8.9 2.5

1995 . . . . . . . . . . . . . . 10,4 7.9 5.6 68.1 8.9 2.4

1996 . . . . . . . . . . . . . 10.1 7.7 5.5 66.0 8.9 2.4

1997 . . . . . . . . . . . . . . . . . . . . 9.8 7,4 5.5 64.1 8.9 2.4

1998 . . . . . . . . . . . . . . . . . . . 9,5 7.2 5.5 62.4 8.9 2.3

1999, . ., . ., ..,..,.., 9.3 7.0 5.5 60.9 8.9 2.3

2000 . . . . . . . . . . . . . . . . . . . . 9.1 6.8 5.5 59.6 8.9 2.3

Cumulative production after 1982 = 223.4 TCF = 29% USGS remaining resource.

Note Row; and columns may not add exactly dueto round!ng

aAssumpflons Nonassoclafed gas new field discovery rate = I.soo BCFw

Growth factor = 30

No add!t!onal growth from prrce rises for old gas

bAs socla t e d / dis so l

v e d gas—gas found In the Same resermirwlth CIll

SOURCE Jensen Associates, Inc, contract submlss!on tether.lfflce of Technology Assessment, 1983
90

APPROACH NUMBER 3–REGION-BY-REGION REVIEW

OF RESOURCES AND EXPLORATORY SUCCESS*

Using a region-by-region review to project future gas production involves a geologist’s examination of a variety of factors affecting production in 10 individual regions of the Lower 48 States

and his subjective evaluation of their future production potential.

For this approach, the gas resource base was

assumed to be a compromise between the assessments of USGS and PGC. For each region, a resource value was selected by examining the field

size and number implications of the two assessments and choosing the value that seemed more

realistic. Then, future additions to proved reserves

were estimated, based on a subjective evaluation

of the following factors:

●

o

●

●

Difficulty and expense of development. —

Based on expected field sizes, depths, known

geology.

Announced leasing schedules.

“Maturity” of province. —The percent of

total expected resources that have already

been developed.

Recent development history. —Especially, the

rates of entry into proved reserves of the remaining resources.

For each region, it was generally considered unlikely that a very high percentage of the remaining undiscovered resource—say, 50 percent or

greater—could be transferred into proved reserves

by 2000, and this situation acted as a strict limit

on production in some regions, for example, in

the “west Texas and eastern New Mexico”

region. * *

Tables 25 and 26 present two scenarios of future

gas production and reserve additions based on the

above approach. Scenario 3A projects that one-

*The analysis described in this section was performed by Joseph

P, Riva, Jr., Specialist in Earth Sciences, Congressional Research

Service (CRS). Riva’s full report, which is part of CRS’S participation in this study, will be incorporated in a background document

to this technical memorandum.

* ● To stabilize current gas production to the end of the century

in this region, 96 percent of the estimated undiscovered gas in the

region would have to be discovered by 2000. From 1970 to 1981,

23 percent of the inferred reserves plus undiscovered resources were

added to reserves.

Table 25.—Lower 48 States Natural Gas Production

and Reserves, 1982-2000 (in TCF)—Scenario 3A

Reserve Proved

Year Production additions reserves R/P

1981. , . . . . . . . . . .

1982 . . . . . . . . . . . . .

1983 ...., . . . . . . . .

1984 ..., . . . .

1985, . . . . . . . . . .

1986 . . . . . . . . . . . . .

1987 . . . . . . . . . . . . .

1988 .., . . . . . . . . . .

1989, . . . . . . . . .

1990 ...., . . . . . . . .

1991 .., ., . . . . . . .

1992 . . . . . . . . . . . . .

1993 ....., . . . . . . .

1994 ..., . . . . . . . . .

1995 ...., . . . . . . . .

1996 ...., . . . . . . . .

1997 . . . . . . . . . . . . .

1998 ......, . . . . . .

1999 . . . . . . . . . . . . .

2000 . . . . . . . . . . . . .

18.5

18.6

17.6

16.8

16.1

15.7

15.3

15.1

14.7

14,5

14.3

14,2

14.0

13.7

13,5

13.4

13.3

13.0

12.8

12.6

21.6

10.9

10.9

11.2

11.2

11.2

11.2

11.2

11.2

11.2

11.2

11,2

11.2

10.1

10.1

10.3

10.3

10.3

10.3

10.3

168.6

160.9

154.2

148.5

143.5

139.0

135.0

131.0

127.4

124,1

121.0

118.0

115.2

111.6

108.2

105.1

102.1

99.4

97.0

94.6

9

9

9

9

9

9

9

9

9

9

8

8

8

8

8

8

8

8

8

8

Cumulative production after 1982 = 260.6 = 34°/0 USGS

remaining resource.

SOURCE J P Rlva, Jr A Pro/ectlon O( Convenf/ona/ Natural Gas Production

In the Lower 48 States fo the Year 2000 Congressional Research Ser

vice/Library of Congress, June 10, 1983

Table 26.— Lower 48 States Natural Gas Production

and Reserves, 1982-2000 (in TCF)—Scenario 3B

Reserve Proved

Year Production additions reserves R/P

1981 . . . . . . . . . . . . .

1982 . . . . . . . . . . .

1983 ...., . . . . . . .

1984 . . . . . . . . . . . . .

1985, . . . . . . . . . . .

1986. , . . . . . . . . . . .

1987 . . . . . . . . . . . . .

1988, . . . . . . . . . . .

1989, . . . . . . . . . . . .

1990. , . . . . . . . . . .

1991 .., . . . . . . . . . .

1992 ..., . . . . . . . . .

1993 ..., . . . . . . . . .

1994 . . . . . . . . . . . . .

1995 ......., . . . . .

1996 . . . . . . . . . . . . .

1997 . . . . . . . . . . . . .

1998 . . . . . . . . . . . . .

1999 ...., . . . . . . . .

2000 . . . . . . . . . . . . .

18.5

18.7

18.0

17.3

16.8

16,2

15.8

15.4

15.0

15.1

15.6

15.7

15,2

14.8

14.5

14,2

13.9

13.7

13,5

13.3

21.6

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

12.1

168.6

161.9

156.0

150.8

146.1

142.0

138.3

135.0

132.1

129.1

125.5

121.9

118.8

116.0

113.6

111.5

109,7

108.0

106.6

105.4

9

9

9

9

9

9

9

9

9

8.5

8

8

8

8

8

8

8

8

8

8

Cumulative production after 1982 = 274 = 35°/0 USGS

remaining resource.

SOURCE J P Riva, Jr A Pro/ecfion of Conventlona/ Natura/ Gas F’roducf/on

(n fhe Lower 48 States to ftre Year 20@ Congressional Research Ser.

vice/Library of Congress, June 10, 1983
91

quarter of the gas estimated to be available in undiscovered fields at the end of 1981 will be discovered by 2000. This compares to 55 percent of

the undiscovered gas being discovered between

1945 and 1981, a period when larger prospects

were available, but also when gas discovery rates

may have been hampered by low regulated prices.

In this scenario, gas production is projected to increase in the Rocky Mountains and Great Plains

region, the Eastern Interior region, and the Appalachian region; in addition; production begins

in Oregon-Washington and on the Atlantic continental shelf. However, major production decreases are projected for west Texas and eastern

New Mexico, the midcontinent, and the gulf

coast, all critical gas producers today.

Scenario 3B assumes that exploration becomes

more efficient and that 35 percent of the resources

in undiscovered fields can be discovered by 2000.

Even under this more optimistic scenario, however, gas production will decline to 13.3 TCF by

2000.

APPROACH NUMBER 4–GRAPHING THE COMPLETE

PRODUCTION CYCLE

Projecting future gas production by graphing

the complete production cycle is based on the expectation of M. King Hubbert that the complete

cycle of production will somewhat resemble a bellshaped curve and that knowing the area under

the curve-the total recoverable resource—allows

a reasonable facsimile of the entire curve to be

drawn, once about a third or more of the production cycle has been completed. Hubbert used

this approach in 195617 to show that then-current

estimates of the remaining oil resource base implied that oil production was on the verge of peaking and then declining.

In this application, gas production values for

1900-82 were plotted, and three freeform curves

were extended from the 1982 production rate such

that the area under the curves equaled the remaining gas resources estimated by, respectively, Hubbert, USGS, and PGC (see table 5). These curves

are shown in figure 24.

The curves show that Hubbert’s assessment implies an extraordinarily sharp decline in production, so that by 2000 the total Lower 48 production rate would be about 3 TCF. Since there is

little flexibility in drawing this curve, it appears

unlikely that the range of uncertainty due to the

“h! K Hubbert, Nuclear Energy and FOSSII Fuels, ” In Amerqcan

Petroleum Jrtstltute, Drilllng and Production Practice (1956), cited

In \l. K Hubbert, “Techniques of Predlctlon as Applied to the Production of 0]1 and ~;as, ” Oil anci G’as Supply Llodeling, S. 1. Gass

( ed. 1, ~atl(~nal Bureau ot Standards Special Report 631, hlay 1982.

selection of the curve’s shape is greater than about

2 to 5 TCF in 2000.

The curves representing the USGS and PGC gas

resource assessments were drawn so that the declining portion of the curve resembles a mirror

image of the ascending portion. Both curves show

production rates staying steady at least until 2000.

A plausible physical interpretation of the curves

is that they represent a resource base that still retains a substantial number of large fields amenable

to rapid rates of production. Furthermore, the

shape of the curves is clearly alined with high demand for gas and prices that encourage substantial development drilling as well as vigorous exploratory efforts.

The USGS and PGC curves obviously can be

redrawn to reflect different conceptions of how

the production cycle might unfold. However, the

necessity of maintaining existing production

trends in the early years and of tapering-off

gradually as the resource is depleted limits the options. Figure 25 shows the original USGS curve

and a second curve that reflects a different conception, that of a production decline that commences earlier but proceeds at a more gradual

rate. This second curve might reflect a future

where industrial demand for gas declines and exploratory activity and development drilling proceed at a lower level, It might also reflect a

resource base whose fields are smaller, in more

difficult to develop locations, and of lower

average permeability.
92

Figure 24.— Future Production Curves for Conventional Natural Gas in the Lower 48 States

25 r

Ea

fol

ch curve represents one possible production future based on the

lowing resource assessments,

A RANGE FOR FUTURE GAS PRODUCTION

In comparing figures 24 and 25 to the production projections produced by the alternative

methods, some interesting conclusions can be

drawn. First, the higher end of the production

ranges, which shows essentially stable production

levels out to 2000, appears to be quite compatible with the USGS and PGC curves, as drawn in

figure 24. It should be remembered, however, that

there are interpretations of the detailed physical

nature of the gas resource base that, while compatible with the overall magnitude and even the

regional estimates of USGS or PGC, could be

completely incompatible with the high year 2000

production projection. The second curve in figure

25 displays such an alternative interpretation, and

there are more radical possibilities as well. *

*One such possibility would be a resource base that, while large,

had most of its resources in hard-to-find, slow-to-produce fields.

A second conclusion is that the lower end of

the production range—about 9 TCF by 2000—is

really much too optimistic for a believer of the

Hubbert or RAND resource estimate. This is because the assumptions of the lower end of the

range, while appearing to be pessimistic to a

“resource optimist, ” may actually appear somewhat optimistic to a “resource pessimist .“ This end

of the range assumes that the fairly low new field

discovery rates of the early 1970’s are more realistic as a long-term average than are the higher

rates of the last few years, but it ignores the

possibility that even these low rates might go

down still farther as resource depletion continues.

Consequently, the true production implication of

The future production “cycle” would then show a significant production drop in the next 20 to 30 years, followed by a very long

period of low but stable production.
93

Figure 25. —Two Production Futures, One Resource Base: Alternative Representations of Future Production

of Conventional Natural Gas in the Lower 48 States, Based on the USGS (1981) Resource Assessment (mean estimate)

—

25

24

23

22

21

20

19

18

17

16

15

14

13

12

11

10

9

8

7

6

5

4

3

2

1

0

1900 1920 1940 1960 1980

SOURCE Office of Technology Assessment

the range of resource base estimates cited in table

5 is likely to be a year 2000 range of about 4 to

19 TCF rather than the range of 9 to 19 TCF expressed by the first three projection approaches. *

As discussed in chapter 4, OTA believes that

the Hubbert and RAND estimates are overly pessimistic and that a more likely lower bound for

the remaining recoverable gas resources is about

400 TCF rather than Hubbert’s 244 TCF or

RAND’s 283 TCF. This higher value is compati-

.

‘It is important to remember that the kind of radical drop in production dictated by the most pessimistic of the resource base

estimates WI]] likely violate their baseline assumpti[~ns of maintenance

of existing cost price relationships — except for Hubbert’s assessment

( Hubbert believes his methodology “captures” future changes in

price cost relationships and technology ). Although many’ present

gas customers can switch without extreme dlfflcult y to 011 products

or to elect rtcltv (assure ing supplies of these are available), a rapid

drop In production would still tend to push gas prices sharply upwards. This In turn would tend to increase the resource base by mo\’-

ing subecc)norn ic resources into the economic, recoverable category.

2000 2020 2040 2060 2080 2100

Year

ble with a 2000 production rate of 9 TCF. Consequently, in our opinion, a reasonable range for

Lower 48 conventional natural gas production for

the year 2000 is 9 to 19 TCF. Similarly, a reasonable range for 1990 is 13 to 20 TCF.

Finally, figure 24 illustrates an important point

about the current “optimistic” assessments of the

recoverable resource base: that these, too, imply

an inevitable decline in conventional gas production, although the date of decline is perhaps 20

or 30 years later than that dictated by a pessimistic

(400 TCF) resource base assessment. It must be

stressed, however, that the additional 20 years or

so of leeway implied by the more optimistic assessments may yield sufficient changes in prices

and technology to allow either or both the entry

of nonconventional gas sources to the market and

the movement of large amounts of conventional

resources from “subeconomic” to “economic.”
94

These potential sources of gas production are out- technical memorandum, but conceivably they

side the boundaries of the resource base assess- could be extremely important to future U.S. gas

ments and production forecasts discussed in this production.

PUBLIC AND PRIVATE SECTOR FORECASTS

OF FUTURE GAS PRODUCTION

Comparisons of alternative gas production forecasts have many of the same problems as those

of comparing gas resource base estimates (see ch.

3, table 4). The economic, regulatory, and other

“scenario” conditions assumed for the forecasts

are not always made clear. Because the range of

reasonable future values/assumptions for these

conditions are so broad, it is probably safe to

assume that there are major scenario differences

between different forecasts. The resources measured may differ, with some forecasts including

only “conventional” gas and others including all

methane sources, especially gas from tight sands.

The extent to which some of the commonly used

resource base estimates (which are important

variables in some of the forecasts, directly determining finding rates or defining an upper limit for

cumulative discoveries) contain unconventional

resources is not always clear. For example, the

PGC acknowledges that as much as 20 percent

of its estimated “potential resource” is in tight

sands, ’a but other estimates do not specify such

a percentage. Consequently, even the forecasters,

themselves, do not always know how much tight

gas is incorporated in their production forecasts. *

Table 27 presents the results of 21 public and

private sector production forecasts of conventional Lower 48 gas production.** Four of the

forecasts explicitly include tight sands and/or

Devonian shale; these are noted on the table.

A striking feature of the table is that all but one

of the forecasts project substantial declines in gas

production, most within 10 years and all but the

“Potential Gas Agency, News Release, Feb. 26, 1983.

● Further, there may not be agreement as to what constitutes “tight

gas. ” For example, the Federal Energy Regulatory Commission includes a maximum permeability of 0.1 millidarcies in its definition,

while the National Petroleum Council used 1 millidarcy as the limit

in its report on unconventional gas sources.

* ● Including associated ‘dissolved gas (gas colocated with oil), on

a dry basis.

one “dissenter” by 1995. It is important to recognize that these forecasters include some prominent

gas “optimists, “ including AGA. Consequently,

much of the current optimism about gas’s future

apparently stems from projections of supplementary supply from unconventional sources, from

Alaska, from Mexico and Canada, and from LNG

imports. Chapter 6 provides a brief discussion of

the potential from all of these sources except unconventional production. *

The extent of agreement about future gas production displayed in table 27 is in sharp contrast

to the very wide range projected by OTA. For

the year 2000, a range of 11 to 15 TCF/yr—an

extremely narrow range, given different base

assumptions, forecasting methods, etc.—would

encompass 13 of the 14 estimates available for that

date. In contrast, OTA believes that an appropriate range for year 2000 production is 9

to 19 TCF/yr. Part of this difference may be attributed to the fact that most of the values in the

table represent forecasts of “most likely” gas production rates, and there may be a tendency for

such estimates to cluster together. In conjunction

with this possibility, a lack of documentation for

many of the forecasts makes it unclear whether

they are all independent, original estimates. Some

may simply be averages of other forecasts, reflecting the “conventional wisdom. ”

Of particular interest is a comparison of AGA’s

year 2000 estimate—12 to 14 TCF/yr—and the

production implications of the AGA-supported

PGC’s gas resource assessment. PGC’s assessment

seems most compatible with production levels of

15 or 16 TCF/yr, or higher. If the AGA production forecast is intended to be associated with the

PGC resource base, then AGA is using a most pessimistic interpretation of the resource base, at least

● Unconventional gas potential will be discussed in the final report

from this study.
95

Table 27.–A Comparison of Conventional Lower 48 Natural Gas Supply Forecasts (TCF)

—

Company 1985 1990 1995 2000 ——. -.—

I. Gulf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2. Texaco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3. Chevron. . . . . . . . . . . . . . . . . . . . . . . . . .

4. Exxon

5. Sheila.. . . . . . . . . . . . . . . . . . ., . .

6. Conocob 

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7. Union. . . . . . . . . . . . . . . . . . .

9. Standard Oil (lndiana)c 

. . . . . . . . . . . .

10. Tenneco . . . . . . . . . . . . . . . . . . . . . . . .

11 AIR . . . . . . . . . . . . . . . . . . . . . . . . . .

12, AGE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

13. GRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ~~~~~~~~

14. DOCC... . . . . . . . . . . . . . . . . . . . . . . .

15. GAO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

16. E. Erickson . . . . . . . . . . . . . ,..,, . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

17, ERA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18. ICF ,.,,,. . . . . . . . . . . . . . . . . .

19. IEA/OECDb 

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

20. Chase Bankb 

., . . . . . ., ., . . . . . . . . . . . .

Average

19.4

18.9

18,2—

17.0

19,0

19,2

18,5

18.0

15.5

16.0-18.0

17.9—

16.5

17.4-18.5

17,3

16,1

16.5-18.0

18,3

18.1

15.4

13,6

15.0-17.0

15,1

—

148 —

149

14.3

14,0-17.0

17,7

16.6

16.7

14.0

165 —

11.5

—

16.5

13.5—

13,5-15,5

12.8

—

14.0 —

14.0

12.4 —

—

153

3 8

3.0

4.0

4.1

8.9

4,6

—

5.5

11.9

—

12,0-14.0

116

12.8

13.5 —

—

—

11-15—

143

aMarketed gas rather than actual total (dry} production Excludes InCreased ProductIon from f!elds that are ‘forever controlled under NGPAandtha! Shell belleves

could be obtained with decontrol

bNumbers Include tight sands

cAverages tnclude Interpolated data

13EFERENCES

1 Gulf 011 Corp. US Energy Analysls Task Group Plttsburg Pa US Env(ronmenfa/Assessment 1982 Scenanos June 1982 Business as Usual scenarto tl~

eludes Lower 48 and southern Alaska I

‘2 Texacolnc Economics Dlv)slon Finance and Economics Department, White Plalns NY Un/ted Sfafes Energy Out/ook 19802000 Februa~ 1981 (Forecastof

Marketed ProductIon )

“3 Standard 011 Co of Cal!fornla Economics Department San Francisco Callf Prellmlnary forecast from forthcoming publication

4 ExxonCo USA Houston Tex Energy Ouf/ook 1980-2C00 December 198 0

“5 Shell OIICO Exploration and Production Economics Department Houston, Tex iVatlona/ Energy Out/ook to the Year 20(?0 JUIV 1982 (Fall 1981 Analysls Dry

Marketed Gas )

“6 Conoco Inc Coordlnaflng and Plannlng Department Stamford Corm Wor/d Er?ergy Out/ook Through 2000 January 1982

“7 Union Oll Co 011 and Gas Dlvls!on Plannlng and Valuation Los Angeles Callf

“8 Marathon 011 Co Eronornlcs Department Flndlay Ohio

“9 Standard 011 Co (Indiana) Ch!cago 1!1 Amnrn$ forecast Includes nonhydrocarbon gases and IS specifically done on a dry gas basis Its 1985 forecast number

IS demand-constrained

“1O Tennessee Gas Transmlsslon Co Economic Analys!s and Long Range Plann!ng Department Houston Tex Energy 7982-200!2 August 1982

“11 American Natural Resources Co Detroit Mlch Ur?(ted Slafes Energy Ouf/ook 1980.2000

12 American Gas Assoclatlon Gas Supply Committee Arltngton Va The Gas Energy Supp/y Ouf/ook 1!980-2000 January 1982

“13 Gas Research Institute Washington DC Gas Research /frs/ghts October 1982

14 US Departmentof Commerce Washington DC US Energy for lhe Rest ofttre Century July 1982

15 General Accounting Off{ce Washington DC Ana/yslsof Current Trends/n US Pefro/eurn and Natura/ Gas Production. Dec 7 1979

16 Dr Edward W Erickson for Nalural Gas Supply Assoc(atton rVatura/ Gas Poficy Acf A Pragmatic Arra/ys/s January 1981

17 Energy Information Admlnlstratlon US Department of Energy Washington DC 1981 Annua/ Report to Congress. February 1982

18 lCFlnc Washington D C “The Economics of Gas Supply” as publ!shed In The Energy JournaL VOI 3, No 4 October 1982

19 international Energy Agency OECD World Energy Ouf/ook, Pans 1982

20 Chase Manhattan Bank Energy Economics Dlv{ston New York Best estimate forecast from forthcoming pubi!catlon

SOURCE Jensen Associates Inc Undersfandfng Natural Gas Supp/y In the Un(led Sfales Contractor Report to the Offlceof Technology Assessment April 1983

from the standpoint of maintaining production

rates at high levels during the next few decades.

OTA undertook to evaluate and compare both

the general methodologies associated with these

forecasts and, in a few cases, the specific assumptions and methodological decisions made by individual forecasters. However, many of the forecasts are based, in large part, on proprietary information, and needed details were unavailable.

Also, several of the forecasts made by the large

energy companies depend heavily on judgmentmodels, and these forecasts would have been difficult to document and evaluate even if the companies had desired public scrutiny of this sort. In

addition, several of the models ostensibly available for public scrutiny do not, in fact, have adequate documentation. A background document

to this report will present OTA’s staff review of

modeling methodologies and of some specific

models. The document will also present a review

of modeling methodology by James Jensen, president of Jensen Associates, an OTA contractor.

al procedures rather than on formal computerized
Chapter 6

Other Gas Sources—Summary
Chapter 6

Other Gas Sources—Summary*

Natural gas imports in 1981 totaled 904 billion

cubic feet (BCF)1 and composed 4.6 percent of the

total U.S. dry gas consumption. As recently as

1979, however, imports constituted as much as

6.1 percent of the total U.S. dry gas consumption. The current import status and future import

projections are summarized in table 28.

In evaluating “other” potential supplies of

natural gas, the most obvious sources are the

border countries, Canada and Mexico. Canada

has been and probably will remain our most important source of supplemental natural gas. In

January 1983, the National Energy Board recommended an additional 9.25 trillion cubic feet (TCF)

of reserves for export. Although this decision

nearly doubles the exportable quantity available

to the United States, actual imports are expected

to remain low in the near-term, owing to de-

*Th]\ chapter \ummari7e\ a deta]lcd dts( uss][~n to be published ]n

the ba~hgr{~und report t () th IS technl( ~ I memorandum

] [1 S [Department ot Energy,, Ener~} In}nrrna t lon Adrnln]strat Ion,

“U.S. Imports and Exp{lrtt [>t Ndtural (jas 1981, ‘ ]une 1982

Table 28.— Natural Gas

.—— . —

creased U.S. demand and noncompetitive pricing. In the long run, the increase in allowable exports will probably help encourage frontier

development.

Exports from Mexico will probably remain at

300 million cubic feet (MMCF/day) in the nearterm, consistent with what they have been since

the present contract was negotiated in 1979.

Although Mexican natural gas supplies are bountiful, the Mexican Government’s current export

philosophy seems to preclude significant increases

in exports to the United States. Mexican consumption is expected to increase as the distribution infrastructure develops.

Alaska represents another large potential supply; the Prudhoe Bay Field alone constitutes over

10 percent of the total U.S. proved reserves. At

present, there is no natural gas production reaching the Lower 48 States, owing to the lack of a

means of transportation. Financing for a transportation project is difficult to obtain because of curImports Summary Table

Natural gas supplied Allowable imports Proved Range of

to Lower 48 States under 1982 reserve future export estimates’ --

Source I n 1981 licenses/contracts estimates 1990 2000

Mexic o

—

0.1 TCF

—

0.1 TCF 75 TCT 0.1-1.0 TCF 0-2,0 TCF

(EIA) (PEMEX) (AGA LA Mexlco)

Canada 0,8 1.8 TCF 88 TCF 1.0-2.5 TCF 1,0-3.0 TCF

(EIA) (CPA) (AGA LA Canada)

Alaska o — 32 TCF ANGTSb

(USGS PGC) 0712 TC F 1 224 TCF

Pacific-Alaskan LNG

0.1 TCF 0,2-0,4 TCF

(AGA)

LNG 0,04 0.9 TCFC N.A. Variable—depends on future U.S.

(AGA/GER) policy and pricing,

Total 0.9 TCT

—

(EIA)

‘This range represents the htghest and lowest est!mates of the references cited

—

bAla~kan Natural Gas Transportation System

cThls value represents the total contract volumes for completed terminals

REFERENCES

AGA -- American Gas AssoclatlonThe Gas Energy SupII/y Ouf/ook 19802000 January 1982

AGA/GER –Amer!can Gas Assoc!atlon, Gas Energy Rev/ew. June 1982

CPA –Canadtan Petroleum AssoclatlonStatmt(ca/ Handbook 198 0

EIA– Energy Information Admjnjstrat]on U S /rnporls and Exports of Nafura/ Gas 1981 J une 1982

LA –Canada– Lew, n & Associates–Canad(ari Na(ura/ Gas A Future North Amer/can Energy Source? January 1980

LA– Mex, co– Lew!n & Associates–future Mex(can 0(/ and Gas Product(on July 1979

PEMEX – n American Gas Assoc!atton Gas Energy Rev/ew December 1982

PGC– Potential Gas Committee Potenf~a/ Supp/y of Natura/ Gas In the U S May 198 1

USGS– Unlfed States Geological Survey Circular 860

SOURCE Of { Ice r]f Technology Assessment

99
100

rent surplus supply and market prices below levels

necessary for financial success. Despite a waiver

package to eliminate roadblocks to private financing, the Alaska Natural Gas Transportation System project still has not achieved adequate financing arrangements. The rival, recently proposed

TransAlaska Gas System would enable North

Slope gas to be marketed outside of the domestic

market. A methanol conversion alternative would

allow the gas to be marketed either domestically

or internationally. Neither of these alternatives

appear to have good prospects for the immediate

future.

MEXICO

Mexico had reported 75.4 TCF of proved reserves as of December 1981. Within the last 4

years, large reserve additions have caused Mexico’s reserve-to-production ratio to double from

30 to 60.

Most of Mexico’s gas production is from wells

associated with oil; nonassociated wells are typically not put into production. This practice reflects Mexico’s policy of exporting oil and using

natural gas primarily to meet domestic energy demands. Mexico exports only the surplus gas remaining after domestic demand is met, which is

the primary limiting factor to export levels. Mexico’s current export level of 110 BCF/yr was established in 1979 by a contract with Border Gas,

a U.S. pipeline company.2 This quantity is recognized as a compromise between Mexican policymakers, who believe energy exports are necessary

to bolster Mexico’s ailing economy, and those

who believe the resource should be saved for

future domestic use.

Mexico has been successful in encouraging conversions to natural gas, and, as a result, domestic

gas demand has been growing at a rate of 13 percent per year. 3

Because Mexico’s financial condition has precluded investment in distribution

‘Border Gas is owned and controlled by six interstate pipeline companies: Tennessee Gas Transmission Co., Texas Eastern Transmission COW., El Paso Natural Gas Co., Transcontinental Gas Pipeline

Corp., Southern Natural Gas Co., and Florida Gas Transmission Co,

‘Petroleum intelligence Weekly, Special Supplement, “Mexico’s

Expanding Role in World Oil Markets, ” June 28, 1982.

Throughout the early to mid-1970’s, liquefied

natural gas (LNG) contracts were viewed as a

favorable means of achieving long-term natural

gas supplies. Since that time, the supply scenario

has changed significantly, and LNG purchasers

are now confronted with high-priced gas during

a time of gas surplus. In the near term, there is

little incentive to increase LNG imports; however,

the availability of the long-term contracts and the

opportunity to diversify U.S. supply may prove

to be attractive in the future.

equipment, the primary constraint to increased

domestic consumption is a lack of transmission

and distribution capability. As the distribution

system develops and the process of converting end

users to gas progresses, domestic consumption will

increase, which could further constrain the exportable surplus.

Substantial increases in the export level are not

expected in the near term. Early in 1982, the Mexicans talked of increasing exports to 500 MMCF/

day and later to 1,000 MMCF/day; however,

these plans were not carried out, owing to problems with gas-gathering systems and budget cutbacks.’

There is a considerable range of estimates for

the future quantity of Mexican gas available for

export to the United States. In their “high success”

case, Lewin and Associates estimate that annual

exports will rise to 766 BCF in 1990 and then decrease to 255 BCF by 1995 and O by 2000.5 The

American Gas Association (AGA) is considerably

more optimistic in its long-run projections and

estimates that between 100 and 1,000 BCF/yr will

be available in the 1990’s and between 100 and

2,000 BCF/yr will be available by 2000.6

41bid.

5Lewin and Associates, Future Mexican Oil and Gas Production,

July 1979.

‘American Gas Association, The Gas Energy Supply Outlook:

1980-2000, January 1982.
101

CANADA

Canada also has large natural gas reserves, estimated at 88.4 TCF by the Canadian Petroleum

Association. Its ultimately recoverable resource

base estimate of 420 TCF7 could be increased considerably by developing unconventional gas in

Western Canada. At present, the technology to

produce most of these low permeability reservoirs

has not been demonstrated.

Marketability problems have created a large

surplus export capability. In January 1983, in an

attempt to alleviate the situation, the National

Energy Board nearly doubled the exportable quantity of gas available to the United States. Also,

in April 1983, the price was reduced from $4.94

per thousand cubic feet (MCF) to $4.40 per MCF

to compete more readily in the U.S. market. However, despite these efforts, the price differential,

decreased U.S. demand, and improved short-term

domestic supply prospects are still expected to

keep U.S. imports of Canadian gas low in the near

term.

The 1980 National Energy Plan (NEP) is expected to have far-reaching effects on the Canadian petroleum industry. The NEP established

guidelines aimed at enabling Canada to achieve

energy self-sufficiency by 1990. Several NEP objectives include:

● encourage substitution of gas for oil by

favorable pricing;

. increase Canadian ownership of the domestic

petroleum industry to 50 percent by 1990;

● stimulate frontier exploration off the East

Coast and in the Arctic;

Ž allow a 25 percent back-in interest for the

Canadian Government on federal leases; and

Ž increase the Canadian Government’s share

of petroleum revenues relative to those received by industry and the producing provinces.

“R, hl I’rocter P. J, Lee, and D, N. Skibo, “Canada’s Conventional Oil and Gas Resources” Geological Survey of Canada, Open

File 767, March 1981, p. 27.

The increased regulation of the NEP has had

a noticeable negative impact on risk investment.

Canadian operators and support companies have

left Canada for more lucrative prospects in the

United States. Many petroleum companies have

cut expenditures and long-term projects and suffered severe losses. These effects could lessen the

quantity of gas produced in the remainder of the

century, thereby limiting the availability of surplus for export to the United States.

Another factor affecting gas export is the level

of Canadian gas consumption. In an attempt to

reduce the need for expensive foreign oil imports,

the Canadian Government is encouraging increased use of natural gas and has provided several incentives for doing so, such as favorable gas

prices, grants, and loans. The NEB forecasts natural gas demand to increase at 4 percent per year

during the 1980’s and 3 percent per year throughout the 1990’s.8 Although the conversion process

is progressing slowly, the quantity of gas available

to the United States could be constrained if Canadian consumption increases substantially in the

future.

Under current Canadian export agreements,

natural gas exports will increase to about 1.6

TCF/yr by 1990 and then decline to about 0.15

TCF/yr by 2000.9 AGA estimates that between

1.0 and 1.7 TCF/yr will be exported by 1990 and

1.0 to 2.0 TCF/yr by 2000. Lewin and Associates

believe that technological advances in the frontier areas and the development of unconventional

gas could allow exports of 2.5 and 3.0 TCF/yr

in 1990 and 2000, respectively. 11

‘National Energy Board, “Omnibus ’82 Backgr(>under, ” Jan 27,

1983.

‘Ibid,

l~American Gas Associat i on, The ~as EnerA~\, .$upp]}’ ~ut~(~()~:

1980-2000, Januar y 1982,

I I Lew,ln and Assc>clates, cana~lan Natural Gas: A Future ,Xrorth

American Energ~ Source, January 1980.
102

ALASKA

The massive hydrocarbon potential of Alaska

was realized with the discovery of the Prudhoe

Bay Field in 1968, which added 26 TCF to estimated U.S. proved gas reserves. Reserve estimates

for Alaska average 32 TCF, and resource base estimates are as high as 145 TCF.12

Despite the substantial quantity of reserves in

Alaska, lack of a transportation system has precluded marketing of Alaskan gas to the Lower 48

States. The Alaskan Natural Gas Transportation

Act of 1976 directs the President, subject to congressional approval, to establish a means to transport Alaskan natural gas to the Lower 48 States.

To ensure domestic use of the resources, the Export Administration Act of 1979 forbids the export of North Slope hydrocarbons to non-U, S.

customers. Several transportation methods have

been proposed; not all of these have designated

the Lower 48 States as the final market.

In September 1977, the Alaskan Natural Gas

Transportation System (ANGTS) was chosen

over several alternatives. The 4,800-mile pipeline

was to be routed from Prudhoe Bay across Alaska

and Canada to Alberta, and split into a western

leg to California and an eastern leg to Illinois. Despite a waiver submitted by President Reagan and

approved by Congress in mid-December 1981, to

remove any legislative deterrents to private financing, the pipeline has not yet been financed.

Investment capital has been difficult to attract

because the marketability of the gas is questionable. ANGTS is estimated to cost between

$38.7 billion and $47.6 billionl3 and deliver gas

at prices estimated between $4.85 per MCF14 and

$20 per MCF.l5 ANGTS is the only transporta-

‘lPotential Cas Committee, Potentia] Suppi}’ of Natural Gas in

the U. S., hlay 1981,

‘ ‘American Gas Association, Gas herg~r Review, V(I1. 10,

No 1, January 1Q82.

I 4]nfern~tjond/ Gas ~echrto]og}r Highlights, “Alaskan I>ipel ine

Ccxts Could Be Lower Because of Delay: Northwest Heat, ” Aug.

30, 1982.

I soil and Gas /cJurnaj, ‘‘Angts Seen Top Option for Alaskan ~jas, ”

Aug. ~, 1982, p. 61,

tion scheme designed to market North Slope natural gas in the Lower 48 States. AGA estimates

that between 0.7 TCF and 1.2 TCF could be available by 1990 and 1.2 TCF to 2.4 TCF by 2000,

depending on when the pipeline is completed.16

Converting North Slope gas to methanol could

provide an alternative market for the gas. The

principal advantage of the methanol option is that

the existing oil pipeline system could be used to

transport the methanol from the North Slope to

Valdez, assuming capacity were available. The

major problems with the methanol alternative are

the high energy loss associated with conversion

and the potential that future demand for methanol

might be insufficient to absorb Alaskan production. Also, costs would be very high; estimated

first year costs for conversion and transportation

range between $14.24 and $17.24 per million

Btu.

17

Two LNG projects have been proposed to market Alaskan gas. The Alaska Governor’s Economic Committee recommended the TransAlaska Gas

System (TAGS). The TAGS requires an 820-mile

pipeline from the North Slope to the Kenai Peninsula, where the gas would be liquefied and shipped

to foreign markets, principally Japan. If this proposal is adopted and an executive order or legislation declaring gas exports to be in the national

interest is obtained, the Lower 48 States may

never receive supplemental gas from the North

Slope. Another LNG proposal, the Pacific Alaska

LNG Project, calls for the shipment of south Alaskan LNG to receiving facilities on the California

coast; however, the potential supply contribution

from this project is small. AGA estimates 0.1 TCF

could be supplied by 1990 and between 0.2 and

0.4 TCF by 2000, depending on the construction

schedule.18

‘*American Gas Association, The Gas Energ~’ Supply Outlook.:”

lQ8@2~, January 1982

‘“Congressional “Research Service, Mdjor issues Associated \Vith

the A]dska Natural Gas Transportation Waivers, Dec. 18, 1981.

‘

sAmerican Gas Association, The Gas Energy Supply Outlook:

1980-2000, January 1982,
103

LIQUEFIED NATURAL GAS

During the early to mid-1970’s, when the United

States was confronted with natural gas shortages,

LNG imports appeared to be a favorable supplemental supply alternative. Several long-term contracts were established with Algeria. Since then,

the supply situation has changed drastically, and

in the midst of a natural gas surplus, LNG purchasers are confronted with very high-cost gas

supplies.

Although existing agreements enable imports

of up to 800 BCF per year, the U. S. imported only

61 BCF of LNG in 1982 at two of four- existing

receiving facilities. The Distrigas facility in

Everett, Massachusetts, received 34.0 BCF and the

Lake Charles, Louisiana, facility received 27.0

BCF since its first shipment in September 1982.

Small amounts of LNG were also trucked from

Canada to New England. Also in 1982, the United

States exported 55.9 BCF from Cook Inlet, Alaska, to Japan, and in 1981 was a net exporter of

LNG.

19

For purposes of evaluating future LNG availability, the LNG resource base includes any large

reserves which, owing to remote location or lack

of a transportation method, are not committed

to existing markets. In 1978 OTA estimated that

of the 2,257 TCF of proved reserves in the world,

about 812 TCF were surplus (635 TCF of the surplus are located in the U. S. S. R., Iran, and Al-

] ‘U S. Department ot Energy, Energy Intormatlon” Admlnl\tratl[)n

~i S ]mpt~rts and ~xports of Natural Gas 1Q81 , ]unt, 1 Q8Z

geria20). Although reserves are plentiful, high costs

preclude a large percentage of natural gas reserves

from being made available as LNG. The total capital required for a world-scale LNG facility (1

BCF/day) is around $5 billion (in 1978 dollars).

Generally, 40 percent is required for production

and liquefaction, 40 percent for transporttion,

and 20 percent for receiving and vaporization facilities. 21

The future of LNG depends principally on pricing and policy. If the producing country is willing to accept a price that achieves parity with the

price of oil at the burner tip, the future of LNG

is considerably brighter than if the oil parity price

is demanded at the wellhead. The additional costs

for liquefaction and transportation are reflected

in the burner-tip price, which, if too high, is not

competitive with oil and is not economically justifiable. Currently, the price of LNG is higher than

market-clearing levels, and lower cost gas is used

as a cushion to moderate the price. This average

pricing concept is often criticized for substituting

high-cost imports for lower priced alternatives,

creating a potential misallocation of resources.

Also, from a policy standpoint, importing foreign

supplies of natural gas, particularly from a member of OPEC, is not consistent with U.S. goals

of reducing energy dependence.
Appendix
Appendix A

Glossary

anaerobic: Conditions that exist only in the absence

of oxygen.

anticline: A fold, generally convex upward, whose

core contains stratigraphically older rocks.

associated dissolved gas: Natural gas that occurs together with oil in a reservoir, either dissolved in the

oil (dissolved gas) or as a gas cap above the oil (associated gas).

combination trap : A trap for oil or gas that has both

structural and stratigraphic elements.

extension test: A well drilled to extend the areal limits

of a partially developed pool. May sometimes become a new pool discovery well, Also known as outpost test .

field: Composed of a single pool, or multiple pools

that are grouped on or related to a single structural

and/or stratigraphic feature.

formation: A rock mass composed 01 individual beds

or units with similar physical characteristics or

origin.

formation water: Water present in a water-bearing

formation under natural conditions, as opposed to

introduced fluids, such as drilling mud.

new field wildcat: A well drilled in search of oil or

gas in a geological structural feature or environment

that has never before been proven productive.

new pool wildcat: Well drilled in search of pools

above (shallower pool test ), below ( deeper pool

test ), or outside the area] limits of already known

pools in fields that have already been proven productive. May sometimes become an extension well.

nonassociated gas: Natural gas that occurs in a reservoir without oil.

outpost test: See extension test .

permeable: Having the property or capacity of a porous rock, sediment, or soil for transmitting a fluid;

it is a measure of the relative ease of fluid flow under

unequal pressure.

petroleum: A general term for all naturally occurring

hydrocarbons, whether gaseous, liquid, or solid.

play: A rock formation or group of formations within

a sedimentary basin with geologic characteristics

similar to those that have been proven productive.

A play serves as a planning unit around which an

exploration program can be constructed. May also

refer to the exploratory effort, often following a

significant discovery, that uses a geologic idea to

determine where petroleum can be found.

pool: A subsurface accumulation of oil and/or gas in

porous and permeable rock, having its own isolated

pressure system. Theoretically, a single well could

drain a pool. Also known as a reservoir.

porosity: The percentage of the bulk volume of a rock

or soil that is occupied by interstices (gaps between

the particles that compose the rock ), whether isolated or connected.

prospect: An area that is a potential site of economically recoverable petroleum accumulation based on

preliminary exploration.

province: A region in which a number of oil and gas

pools and fields occur in a similar or related geological environment.

reserves: Usually refers to oil or gas that has been

identified by drilling or extrapolation from drilling

and is recoverable at current prices and technology.

Proved reserves are identified and estimated directly by engineering measurements; in most cases, only

the drilled portion of fields is included in this category.

reservoir: See pool.

reservoir rock: Any porous and permeable rock that

yields oil or gas. Sandstone, limestone, and dolomite

are the most common reservoir rocks, but gas accumulation in the fractures of less permeable rocks

also occurs.

resources: The total amount of oil or gas that remains

to be produced in the future. Generally does not include oil or gas in such small deposits or under such

difficult conditions that it is not expected to be produced at any foreseeable price technology combination.

secondary migration: The movement of fluids within

the permeable reservoir rocks that eventually leads

to the segregation of oil and gas into accumulations

in certain parts of these rocks.

sedimentary basin: A low area in the Earth’s crust,

caused by earth movements, in which sediments

have accumulated.

sedimentation: The act or process of forming or accumulating sediment in layers, including such processes as the separation of rock particles from the

material from which the sediment is derived, the

transportation of these particles to the site of deposition, the actual deposition or settling of the particles,

the chemical or other changes occurring in the sediment, and the ultimate consolidation of the sediment

into solid rock.

source rock: Sedimentary rock in which organic

material under pressure, heat, and time was transformed to liquid or gaseous hydrocarbons. Source

rock is usually shale or limestone.

107
108

stratigraphic trap: A trap for oil or gas, resulting from trap: Any barrier to the upward movement of oil or

changes in rock type, porosity, or permeability, that gas that allows either or both to accumulate. A trap

occurs as a result of the sedimentation process rather includes a reservoir rock and an overlying impermethan structural deformation. able roof rock; the contact between these is concave,

structural trap: A trap for oil or gas resulting from as viewed from below. See also stratigraphic, strucfolding, faulting, or other deformation of the Earth. tural, and combination traps.