U.S. Natural Gas Availability: Gas Supply

Through the Year 2000

February 1985

NTIS order #PB84-114909
Recommended Citation:

U.S. Natural Gas Availability: Gas Supply Through the Year 2000 (Washington, DC: U.S.

Congress, Office of Technology Assessment, OTA-E-245, February 1985).

Library of Congress Catalog Card Number 85-600507

For sale by the Superintendent of Documents

U.S. Government Printing Office, Washington, DC 20402
Foreword

This report responds to a request from the House Committee on Energy and

Commerce and its Subcommittee on Fossil and Synthetic Fuels to conduct a study of

the domestic (Lower 48 States onshore and offshore) natural gas availability over the

next few decades. OTA was asked to examine both conventional and unconventional

sources of natural gas, review current estimates of resource bases and production potentials, and examine key technical issues that will affect the future development of those

sources. This request was supported by the Subcommittee on Energy Research and

Development of the Senate Committee on Energy and Natural Resources. Two interim

reports were released in conjunction with the request: a Technical Memorandum on

U.S. Natural Gas Availability: Conventional Gas Supply Through the Year 2000, and

a Staff Memorandum on The Effects of Decontrol on 0/d Gas Recovery. This report

combines the results of the earlier reports with considerable additional material on

the unconventional gas sources to provide a comprehensive survey of the natural gas

sources available to the United States during the next few decades.

National concerns about gas supplies have eased considerably with the current

surplus deliverability and recent improvements in the rate of additions to the Nation’s

proved reserves. The Congress’ perception of the Nation’s long-term gas supply prospects will still, however, play an important role in its consideration of several important policy initiatives. These initiatives include pressure for repeal of constraints on gas

usage embodied in the Powerplant and Industrial Fuel Use Act of 1978, continuing

attempts to decontrol natural gas prices, and initiatives to support the added use of

natural gas in power generation as part of a strategy to reduce acid rain.

In addition, arguments about the appropriate Federal role in research on unconventional gas sources hinges in large part on Congress’ concerns about the need for new

sources to supplement the United States’ traditional domestic gas sources. OTA hopes

that this report will help to clarify the continuing arguments about gas’ potential longterm role in future U.S. energy consumption and assist the Congress in formulating

effective natural gas and energy policies.

OTA received substantial help from many organizations and individuals during the

course of this study. We would like to thank the project’s contractors, who prepared

critical background analyses, the project’s advisory panel and the workshop participants, who provided guidance and extensive critical reviews, and the many additional

reviewers who gave their time to ensure the accuracy of this report.

. . . Ill
U.S. Natural Gas Availability Panel

William Vogely,

Department of Mineral Economics,

Marc Cooper

Energy Director

Consumer Federation of America

Lloyd Elkins

Petroleum Consultant

Tulsa, OK

Ed Erickson

Professor of Economics and Business

North Carolina State University

Daniel Grubb

Vice President of Gas Supply

Natural Gas Pipeline Co. of America

John Haun

Professor of Geology

Colorado School of Mines

Don Kash

George Lynn Cross Research Professor of

Political Science, and Research Fellow

Science and Public Policy Program

University of Oklahoma

Chairman

Pennsylvania State University

Lawrence Moss

Independent Consultant

Estes Park, CA

Roy E. Roadifer

Chief Geologist

Mobil Oil Corp.

John Schanz

Senior Specialist in Energy Resource Policy

Congressional Research Service

Benjamin Schlesinger

Independent Consultant

Bethesda, MD

John C. Sharer

Director

Natural Gas Supply Research

Gas Research Institute

John Weyant

Deputy Director

Energy Modeling Forum

Stanford University

Harry C. Kent

Director, Potential Gas Agency
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. Whipple, Gas Imports, Devonian Shale Gas, Coal Seam Methane

David Strom, Computer Supply Models

Administrative Staff

Lillian Quigg Edna Saunders

Other Contributors

Joseph Riva, Congressional Research Service

Kathryn Van Wyk, Editor (Part I)

Contractors and Consultants

Richard Nehring, Colorado Springs, CO

Jensen Associates, Inc., Fairfax, VA

James W. Crafton, Golden, CO

Johnston & Associates, Haymarket VA
Acknowledgments

Many other people contributed to this report by providing information, advice, and substantive reviews

of draft materials. OTA would like to specially thank Lawrence Drew of the U.S. Geological Survey, Robert

Kalisch of the American Gas Association, Wallace Howes of the Natural Gas Pipeline Company of America,

Vello Kuuskraa of Lewin & Associates, and Charles Matthews of the Shell Oil Co. for their exceptional contributions to this report. We would like to acknowledge the

Dayne Adams,

El Paso Natural Gas

Ovid Baker

Mobil Research & Development Corp.

Porter Brown

Columbia Gas Transmission Co.

David Burnett,

Chandler & Associates

Paul Ching

Shell Oil Co.

Tim Considine

Bank of America

Todd Doscher

Doscher’s Group, Inc.

Everett Ehrlich

Congressional Budget Office

Scott Farrow

Carnegie Mellon University

William Fisher, Robert Finley

University of Texas at Austin

Michael German, Jeffrey Wingenroth

American Gas Association

Gail Harrison

Wexler, Reynolds, Harrison, & Schule

Robert A. Hefner, Ill

The GHK Companies

Steve Holditch

Texas A&M University

C. J. Holland, Jr.

Sun Exploration & Production Co.

Howard Kilchrist, Webster Gray,

Wayne Thompson, Victor Zabel

Federal Energy Regulatory Commission

Charles Komar

Morgantown Energy Technology Center,

U.S. Department of Energy

valuable contributions of the following individuals:

Charles Mankin

Oklahoma Geological Survey

Richard O’Neill, Lucio D’Andrea, Phil Shambaugh

Energy Information Administration,

U.S. Department of Energy

Gary Pagliano

Congressional Research Service

Dudley Rice, Gordon Dolton, Charles Spencer

U.S. Geological Survey, Denver, CO

David Root, John Houghton, Richard Meyer,

Terry Offield

U.S. Geological Survey, Reston, VA

R.J. Saucier

Shell Western E&P, Inc.

John Scheunemayer

University of Delaware

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

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

Exxon Co., U.S.A.

Ralph Veatch

Amoco Production Co.

W. R. Watkins

DeGolyer & MacNaughton

Steve Watson, Steve Minihan, Richard Jefferis

U.S. Department of Energy

James White

U.S. Department of Energy

Ralph Willard

Dowell Division of Dow Chemical Co.

Thomas Woods, Daniel Dreyfus, Joseph Rosenberg

Gas Research Institute
Workshop on Unconventional Natural Gas Resources

Dayne Adams

Division of Reservoir Engineering

El Paso Natural Gas

Ovid Baker

Mobil Research & Development Corp.

David Burnett

Chandler & Associates

Marc Cooper

Consumer Federation of America

Ed Erickson

Department of Economics and Business

North Carolina State University

John Haun

Colorado School of Mines

Donald Kash

Science and public Policy Program

University of Oklahoma

Charles Komar

Morgantown Energy Technology Center

Vello Kuuskraa

Lewin & Associates

John McCormick

Environmental Policy Institute

Joseph Rosenberg

Gas Research Institute

Charles Spencer

Oil and Gas Resource Branch

U.S. Geological Survey

James R. White

Department of Energy

Ralph Willard

Dowe!l Division of Dow Chemical Co.

vii
—

Contents

Chapter

1. Introduction and Overview . . . . . . . . . . . . . . . . . . . . . . . . .

Part 1: Conventional Gas Supplies

2.

3.

4.

5.

6.

. . . . . . . . . . . . . . .

Summary: Availability of Conventional Gas Supplies . . . . . . . . . . . . . . . . . . .

Natural Gas Basics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

The Natural Gas Resource Base . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Gas Production Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7.

8.

9.

10.

Page

3

17

29

39

81

Other Gas Sources: Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . ...........111

Part II: Unconventional Gas Supplies

Introduction and Summary:

Availability of Unconventional GasSupp

Tight Gas . . . . . . . . . . . . . . .

Gas From Devonian Shales

Coalbed Methane . . . . . . . .

. . . . . . . . . . .

. . . . . . . . . . .

lies . . . . . . . . . . . . . . . . . . . . . . . . . .121

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 179

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207

Page

A.

B.

c.

D.

Calculation of Additional Reserves From Increased Gas

Recovery in Old Gasfields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........227

Fracturing Technologies . . . . . . . . . . . . . . . . . . . . . . . . . ...................229

Double Counting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................236

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .........................242

Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .247
Chapter 1

Introduction and Overview
introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Projections of Future production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

The Gas Resource Base. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Natural Gas and Energy Policy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

How This Report is Organized . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

FIGURE

3

5

6

7

9

10

Figure No. Page

1. Natural Gas production, Additions to Reserves, and

Total Reserves of the U.S. Lower 48 States . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Chapter 1

Introduction and Overview

INTRODUCTION

The passage of the Powerplant and Industrial

Fuel Use Act in 1978, which put legal restraints

on future 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 a year earlier 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. ’

These pessimistic predictions were based partly

on short-term problems— periodic curtailments

of natural gas deliveries 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 1960s,

the ominous and apparently unstoppable decline

of proved gas reserves (fig. 1).

Since 1978, 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, was

caused by a combination of energy conservation,

recession-induced reductions in industrial activity, and industrial fuel switching from gas to oil

as a result of declining oil prices and increased

gas prices. At the same time, reserve additions

have rebounded from the depressed levels of the

1970s to over 20 trillion cubic feet (TCF) in 19812

1 R. CII iano, et al., A Cornparatil e State-of-the-Art Assessment of

Gas Supp/y Mode/Ing, EPRI report EA-201, February 1977.

‘Energy I ntormatlon Acimlnlstratlon, US. Crude 0//, Natura/ Gas,

and Natura) Gas .lqulds Reserves, 1981 Annual Report, U.S. Department of Energy, August 1982. Because the EIA data series appears to differ somewhat from the earlier American Gas Association data (EIA began In 1977), the interpretation of the recent higher

reserve add It Ions is somewhat controversial.

and over 17 TCF in 1982.3 Also, the U.S. Geological survey (USGS) and the Potential Gas Committee (PGC) have each recently reaffirmed their

earlier estimates of the remaining recoverable

resources 4 in the Lower 48 States:5 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.6

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. And finally, a series of recent reports

by the National Petroleum Council and others7

have projected that large supplies of “unconventional” gas from tight gas reservoirs, Devonian

shales, and coal seams can be made available

well within this century.

Along with this new optimism has come some

new uncertainty about future gas supply, however. This uncertainty stems from: 1 ) the current

3Energy I nformatlon Administration, U.S. Crude Oi/, Natura/ Gas,

and Natural Gas Lquids f?eser~’es, U.S. Department of Energy,

August 1983.

4“Resources” and ‘‘reserves’ are terms that are often–

incorrectly—used Interchangeably. The term ‘‘reserves” or ‘‘proved

reserves” refers to the portion of the total gas resource base that

has been positively identified by drilllng and estimated directly by

engineering measurements, and that is recoverable at current prices

and technology. “Resources” refer to a broader, more speculative

estimate of the total gas remaining to be produced, under conditions defined by the estimator.

‘B. M. Mi Iler, et al,, Geo/ogica/ Estimates of Undlsco\ered Recoverable Oil and Gas Resources in the United States, USGS Clrcu Iar 725, 1975; and Potential Gas Committee, Pofentia/ Supp/}<

of Natura/ Gas in the United States (as of Dec. 31, 1980) (Potential

Gas Agency, Colorado School of Mines, Golden, CO), May 1981.

6G, L. Do[ton, et al,, Estlrnates of Undisco\’ereci Recolerabk Convention/ Resources of 0// and Gas In the United States, U.S. Geological Survey Circular 860, 1981; and Potential Gas Comrnlttee,

Potentia/ Supp/y of Natur,]/ Gas In the Unlteo’ States (,;s of Dec.

31, 1982) (Potential Gas Agency, Colorado School of Mines, Golden,

CO), June 1983.

‘National Petroleum Council, Uncon\entlona/ Gas Sources: Vo/-

ume 1{: Tight G]< Reservoirs-Parts / and II, December f 960 and

other \olumes; R. E, Zlellnskl and R, D. Mclver, Resource and Ek -

pkjraflon Assessment of the 0// and Gas Potentia/ In the De\ onmn

Gas Sha/es of the Appa/ac-ht. ?n Basin, U.S. Department of Energy

Report, DOE/DP/0053-l 125, undated; and other reports.

3
4 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Figure 1.

300

280

260

240

220

200

180

—Natural Gas Production, Additions to Reserves, and Total Reserves of the U.S. Lower 48 States

Years

30 \

151 -

20

‘ t

Production

I

Additions

1950 1955 1960 1965 1970 1975 1980 1985

Years

SOURCE American Gas Association, The Gas Energy Supply Outlook: 1983-2000, October 1983.

low level of proved reserves (which increases the

volatility of production); 2) substantial changes

in gas prices and demand; 3) rapid advances in

technology and the subsequent emergence of

new and relatively unproven gas supply regions

such as the Western Overthrust Belt; and 4) the

potential shift of production from the familiar conventional sources to the less familiar unconventional sources of gas.

In reaction to this changing outlook for U.S.

natural gas supply, the House Committee on

—.——

‘The current proved reserves in the Lower 48 States would very

quickly be depleted without a constant influx of new reserves. A

failure to add substantially to reserves would soon be followed by

a major decline In gas production.

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 onshore and offshore) natural gas availability over the next few decades. The

study was to examine both conventional and unconventional sources of natural gas, review current estimates of resource bases and production

potentials, and examine key technical issues that

will affect the future development of those

sources.

This report presents the results of OTA’s study

of U.S. natural gas availability,
Ch. 1—lntroduction and Overview ● 5

OVERVIEW

There is a distinct possibility that the United

States’ traditional domestic sources of natural gas,

with only modest help from supplemental sources,

will be sufficient to maintain present levels of gas

usage for the next few decades. In fact, the projection of only moderate rates of decline in production from these traditional sources, barring

any collapse of drilling activity, appears to have

a growing consensus among gas analysts. OTA

concludes, however, that this is not the only

plausible future course for U.S. natural gas availability; it is also quite possible that gas supplies

from current sources will decline considerably

more sharply over the next few decades than

predicted by most recent forecasts. In other

words, the uncertainty of both the future production and total recoverable resources of natural

gas is still high, and the range of plausible gas

“futures” is greater than is generally acknowledged. Thus, complacency about U.S. natural gas

availability over the next few decades would be

an error. If the United States wants to be confident about the availability of a continued high

level of gas supply for the next few decades, it

must ensure that it can gain access to significant

new sources of supply in case its traditional supply

turns downward.

In addition to “conventional” gas obtainable

at current prices with available technology, the

United States has substantial gas resources that

can come into production only with improved

recovery technologies or higher gas prices, or

both, This gas resides in tight gas reservoirs, in

Devonian shales, in coal seams, and in harderto-produce conventional-type gas reservoirs.

Also, there are substantial possibilities for expanded gas imports. For each of these alternatives, the magnitude of the recoverable resource

base and, for the new sources, the time required

to reach high production (or import) levels are difficult to assess. Given the uncertainties about

future production, reliance on only one or two of

the alternatives might expose the United States to

future gas supply shortages. Instead, a diversified

development strategy that allows for access to all

potential gas sources appears most desirable. OTA

believes that the probability of obtaining adequate

gas supplies is high if such a strategy is pursued.

Conventional and Unconventional Gas

Conventional natural gas is gas that is recoverable using technology that is either currently available or is a modest extension of current technology, at prices similar to or slightly higher than

today’s. Virtually all of the resource estimates of

“remaining recoverable U.S. gas resources”-

including the well-known resource estimate published by the U.S. Geological Survey9

–are meant

to be estimates of conventional gas only.10 Consequently, OTA’s analysis of future conventional

gas supplies excludes gas whose recovery depends on new technologies that are not readily

foreseeable extensions of existing technologies,

or well head prices much higher than today ’s. In

addition, in order to focus on technical rather

than market uncertainties in the supply of conventional gas, the analysis assumes that demand

for gas is high enough that exploration and production are not curtailed because of soft markets.

Consequently, “pessimistic” scenarios examined

in the analysis of conventional supply reflect only

pessimism about technical prospects for gas discovery and production and do not reflect the possibility that low gas demand may drive down exploratory drilling, discovery rates, and production.

Also, the analysis cannot account for any effects

that higher gas prices and advancing technology

may have on expansion of conventional production into deeper and more hostile waters and

other geologically conventional but (currently)

uneconomic formations.

Unconventional gas is produced from reservoirs

that are different in geologic character from conventional gas reservoirs, and requires higher gas

prices or significant advances in production technology—or both—for its economic recovery.

Thus, in examining unconventional gas supplies,

OTA has relaxed the price and technology assumptions adopted for evaluating conventional

9G. L. Dolton, et al., Estimates of Uncl/sco\+ered Reco\erab/e Conventional Resources of Oi/ and Gas in the Urr\ted States, U.S. Geological Sur\ey Circular 860, 1981.

10However, It IS ce~a i n that these estimates do i nc I ude some gas

that might be characterized as unconventional. Because some production of tight sands gas and gas from Devon Ian shales ha~

occurred In the pa~t and occurs today, the houndary between ‘ ‘conk entional ’ and ‘ ‘unconventional” is ambiguous.
6 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

gas supply. Unconventional gas sources include

gas from Iow-permeability11 sandstone and limestone formations (so-called “tight gas”), Devonian shales, coal seams, and geopressurized aquifers. Recently, gas vented from deep within the

Earth (“deep source gas”) and gas hydrates–gas

trapped with water in an ice-like state—have been

added to the “unconventional” category. (See

box A for definitions of the individual unconventional sources.) Of these six unconventional

sources, three—tight gas, Devonian shale gas, and

coal seam methane—generally are considered to

be the most likely to play a significant role in U.S.

gas supply within the next 20 to 30 years. OTA

I I permeability is a Measure of how easily Iiqu ids and gases flow

through porous rock. Thus, low-permeability rock is rock through

which liquids and gases may flow only with difficulty.

has chosen to focus its analysis on these three

sources.

Projections of Future Production

OTA finds that, even if the uncertainties about

future gas prices and markets could somehow be

eliminated, the technical and geological uncertainties associated with the gas resource base and exploration process are too great to allow a reliable

consensus to be established about a single “most

likely” estimate of future annual gas production.

For the production of conventional gas, a credible range for Lower 48 State production levels in

the year 2000 is 9 trillion to 19 trillion cubic feet

per year (TCF), assuming gas demand remains high

and gas prices do not soar. This range encom-
Ch. 1—Introduction and Overview ● 7

passes drastically different conceptions of the role

of conventional natural gas in the United States’

future energy supply. The width of the range

reflects uncertainties about the magnitude and

character of the remaining conventional resource,

the appropriate interpretation and extrapolation

of past discovery trends, and the production rates

possible from reserves not yet discovered.

Projections of unconventional/ gas production

suffer from many of the geologic uncertainties

associated with projections of the conventional resource, but in a more severe form because there

has been less information-gathering and because

measurement of geologic parameters generally is

more difficult in the unconventional fields. I n addition, these projections are confounded by difficulty in forecasting the rate of development of

newly emerging production technologies and by

the lack of an extensive production history to provide guidance about the shape of future production. Furthermore, because of the technological

risks, the pace of development of the unconventional gas sources will be particularly sensitive to

gas prices and to the availability of lower risk prospects for conventional gas production.

In light of these uncertainties, OTA believes that

the year 2000 production of unconventional tight

gas, over and above production in areas being developed today, could range anywhere from 1 to

4 TCF/yr or perhaps even higher, depending on

gas prices, conventional gas production, the pace

of tight gas research programs, and the outcome

of numerous geological and technological uncertainties. Similarly, new Devonian shale production could range from negligible amounts to about

1.0 to 1.5 TCF/yr by the year 2000. At this time,

the technical uncertainties associated with producing coal seam methane are too great to provide a usefuI estimate of future production from

this resource.

In addition to domestic Lower 48 production,

the United States can supplement its gas supply

with pipeline i reports from Canada and Mexico,

and imports of liquefied natural gas (LNG) from

a variety of suppliers. Also, there is the possibility of pipeline or LNG deliveries of natural gas

from Alaska. OTA has examined available estimates of future pipeline gas imports and Alaskan

gas deliveries to the U.S. Lower 48 States; these

estimates range from 1 to about 6 TCF/yr by 2000.

LNG imports are even less certain, and were not

projected. Factors affecting gas imports include

the U.S. domestic gas supply balance, gas prices,

and the export policies and energy supply situations of the exporting nations.

The separate projections of conventional gas

production, unconventional gas production, and

gas imports cannot simply be added together to

yield a projection of total U.S. natural gas availability, because the projections have different

baseline assumptions and because the projections

are not independent—the gas volume attained by

any one of the sources affects and is affected by

the volume attained by the others. The nature

of this interdependence is that neither the

“lows’ ’-the pessimistic estimates–nor the

“highs’ ’-the optimistic estimates–are likely to

occur together in the same scenario.

Year 2000

Resource production, TCF/yr

Conventional gas . . . . . . . . . . 9-19

Tight gas . . . . . . . . . . . . . . . . . 1 -4+

Devonian shale gas . . . . . . . . 0-1.5

Coal seam methane . . . . . . . . unknown

imports and Alaskan gas . . . . 1-6+

The Gas Resource Base

Uncertainties about the magnitude and character of the conventional and unconventional gas

resource bases are an important source of uncertainty in projections of future gas production.12

For conventional gas, the critical areas of uncertainty include the:

role of small gasfields, which up to now have

provided an extremely small share of cumulative production and proved reserves;

potential of deep onshore gas, and gas in

frontier areas such as the Eastern and Western Overthrust Belts, the eastern Gulf of

Mexico, the Georges Bank, and elsewhere;

potential for obtaining substantial quantities

of additional gas from older gasfields; and

the possibility of finding large quantities of

gas in stratigraphic traps13 bypassed by old

exploration methods:

I zTh I ~ I $ not a trl~,lc] I qa tement. It the resource base were suHclently large, u ncertal nty about the rnajorlt y of It stl II might not attect projections of near-term production, which presumably will

draw trom the best-understood portion of the base.

I JSrrC2tlgrcqph;c traps: t ra Ps, 1.e., geologic barriers that ‘ ‘trap’ gas

and 011 and allow, them to accumulate, formed by gradual chan~et

i n the permeahl Iity of sedimentary layers rather than by (more ea$l Iy

detected) abrupt structural shifts and deformation of the layers.
8 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

In addition, there remain challenging questions

about the appropriate interpretation of past trends

in gas discovery and their usefulness in projecting remaining discoveries. Accounting for these

uncertainties, OTA concludes that a reasonable

range for the remaining conventional gas resource

in the U.S. Lower 48 States is 430 to 900 TCF. Because the definition of “conventional” includes

price and technology constraints, however, this

range is conservative; it excludes gas in deepwater offshore areas, in deep onshore formations,

and in small fields that will be added to the economically recoverable resource base by future

gas price increases and technological advances.

Three unconventional sources are examined

in this report. Of the three, tight gas generally is

considered to have the largest recoverable resource base. Because tight formations often occur

in basins that have undergone much conventional gas development, and because considerable

development of relatively tight gas has already

occurred, there is a substantial base of information from which to project the tight gas resource.

The primary areas of remaining uncertainty associated with the tight gas resource base magnitude

include:

●

●

●

the volume of recoverable gas present in the

Northern Great Plains and in the numerous

tight gas basins that are unexplored or lightly

explored;

the ability of well stimulation technologies

to allow production from low-permeability

“lenses” (small, discontinuous reservoirs

that occur in large, thick formations) that are

not penetrated directly by the wellbore

(without such “remote” production, much

of the tight resource will not be economically recoverable except at extremely high

gas prices); and

our future ability to create very long fractures at low costs.

In addition, the size of the tight gas recoverable

resource is quite sensitive to gas prices and to required rates of return. Given the uncertainties

associated with all the above factors, the tight gas

140f the several existing estimates of the tight gas resource, on IY

one–the study by the National Petroleum Council—has attempted

to estimate the resources in the unexplored/lightly explored basins.

recoverable resource will most likely be in the

range of 100 to 400 TCF. A more optimistic—but

still plausible—view held by some industry scientists would raise the high end of the range by

a few hundred TCF.

Devonian shale gas, like tight gas, has a considerable history of production, but its development has been more constrained both in area and

in technological innovation, and there is less information available for a reliable estimate of recoverable resources. In particular, until recently,

resource appraisers did not have the reservoir

modeling capabilities that are available to assessors of tight gas resources. primary areas of uncertainty include: basic geological/resource characteristics of areas outside the current limited

development area; the potential recovery efficiency available with new stimulation technologies and improved drilling patterns; and the potential for economic recovery from areas that do

not have well-developed natural fracture systems.

Given these uncertainties, a moderately conservative range for the Devonian shale recoverable resource is 20 to 50 TCF for the Appalachian Basin,15

with a reasonable potential for up to 80 or 100

TCF with high gas prices and successful technology development. in addition, there is some potential to add considerably to the recoverable resource if a means is found to produce from the

unfractured part of the shale.

Coal seam methane has not been extensively

developed to date, although there are small development efforts in the Black Warrior Basin in

Alabama, the San Juan Basin in New Mexico, and

elsewhere. It is the Ieast understood of the three

resources, with important uncertainties associated with the basic characteristics of the coal resource, the gas production mechanisms, and the

possibilities for and characteristics of new stimulation methods. In addition, access to the gas residing in shallow, minable coal seams is hampered

by concerns about ownership of the gas and the

possibility that well stimulation (fracturing) will

damage the integrity of the rock overlying the

coal seam, adversely affecting mine safety. ExI sL~ss is known about the two other Devonian shale basins, the

Michigan and Illinois Basins. However, recoverable resources appear !ikely to be considerably smaller than those in the Appalachian

Basin,
Ch. 1—Introduction and Overview 9

isting resource estimates are crude, and although

it seems likely that the recoverable resource will

be at least a few multiples of 10 TCF, the range

of possible resource values probably extends, at

least speculatively, up into the 100s of TCF at high

gas prices.

Recoverable

Resource resource, TCF

Conventional gas . . . . . . . . . . 430-900+

Tight gas . . . . . . . . . . . . . . . . . 100-400+

Devonian shale gas . . . . . . . . 20-100+

Coal seam methane . . . . . . . . 20-200 +

Natural Gas and Energy Policy

The resource and production estimates have

implications for national energy policy. One of

the more important is that any policy that would

tend to restrict U.S. gas availability to “conventional” gas supplies—e.g., a policy that restricted gas prices to below market levels and thus

discouraged technology development–would

strengthen the possibility that natural gas could

be in short supply by the 1990s. This is because

the lower end of the range of year 2000 production potential for conventional gas is 9 TCF/yr,

far below expected gas requirements. A willingness to let gas prices seek a market level and

an active encouragement of technology development and the exploitation of new gas sources

would make it more likely that any shortfall of

conventional gas could be made up by alternative

gas sources.

The total recoverable gas resource base will respond to price increases and technology advances in a number of ways. First, as noted

above, the boundaries—and thus the magnitude—of the conventional gas resource base will

expand with higher prices and improved technology. These boundaries are defined by maximum

water depth, minimum exploitable field size,

maximum feasible drilling depth as a function of

field size and geology, minimum “pay” (gasbearing) thickness, and so on.16 Not only will formerly uneconomic fields and reservoirs now be

developed, but measures will be taken to increase

gas recovery from fields and reservoirs whose de16An Ongol ng OTA study, Technology for De~’eloping Offshore

0// and Gas Resources In Hos/1/e Environments, is examining one

of these ‘ ‘bound aries. ”

velopment would have been less intensive under

the old conditions. In fact, because gas prices in

some fields have been controlled at below-market

rates, gas recovery could be increased merely by

allowing gas from these fields to obtain today’s

free market prices. OTA calculated the potential

increase in recoverable gas from decontrol of the

price-controlled fields, over and above increases

already programmed into existing legislation, to

be 19 to 38 TCF.17

Second, the magnitude of the unconventional

gas recoverable resource base will increase substantially with higher gas prices and advances in

recovery technology. For example, current studies

imply that doubling gas prices from today’s levels

would approximately double the recoverable

tight gas resource with present technology. Similarly, solving the numerous remaining technical

problems associated with the unconventional

resources—improving logging techniques, expanding effective fracture lengths and increasing

fracture efficiencies, developing accurate reservoir simulation models, and so on—will allow

higher recovery efficiencies and open up more

difficult areas to commercial exploitation. (See

box B for a list of technical requirements for developing the unconventional gas resources.) With

tight gas, which has already seen considerable

commercial exploitation and technology development, further technology development still

holds the promise of expanding the recoverable

resource by 40 percent or more. With Devonian

shale gas and coal bed methane, further technology development holds the promise of even

larger gains.

Another important conclusion is that, given the

high risks and long Ieadtimes necessary to establish new sources of supply, the United States

should place a high premium on providing an early

warning of any impending shifts in gas supply.

Comprehensive data collection and gas supply

analysis capabilities exist outside of the Federal

Government, for example, in organizations such

as the American Gas Association and Gas Research Institute. The perspectives of these organizations and the uses to which they put their

forecasts may be quite dissimilar to the perspec-

‘ ~At a market price of $3,50/JMCF (1 983 dollars),

38-742 0 -85 - 2
10 ● U.S. Natural Gas Availability: Gas Supply Through the year 2000

tive and required uses of the Government, however. Consequently, Congress may not wish to

rely solely on such organizations for warnings

about impending supply problems, Inside the

Federal Government, the Energy Information Administration plays the critical role in collecting

and analyzing natural gas supply statistics. MainHOW THIS REPORT IS

The remainder of the report is organized as

follows:

@ Part l—Conventional Gas Supplies:

– Chapter 2: Summary--Availability of Con- –

ventional Gas Supplies summarizes OTA’s

major findings about future production of

conventional gas, the magnitude of the conventional gas resource base, and the potential for gas imports to the Lower 48 States. —

– Chapter 3: Natural Gas Basics presents a

brief review of basic natural gas terminology

and concepts.

– Chapter 4: The Conventional Natural Gas

tenance of ElA’s capabilities in this area, as well

as protection of its independence from the Department of Energy policymaking apparatus

should be considered a high priority by those

valuing an independent warning system for future

supply problems.

ORGANIZED

uates a number of critical resource issues,

and presents OTA’s conclusions about the

magnitude of the remaining resource base.

Chapter 5: Conventional 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: Gas imports–Overview briefly

reviews the prospects for gas imports to the

Lower 48 States–liquefied gas imports and

pipeline imports from Alaska, Canada, and

Mexico.

Resource Base reviews resource assessment ● Part n-Unconventional Gas Supplies:

methodologies, describes and critiques sev- – Chapter 7: Introduction and Summary–

eral specific gas resource assessments, eval- Availability of Unconventional Gas Supplies
Ch. 1—introduction and Overview . 11

briefly defines the unconventional gas resources, describes the definitional problem

of separating unconventional from conventional gas, and introduces the major uncertainties in defining the resource base and

production potential, then describes the

technologies for producing unconventional

gas and summarizes OTA’s findings about

the size of the resource base and the future

production potential for this gas.

– Chapter 8: Tight Gas describes the tight gas

resource and the technology necessary to

exploit it, and discusses and evaluates projections of the resource base and future production.

– Chapter 9: Gas From Devonian Shales and

Chapter 10: Coalbed Methane duplicate

chapter 8 for these two resources.
Part I

Conventional Gas Supplies*

● The material in Part I is based on: U.S. Natural Gas Availability: Conventional Gas Supply Through

the Year 2000—A Technical Memorandum (Washington, DC: U.S. Congress, Office of Technology

Assessment, OTA-TM-E-12, September 1983). At the time of publication of the technical memorandum, data on natural gas production and reserves were available through 1981. Currently, data are

available through 1983. A portion of the material in Part I has been revised and updated to take account of this new data. However, the two additional years of data generally do not change the conclusions of Part I as originally presented. A small exception is the raising of the lower bound of year

1990 production potential from 13 to 14 TCF.
Chapter 2

Summary: Availability of

Conventional Gas Supplies
Contents

Page

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Major Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Natural Gas Production Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Uncertainty 1: The Gas Resource Base . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Uncertainty: Interpretation and Extrapolation of Discovery Trends . . . . . . . . 23

Uncertainty 3: Production From Proved Reserves—The R/P Ratio . . . . . . . . . . 24

Summary of Assumptions and Conditions Underlying OTA’s Projections . . . . 25

TABLES

Table No.

1. Gas Production Forecasts. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2. Alternative Estimates of Remaining Conventional Natural Gas

Resources in the U.S. Lower 48 States. . . . . . . . . . . . . . . . . . . . . . . . .

3. Bases for OTA’s Projections of Natural Gas Production—Baseline

Assumptions: Good Market Conditions, Readily Foreseeable Technology . . .

FIGURE

Figure No.

2. Alternative Concepts of the Natural Gas Production Cycle

If Remaining Resources = 400 TCF . . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

. . . . . . . 19

. . . . . . . 19

 . . . 25

Page

. . . . . . . 20
Chapter 2

Summary: Availability of Conventional Gas Supplies

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 1960s, 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 of 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?

Part I of this report presents OTA’s assessment

of the future prospects for the discovery and production of conventional natural gas in the Lower

48 States. This assessment 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

Part I also summarizes the prospects for additional conventional supplies to the Lower 48 from

pipeline imports from Canada and Mexico, Alaskan gas, liquefied natural gas (LNG) imports, and

synthetic gas from coal.

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 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.

● 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

so well known that there is a substantial con17
18 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

sensus 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 430 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.

● Assureing market conditions generally 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 14 to 20 TCF/yr.

● Because it is unclear whether the recent

surge in the rate of additions to proved gas

●

●



reserves’ is sustainable, the range of plausible annual reserve additions is wide even for

the near future. The range for the Lower 48

States for 1987 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 v. 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 generally favorable to

gas exploration and production, but assuming

that real gas prices do not rise well above today’s

levels, 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 14 to 20 TCF/yr. Current annual production is about 17 to 18 TCF/yr and actual production capacity is probably at least 1 or

2 TCF/yr higher. 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 private institutions and individuals,

and Government agencies. A striking feature of

this group of forecasts is that 13 of the 15 forecasts that project a year 2000 production level

fall within 77 to 75 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. the magnitude and character of the gas resource base;
Ch. 2—Summary: Availability of Conventional Gas Supplies . 19

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

Government

Oil companies Other private agencies Average OTA

1985

Lowest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.0 15,5 16.5 — —

Average . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.7 17.1 17.3 17.9 —

Highest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.5 18.3 18.0 — —

1990

Lowest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13.9 13.6 14.3 — 14

Average . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.1 15.4 15.1 16.7 —

Highest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.8 17.7 15.5 — 20

2000

Lowest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8.9 11.6 12.8 9

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

—

13.5 12.2 13.1 13.1 —

Highest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14.6 13.5 13.5 — 19

Number of individual forecasts . . . . . . . . . . . . . . . . . 9 6 5 — —

NOTE: All forecasts calculate gas on ’’dry’’ basis at standard temperature and pressure, Some forecasts include unconventional sources of supply, such as tight sands

and Devonian shales; others include only conventional sources.

SOURCE Office of Technology Assessment, based on data in Jensen Associates, Inc., “Understanding Natural Gas Supply in the U.S.,’’ contractor report to the Office

of Technology Assessment, April 1983

2. the appropriate interpretation and extrapelation of past trends in natural gas discovery, and;

3. the rapidity with which gas in proved reserves can be produced, expressed as the

reserves-to-production ratio.

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 process of

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

Table 2.—Alternative Estimates of Remaining

Conventional Natural Gas Resourcesa in the

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

Trillion

Source b (publication date) cubic feet

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

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

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

Shell (1984) . . . . . . . . . . . . . . . . . . . . . . 525

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

US. 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 include gas not recoverable by current or readily foreseeable

btechnology nor gas not recoverable at price/cost ratios similar to today ’s.

In most cases, the sources for these estimates were assessments of either the

ultimately recoverable resource or the undiscovered resource base, The

estimates shown are derived by subtracting cumulative production from

estimates of ultimately recoverable resource or by adding proved reserves and

expected growth of known fields to estimates of the undiscovered resource,

Where ranges of resource estimates are given by the source, the estimate in

this table is based on the mean value,

SOURCE: Office of Technology Assessment, 1983

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

magnitude—although this does not rule out the

possibility that production may be sharply constrained by the character of the remaining re-
20 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

sources. 2 In contrast, estimates at the lower

end—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, 2). Therefore, selection of a “best” resource estimate, or

narrowing of the range, could conceivably have

profound implications for expectations of future

gas production.

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

2For ~xample, by their location, depth, degree Of contamination,

and size distribution of fields and reservoirs.

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. s —

3Th is does not imply, of course, that some normalization cannot

be accomplished. For example, PGC has incorporated into its reFigure 2.-Alternative Concepts of the Natural Gas Production Cycle lf Remaining Resources = 400 TCF

(conventional gas only)

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 producers work extremely hard to maintain production at high

levels for as long as possible. But even in this situation, production 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 typically release small quantities of gas over

long periods of time.

1900 1920 1940 1960 1980 2000 2020 2040 2060 2080 2

Year

00
Ch. 2—Summary: Availability of Conventional Gas Supplies ● 21

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 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

——

source 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/u nconventional boundaries of the assessments

should reduce the differences between PGC’S estimate and those

of USGS and RAND.

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 delaying well abandonments, either by reworking damaged wells or by merely

continuing operation to lower abandonment

pressures, drilling at smaller spacing to locate gas

pockets that otherwise would not be drained,

fracturing the reservoir rock to allow recovery

from low permeability portions of fields, and expanding development to formerly subeconomic

portions of fields. Currently, estimates of the potential increase in recoverable resources range

from a few TCF to about 50 TCF.

OTA has examined this issue in some detail.4

We concluded that the potential additional re4See Office of Technology Assessment, ‘‘Staff Memorandum on

the Effects of Decontrol on Old Gas Recovery, ” February 1984.
22 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

serves that may be obtained from older fields, if

gas in these fields can obtain a market price of

$3.50 to $4.50/MMBtu, is about 43 to 65 TCF.

Because the NGPA maintains low controlled

prices in many older fields, the likely reserve increase with no legislation changes or other new

incentives is somewhat lower: 20 to 35 TCF, with

some possibility of additional reserves from the

current price incentives for “stripper” (low production) wells and production enhancement

measures. The above estimates include reserves

from delayed abandonment, drilling at smaller

spacing (infill drilling), and fracturing and other

well stimulation measures, but do not include reserves that might be available from expanding development onto formerly subeconomic portions

of fields.

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. Some of

these doubts must be tempered, however, by recent declines in drilling costs and the continued

advance of deep drilling technology and expertise. 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 expensive 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 of sedimentary layers rather than by abrupt

structural shifts and deformation of the Iayers. 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.
Ch. 2—Summary: Availability of Convention/ Gas Supplies . 23

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 430 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 1990s. 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 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’’).s

5

This last category of reserve additions may be negative.

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 “indicator s,” 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 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
24 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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,6 reserve additions have

surged to over 20 TCF7 in 1981 and over 17 TCF

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

wouId 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 high secondary discoveries. Alternative or additional causes of the recent increases in secondary 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 short-term 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 wouId 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. s

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

1987. 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. . . . . . . . . . . . . . , . . . . . . . . . . . . 0-+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

6As reported by the American Gas Association.

7As 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.

BThe 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.
Ch. 2—Summary: Availability of Conventional Gas Supplies ● 25

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 1946.9

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 off9

The recent cutbacks in gas production because of weak demand

have temporarily raised R/P even though production capacity has

not necessarily fallen.

Table 3.—Bases for OTA’s Projections of Natural Gas

shore 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.

Summary of Assumptions

Conditions Underlying

OTA’s Projections

and

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.

Production-Baseline Assumptions: Good Market

Conditions, Readily Foreseeable Technology -

9 TCF/yr in 2000 19 TCF/yr In 2000

1. Magnitude of remaining resources:

430 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

stratigraphic 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 1987:

New field discoveries: 1.5 TCF

Extensions and new pool discoveries: 6.0 TCF by 1987

Revisions: O

6. R/P Ratios:

9.5 by 2000, predicated on lower permeability reserve

additions, difficult production conditions.

900 TCF

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 stratigraphic 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 —.An exploratory campaign based on a cohesive geologic idea.

SOURCE Office of Technology Assessment, 1983.

38-742 0 -85 - 3
26 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

OTHER SOURCES OF LOWER 48 SUPPLY

Aside from domestic conventional gas production, gas consumers in the Lower 48 States may

have access to other sources of supply, including

production from so-called unconventional

sources (tight sands, coal beds, gas in geopressurized aquifers, and Devonian shales); pipeline

imports from Alaska, Canada, and Mexico; LNG

imports from a variety of gas-producing nations

throughout the world; and synthetic natural gas

from coal and biomass. The potential supply from

unconventional sources is discussed in Part II of

this report. OTA previously discussed synthetic

natural gas in a report released in 1982.10

The United States currently imports about 0.8

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

lo/ncrea5& Automobile Fuel Eficiency and Synthetic Fuels: Alternatives for Reducing 0;/ Imports (Washington, D. C.: U.S. Congress,

Office of Technology Assessment, OTA-E-185, September 1982).

sources, like future domestic production, is subject to considerable uncertainty. High transportation 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 5.7 TCF11 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.

I I This estimate is derived by adding individual estimates for each

of the three import categories. This simple addition may overstate

the range somewhat because the categories are not independent.

For example, high levels of Canadian gas imports might serve to

dampen prospects for Alaskan gas, so it is not certain that the “high”

Canadian and Alaskan projections are compatible with each other.
Chapter 3

Natural Gas Basics
Contents

What Is Natural Gas? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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

Where Is Natural Gas Found? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

How is Natural Gas Discovered?.

How Is Natural Gas Produced? . .

Table No.

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TABLES

29

29

30

32

35

Page

4. Estimated Total U.S. Proved Reserves of Natural Gas–1977-83. . . . . . . . . . . . 34

FIGURES

Figure No. Page

3. Known oil-and Gas-Bearing Areas in the Lower 48 States . . . . . . . . . . . . . . 31

4. Four Requirements for Petroleum Accumulation. . . . . . . . . . . . . . . . . . . . . . . 31

5. Trapping Mechanisms. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

6.AAPG and APl Classification of Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

7. Production Mechanics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Chapter 3

Natural Gas Basics

This chapter briefly describes basic theories and how discoveries are reported. Words in boldface

terminology used within the report-i. e., it briefly are defined in Appendix D: Glossary. Readers fadescribes what natural gas is, how it is formed, miliar with basic terminology and concepts of nathow it is found and subsequently produced, and ural gas supply may wish to skip this section.

WHAT IS NATURAL GAS?

As its name implies, natural gas is a naturally dustry. Associated heavier hydrocarbons such as

occurring mixture of hydrocarbon and nonhydro- ethane, propane, and butane and impurities such

carbon gases found in subsurface reservoirs as water, hydrogen sulfide, and nitrogen occur

within the Earth’s crust. Methane (CH4

, a light with the methane. If the concentrations of these

hydrocarbon, is the primary constituent of natu- other constituents render the gas unmarketable,

ral gas and of principal interest to the energy in- they must be removed prior to use.

HOW DOES NATURAL GAS FORM?

There is no universally accepted explanation

of how natural gas formed. Most hydrocarbon deposits of significant size have been discovered in

sedimentary basins, however, and generally 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. I n 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 may

also have been formed by other processes: by

the anaerobic (without oxygen) digestion of

organic materials by bacteria at relatively low

temperatures, and inorganically by the chemical

transformation of carbon compounds at high

pressures and temperatures deep within the

Earth. The fraction of natural gas that is bacteriagenerated gas, usually called biogenic gas, is at

issue, but estimates range to as high as 20 percent or more. ] As for the “deep earth gas, ” a major controversy exists as to whether or not this

gas even exists. According to arguments by

Thomas Gold and Steven Soter of Cornell University, most naturally occurring methane is of inorganic origin and vast reserves remain to be discovered at depths below 15,000 ft.2

Temperature and pressure conditions play 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,

] D. D. Rice and G. E. Claypool, “Generation, Accumulation, and

Resource Potential of Biogenic Gas, ” AAPG f?u//etin, vol. 65, No.

1, January 1981.

2

T. Gold and S. Soter, “Abiogenic Methane and the Origin of

Petroleum, ” Energy Exploration and Exploitation (city, st: Graham

& Trotman, Ltd., 1982).

29
30 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

where lower temperatures are characteristic.3

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

ft, with light hydrocarbon liquids occurring at

depths greater than 9,500 ft.4 Biogenic gas is usu-

. —3-— —

H. Douglas Klemme, Geotherrna/ Gradients, F/eat How, and Hydrocarbon Recovery. Petroleum and Global Tectonics (Princeton

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

Jensen Associates, Inc., Understanding Natural Gas Supply in the

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

4B. P. Tissot and D. H. Welte, Petroleum Formation and Occurally found at depths of a few hundred to a few

thousand feet, because it is formed at the low

temperatures that accompany shallow burial and

rarely is generated at depths greater than 3,000

ft.5

rence (New York: Springer-Verlag, 1978), p. 202. Cited in Jensen

Associates, Inc., op. cit.

sRice and Claypool, op. cit.

WHERE IS NATURAL GAS FOUND?

Petroleum accumulations occur as reservoirs

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

mass but in the minute pore spaces between the

particles that compose the rock. The greater the

amount of pore space in the rock (porosity), the

larger the quantity of gas or oil that may be contained within it. Pools often occur together in a

field, and multiple fields in similar geologic environments constitute a province.

Gas occurs separate from (nonassociated gas)

and together with oil. When together, it occurs

in solution with the oil (dissolved gas) or, when

no more gas can be held in solution under the

pressure and temperature conditions of the reservoir, as free gas (associated gas) in a gas cap.

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.

Sedimentary rocks compose about 75 percent of

the exposed rocks at the surface, but onlys percent of the Earth’s crust (outer 10 miles) . The

known oil- and gas-bearing areas in the United

States are identified in figure 3.

Commercial petroleum accumulations are not

usually found in the source rock. Source rocks

are generally of too low a permeability, 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 has

formed, the gases and fluids (oil and formation

water) migrate from the source bed to a more

permeable rock, called the “reservoir rock” (this

process is called “primary migration”). The fluids

move in the path of least resistance (or highest

permeability) and continue migrating within the

reservoir rock (secondary migration) until an impermeable barrier is encountered, which prohibits further migration into adjacent or overlying

rock units or formations. The petroleum then

migrates 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 pictorially

in figure 4.

There are three basic types of petroleum traps:

structural, stratigraphic, and combination (see

fig. s). 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 petroleum.

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.
Ch. 3—Natural Gas Basics 31

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

Figure 4.—Four Requirements for

Petroleum Accumulation

Water layer,

Impermeable barrier:

-Reservoir rock:

organic-rich shale

SOURCE: Office of Technology Assessment
—

32 . U.S. Natural Gas Availability: Gas Supply Through the year 2000

Figure 5.-Trapping Mechanisms

Structural trap–fault

Gas

accumulation

Stratigraphic trap—pinched-out bed

Gas

accumulation

Combination trap—salt intrusion

Gas

accumulation

SOURCE: Office of Technology Assessment.

HOW IS NATURAL GAS DISCOVERED?

Before an understanding of subsurface geology

was acquired or rules of petroleum occurrence

were established, petroleum discoveries were

based on surface seeps, knowledge gained from

water well drilling, and luck. Today there are a

variety of concepts, exploration methods, and instruments available to help geologists locate subsurface hydrocarbon accumulations.

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
Ch. 3—Natural Gas Basics . 33

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 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

Figure 6.—AAPG and API Classification of Wells

SOURCE, Lahee classification of wells, as applied by the Committee on Statistics of Drilling of the American Association of Petroleum Geologists, and the American

Petroleum Institute Developed by Frederic H Lahee in 1944.
34 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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 subracted 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 by the EIA, U.S.

Crude Oil, Natural Gas and Natural Gas Liquids

Reserves–Annual Report.

*EIA began its data series in 1977. The American Gas Association and American Petroleum Institute also published reserve statistics in basically the same format (without a “corrections and adjustments” category) from 1966 to 1979, and in a somewhat different

format from 1947 to 1965,

Table 4.–Estimated Total U.S. Proved Reserves of Natural Gas–1977-83

Net of New reservoir Proved Net

corrections Revision Revision Extensions to discoveries New field Total reserves b

change from

& adjustments increases decreases old reservoirs in old fields discoveries discoveries 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

1982 . . 2,378 19,795 19,340 8,349 2,687 3,419 14,455 17,506 201,512 –218

1983 . . 3,090 17,602 17,617 6,909 1,574 2,965 11,448 15,788 200,247 .1,265

NOTE: “Old” means discovered in a prior year. “New” means discovered during the report year. aColumn 4 + Column 5 + Column 6.

bPrior year Column 9 + Column 1 + Column 2 – Column 3 + Column 7 – COIU Mn 8

cBillion cubic feet, 14,73 psia, 60° F.

dConsists only of reported corrections.

eBased on following year data only.

SOURCE’ Energy Information Administration, US. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves-1983 Annual Report, DOE/EIA-0216 (83), October 1984.
Ch. 3—Natural Gas Basics ● 3 5

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. When the

reservoir rock is of low permeability, the rock

may be artificially fractured to form pathways to

the well bore. This is accomplished either with explosives or by hydraulic means, pumping a fluid

under pressure into the well.

Production can 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

u rider 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

*However, the requirement that the revenues generated by gas

sales at least match the expense of operating the well generally WIII

force an end to production before the flow of gas actually ceases.

Figure 7.— Production Mechanics

Barrier rock

-Reservoir rock

Gas and water drive mechanism

Barrier rock

-Reservoir rock

SOURCE Off Ice of Technology Assessment

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 utility.
Chapter 4

The Natural Gas Resource Base
Page

Resource Base Concepts . . . . . . . . . . . . . . . 40

Approaches to Gas Resource Estimation . . 42

Geologic Approaches . . . . . . . . . . . . . . . . 42

Historical Approaches . . . . . . . . . . . . . . . 43

Dealing With Uncertainty . . . . . . . . . . . . 46

Comparison and Review of individual

Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . 47

U.S. Geological Survey . . . . . . . . . . . . . . 47

Potential Gas Committee. . . . . . . . . . . . . 50

RAND/Nehring . . . . . . . . . . . . . . . . . . . . . 52

Hubert. . . . . . . . . . . . . . . . . . . . . . . . . . . 54

.

Reconciling the Different Estimates . . . . . . 56

ls There a Consensus? . . . . . . . . . . . . . . . 57

I-low Credible Are the Methods . . . . . . . 60

Are the Physical Implications of the

Assessments Plausible? . . . . . . . . . . . . . 60

A Break With Past Trends? . . . . . . . . . . . 61

Some Alternative Explanations . . . . . . . . 66

Conclusions. . . . . . . . . . . . . . . . . . . . . . . . 77

TABLES

Table No. Page

5. Why It Is Difficult to Compare

Resource Estimates . . . . . . . . . . . . . . . . 41

6. Alternative Estimates of Ultimately

Recoverable and Remaining Natural

Gas in the United States . . . . . . . . . . . . 49

7. Comparison of Potential Gas Committee

Estimates of Ultimately Recoverable

Gas Resources in the Lower 48 States. 51

8. Field Discovery implications of USGS

Circular 725, Onshore Lower 48

Undiscovered Petroleum Resource . . . 54

9. Hubbert’s 1980 Estimates of Ultimately

Recoverable Gas Resources in the

Lower 48 . . . . . . . . . . . . . . . . . . . . . . . . 55

IO. The Optimist’s View of Gas

Resources . . . . . . . . . . . . . . . . . . . . . . . . 58

Table No. Page

11. The Pessimist’s View of Gas

Resources . . . . . . . . . . . . . . . . . . . . . . . . 58

12. Returns to New Field Wildcat Drilling

in the Onshore Lower 48 States,

1966-81 . . . . . . . . . . . . . . . . . . . . . . . . . . 61

13. Historical Record: Number of New

Gasfield Discoveries Proved After Six

Years To Be of Significant Size . . . . . . . 63

14. Oil and Gas Drilling Success Rates . . . 69

15. Potential Recoverable Gas Resources

From New Discoveries in the Permian

Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

16. Potential Additions to “Old Gas”

Reserves From Lowered Abandonment

Pressures, Well Reworking, Infill

Drilling, and Well Stimulation . . . . . . . 75

FIGURES

Figure No. Page

8. The McKelvey Box . . . . . . . . . . . . . . . . 40

9. Discoveries of Recoverable Natural

Gas in the Lower 48 States v.

Cumulative Exploratory Drilling . . . . . . 44

10. Probability Distribution for

Undiscovered Recoverable Gas

Resources in a Province . . . . . . . . . . . . 47

11. Number of Gasfields Discovered As a

Percentage of New Field Wildcats

Drilled, by Field Size Grouping . . . . . . 64

12. Number of Gasfields Discovered

per Year, by Field Size Grouping. . . . . 64

13. Gas Potential, Gas Well Completions,

and Expenditures–1978 . . . . . . . . . . . . 67

14. New Field Wildcat Success Rate,

1966-81 . . . . . . . . . . . . . . . . . . . . . . . . . . 68

15. Size Distribution of Discovered Oil

and Gas Fields in the Lower 48 States 70

16. Known and Projected Size

Distributions of Discovered Oil and

Gas Fields in the Lower 48 States . . . . 72
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 report 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” (1 985-2000)

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 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 l--lubber-t 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 conventional 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 Applled to the Production of Oil and Gas, ” In Oil and Gas Supply Modeling, 5. 1.

Gass (cd.), National Bureau of Standards Special Publlcatlon 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 Product Ion Cycle. ”

39
40 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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 of

the resource base—and the failure of the client

to comprehend what a resource base is, or what

a particular resource base is.

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 proporFigure 8.—The McKelvey Box

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

policy,” American Scientist, vol, 60, No. 1, 1972, pp. 32-40.

tions 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 producible. 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. 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. ’

——

ZG. I.. Do]ton, et al., Estimates of Undiscovered Recoverable Conventional Resources of Oil and Gas in the (Jnited States, U.S. Geological Survey Circular 860, 1981.

31bid.

4Potential Gas Agency, Potentia/ Supp/y of Natura/ Gas in the

United States (as of Dec. 31, 1980), May 1981.
Ch. 4—The Natural Gas Resource Base . 41

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 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

*Oil has undergone such cycles of apparent depletion followed

by large new discoveries and drastic upward revisions in resource

estimates. Two other well-known materials that have undergone

similar cycles are uranium and iron ore.

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 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 two-thirds of the box—in his estimate, although he restricts the estimate to “conventional” gas and excludes such sources as

methane in coal seams. s

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: Office of Technology Assessment, 1983.

38-742 0 -85 _ 4
42 ● U.S. /Vatural Gas Availability: Gas Supply Through the Year ,2000

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

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

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

*This section is based largely on U.S. Geological Survey Circular

860, “Estimates of Undiscovered Recoverable Conventional Resources of Oil and Gas in the United States, ” G. L. Dolton, et al.,

1981; and D. A. White and H. M. Gehman, “Methods of Estimating Oil and Gas Resources, ” AAPG Bulletin, vol. 63, No. 12, December 1979.

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).

AreaI-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
Ch. 4—The Natural Gas Resource Base ● 43

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.

The simpler methods are most useful in the

early stages of development of a basin when few

data are available and the r-teed 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 recoverable 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 cumuIative 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,

*Area = j: (amount of gas discovered per foot drilled)

d (cumulative feet drilled).
44 ● U.S. Ntural Gas Avaiability: Gas Supply Through the Year 2000

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

Expected

Reported

growth

SOURCE: David H Root, USGS.
Ch. 4—The Natural Gas Resource Base 45

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 assumption 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

*In support of this view, it is worth mentioning that neither the

major technical advances in exploration nor the opening of new

territories since World War I I were of sufficient importance to restore the 011 or gas discovery rate to pre-war levels; instead, the

discovery rate continued a fairly steady downward drift for several

decades, In seeming disregard of changing conditions and technology.

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

decades 7

–in other words, from the top twothirds 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 predicted 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

61bld.

7R. P. Sheldon, “Estimates of Undiscovered Petroleum Resources

—A Perspective,” U.S. Geological Survey Annual Report, Fiscal Year

1978.

*Discovery data generally is preferred over production data I n

a historical approach because the discovery cycle is always a few

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

the cycle consequently is less severe for discovery than for production.
46 . U.S. Natural Gas Availability: Gas Supply Through the year 2000

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 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 million8)

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

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

2, May 1982.

glbld

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, 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

——

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

finite probability 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.
Ch. 4—The Natural Gas Resource Base 47

Figure 10.—Probability Distribution for Undiscovered

Recoverable Gas Resources in a Province

Resources Q, TCF of undiscovered recoverable gas

NOTE: “More than” cumulative distribution function.

SOURCE: David H. Root, USGS.

cannot be directly added (or, in the case of estimates for volumes and yield factors, multiplied)

to form aggregate 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

C). *

——.——

“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

COMPARISON AND REVIEW

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 the Lower 48 States—244 to 916

trillion cubic feet (TCF)—implies, in turn, a wide

range in the outlook for future gas production,

especially in the longer term.

Although probabilistic methods are useful for

displaying some of the uncertainties associated

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.

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.

OF INDIVIDUAL ESTIMATES

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 probably the most widely used gas

10B, M, Miller, et al., Geo/ogica/ ~SfirTrates Of ufJdi5COVered

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

Circular 725, 1975.

I I Dolton, et a!., Op. cit.
resource estimates. The most recent estimate uses

a Delphi-type 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 historical 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’ 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’

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
Ch. 4—The Natural Gas Resource Base 4 9

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 . . . . . . . . . . . . . . 1975 — 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 966C — 340 166

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

Shell (1) . . . . . . . . . . . . 1978 946 910-1,075-1,260 320 146

Shell (2) . . . . . . . . . . . . 1984 1,150d 1,265d 525d

350d

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

PGC . . . . . . . . . . . . . . . 1983 1,542 1,711 916 742

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

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

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

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

aApproximate cumulative Lower 48 production through 1962 was 631 TCF, of which about 5 TCF is in underground storage. “Remaining resource” is “Lower 48” (ultimately

recoverable) column value minus 631 TCF plus 5 TCF.

Lower 48 proved reserves assumed to be 169 TCF on Dec. 31, 1982 (excluding underground storage). cOriginal estimate for onshore gas only. Total arrived at by adding USGS (mean) estimate for ultimately recoverable offshore gas in Lower 48 (235 TCF)

‘Estimate includes 52 TCF for additional resources obtainable with old gas decontrol.

‘Based on an analysis of finding rates by David Root, USGS.

SOURCE: Mobil—J. D. Moody and R, E. Geiger, “Petroleum Resources; How Much Oil and Where,” Technology Review, March/April 1975. Verbal comments by John

Moody at a FPC presentation, Apr. 14, 1975.

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

Gas Association, June 9-11, 1975, cited in Potential Gas Committee, A Comparison of Estimates of Ultimately Recoverable Quantities of Natural Gas In the

United States, Gas Resource Studies No. 1, Potential Gas Agency, April 1977.

Wiorkowski-J J Wiorkowski, Estimation of Oil and Natural Gas Reserves Usirn Historical Data Series: A Critical Review, unpublished manuscript, 1975,

cited in J. J Wiorkowski, ‘i Estimating Volumes of Remaining Fossil Fuel Resources: A Critical Review, “ in J. Am, Stat. Assoc., vol. 76, No. 875, September 1961

Bromberg/Hartigan-L. Bromberg and J. A Hartigan, Report to the Federal Energy Administration, unpublished manuscript, 1975, cited in Wiorkowski (1981),

noted above.

Exxon—Exxon Co , U. S. A., Exploration Department, “U.S. Oil and Gas Potential, ” March 1976. Oil and Gas Journal, “Exxon Says U.S. Still Has Vast Potential, ”

Mar. 22, 1976,

Shell (1)—C. L. Blackburn, Shell Oil Co., “Long-Range Potential of Domestic Oil and Gas,” presented at NAPIA/PIRA Fall Conference, Boca Raton, Fla., Oct.

19, 1978, Oil and Gas Journal, “Shell: Alaska Holds 58% of Future U.S. Oil Finds, ” Nov. 20, 1978.

Shell (2)—R. A. Rozendal, Convention/ U.S. Oil and Gas Remaining To Be Discovered: Estimates and Methodology Used by Shell Oil Company, draft, Aug.

1, 1964, Shell Oil Co.

IGT—J. D. Parent A Survey of United States and Total World Production, Proved Reserves, and Remaining Recoverable Resources of Fossil Fuels and Uranium,

Institute of Gas Technology, Chicago, August 1960, cited in American Gas Association, “Energy Analysis A Comparison of U S. and World Remaining Gas

and Oil Resources,” Aug,-

7, 1981.

PGC– Potential Gas Agency, Potential Supply of Natural Gas in the United States (as of Dec. 31, 1982), Colorado School of Mines, June 1983.

Hubbert (1) (2)—M, K. Hubbert, “Techniques of Prediction as Applied to the Production of Oil and Gas, “ in Oil and Gas Supply Modeling, S. I. Gass (cd,),

National Bureau of Standards Special Publication 631, May 1982.

RAND—R. Nehring with E. R. Van Driest 11, The Discovery of Significant Oil and Gas Fields in the United States, R.2654/l -USGS/DOE, RAND Corp ,

January 1981,

USGS—G L Dolton, et al., Estimates of Undiscovered Recoverable Convention/ Resources of Oil and Gas in the United States, U.S. Geological Survey Circular 660, 1981

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 economically 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

‘

z Ibid,

areas of known

elation from

growth. 13 Field

gas, and USGS

pools* by using a simple extraphistorical records of gasfield

growth is a significant source of

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

*These resources are called ‘‘inferred reserves’ i n the USGS

assessment and are equivalent to the “probable potential resources”

in the PGC assessment.

131bid, app. F,
50 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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’ 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 .14 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 is of “undiscovered recoverable conventional resources (our emphasis)” and excludes

“gas in low permeability (’tight’) reservoirs” and

other so-called 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’ Delphi

technique, described by USGS as relying on reIdpersonal communication with John Schanz, Congressional Research Service.

~SDolton, et al., Op. cit.

views 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. *

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

potential resource—876 TCF for the end of 198217

–-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 re-

———16G Dojton, USGS, presentation at RAND workshop on estimating U.S. natural gas resources, Washington, DC, Mar. 1-3, 1982.

* PGC is 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.

I 7News release,potential Gas Agency, Feb. 261 1983.

I Spotential Gas Agency, Potential Supply of Natural Gas in the

United States (as of Dec. 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

gec~logic province, and speculative gas is from formations or provinces that have not yet proven to be productive.
Ch. 4—The Natural Gas Resource Base . 51

sources, 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.”19 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 techniques 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,20

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 only.

———. ——.—.

191 bid.

* *Orr the other hand, the actual price requirements for producing deep gas under tree market conditions are uncertain, and it

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

not tar removed from today’s.

‘(’1 bid.

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.

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

*For example, the addition of the Western Overthrust Belt due

largely to advances in seismic technology, and the addition of large

amounts of gas from 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 year end 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

aApproximate—A portion of the difference between the 1980 and 1982 estimates

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

(used for the 1960 calculation) and the EIA (used for the 1982 calculation)

SOURCE Potential Gas Agency, Potential Supply of Natural Gas in the United

States (as of Dec. 31, 1980), May 1981, and Potential Gas Agency, news

release, Feb. 26, 1983
52 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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 longterm 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.21 The

assessment incorporates a variety of approaches:

ZI R. Nehri ng With E. R. Van Driest 11, The ~;SCOVerY Of S;g~;f;-

carrt Oi/ and Gas Fiekfs in the United States, RAND Corp. Report

R-2654/l-USGS/DOE, January 1981.

1.

2.

3.

4.

To estimate the growth of reserves in known

fields, a combination of methods were used,

including extrapolating by historical field

growth factors and by more analytical approaches that used available geologic information and known production practices.

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, discovery

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 historical record, however, the approach also

incorporates geologic methods based on

play analysis.

play analysis was used to estimate the resources in new plays in mature regions.

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 his-
Ch. 4—The Natural Gas Resource Base ● 5 3

torical 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

high optimism in each, with the possible exception of the frontier areas. The four hypotheses and

Nehring’s countering arguments are summarized

in box D. A more detailed discussion of these hypotheses is presented later in this chapter.

A second facet to this argument is that this exhaustion of geologic possibilities is reflected in

the recent (disappointing) history of exploratory

drilling. Nehring argues that optimistic assessBox D.—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.

c 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

● 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 forma 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: Office of Technology Assessment, based on R. Nehring, The Discoveryof Significant Oil andGas Fields in the United States, R-2654/1-USGS/OOE, RAND Corp.,

January 1981.
54 U.S. Natural Gas Availability: Gas Supply Through the Year 2000

ments simply do not bear up under the weight

of the question, “Is it likely that we will find as

many large fields as this assessment implies must

be there?” For example, table 8 presents a proposed field size distribution that would yield an

undiscovered petroleum (oil plus gas) resource

equal to that predicted in the 1975 USGS (Circular 725) onshore assessment. This distribution

would also be approximately equivalent to the

more recent 1981 (Circular 860) USGS assessment, although the more recent assessment is

slightly more optimistic. in the table, the proposed distribution is compared to actual field

discovery statistics for 1971 through 1978. The

last column shows how long it would take to find

the necessary number of fields of each size category if the annual discovery rates of 1971

through 1978 continued for the life of the resource. In Nehring’s opinion, the number of large

fields that would have to be discovered to fulfill

the USGS assessment is too large 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 additions 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, and

*However, the recent controversy over the magnitude of additional gas that might be obtainable from old gas decontrol 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.

Table 8.—Field Discovery Implications of USGS Circular 725, Onshore Lower 48 Undiscovered Petroleum Resource

Implied time to find

Potential field size Actual field discoveries USGS undiscovered resource,

distribution: USGS — constant annual discovery

Field sizea Circular 725 1971-75 1976-78 rate at 1971-78 average (years)

AAAA (>500/>3,000) . . . . . . . . . . . . . . . . 11 0 1 88

AAA (200-500/1,200-3,000) . . . . . . . . . . . . 44 0 0 Large but indeterminate

AA (100-200/600-1,200). . . . . . . . . . . . . . 94 7 1 94

A (50-100/300-600) . . . . . . . . . . . . . . . . 199 7 3 159

B (25-50/150-300) . . . . . . . . . . . . . . . . . 375 15 8 130

C (10-25/60-150) . . . . . . . . . . . . . . . . . . 977 44 22 118

D (1-10/6-60) . . . . . . . . . . . . . . . . . . . . . 6,000 455b — 66

E (< 1/<6) . . . . . . . . . . . . . . . . . . . . . . . 70,000 3,041b

115

aValues in parenthesis are size range in millions of barrels of oil equivalent (mmboe)/billions of cubic feet of gas (BCF). 1972-76 Committee on Statistics of Drilling of the American Association of petroleum Geologists.

SOURCE: Office of Technology Assessment, based on R. Nehring, The Discovery of Significant Oil and Gas Fields in the United States, RAND Corp. report

R-2654/l-USGS/DOE, January 1961. Also, personal communication, Richard Nehring.
Ch. 4—The Natural Gas Resource Base ● 55

so forth-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 (Q~) 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 167 TCF; * * if correct, it leaves only

about 70 TCF remaining to be added to reserves

from the growth of known fields (calculated by

USGS to be 172 TCF) and new field discoveries.

In other words, Hubbert’s assessment implies that

the precipitous declines of the early 1970s 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 de-

*

2Hubbert, op. cit.

* *As of the beginning of 1983.

Table 9.—Hubbert’s 1980 Estimates of Ultimately

Recoverable Gas Resources in the Lower 48

Method of estimation Q m (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 00 . . 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: Office of Technology Assessment, based on M. K, Hubbert, “Techniques of Production as Applied to the Production of Oil and Gas, ”

in 0// arrd Gas Supp/y Mode/irrg, S. 1, Gass (cd,), National Bureau of

Standards Special Publication 631, May 1982,

rived equations for the magnitudes and rates of

change of gas production and discoveries by

noting some simple boundary conditions for the

production cycIe* 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 Qm, 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

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 approximate the curve of ~ v. Q. Aside from the

criticism associated with all historical approaches

*Cumulative production Q is zero at the beginning of the cycle

and Qm at the end; the production rate ~~ is zero when Q = O

and also when Q = Q ~).

**R = C,Q + C2Q2

zJFor example, L. S. Mayer cites three: D. V. P. Harris, “Conventional Crude Oil Resources of the U. S.: Recent Estimates, Methods for Estimation and Policy Consideration, ” Makrja/s art~ socje~y

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 Production, ” 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)
56 ● U.S. Natural Gas Availability: Gas Supply Through the year 2000

–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 Q~.

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.24 Although Hubbert’s

curve for oil discovery is more satisfactory, it may

be 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 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

24 E,g., J. j. wiorkowski,1981 ~ “Estimating Volumes of Remaini ng Fossil Fuel Resources: A Critical Review, ” ). Arrr. 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 d iscovery is more advanced in its overall cycle. The less advanced, or

less “mature,” the curve, the less satisfactory will be the results.

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 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.

‘25 Harris, 197’7, Op. cit.

*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.

‘ *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 ,~t best a rough approximation. Furthermore, there are reasons

to suspect that the /ong-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 2. How credible are the methods used by the

believed? in approaching this question, OTA used assessors, in the abstract and in actual perthree criteria: formance?

3. What do the different assessments imply in

1. Is there a consensus, or even a “central terms of geology and future discoveries? Are

tendency, “ in the scientific community? these implications credible?
Ch. 4—The Natural Gas Resource Base . 57

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 i n a particuIar 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 estiBox E.—A Very Brief History

The history of petroleum exploration in general,

mates 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 predictions of scarcity followed by

radical upward revisions in resource assessments

appear to be common for nonrenewable resources (see box E). On the other hand, the USGS

of Petroleum Exploration

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 Iarge, 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 Schanz, Senior Specialist in Energy Resources Policy, Congressional Research Service.

38-742 0 -85 - 5
58 . U.S. Natural Gas Availability: Gas Supply Through the year 2000

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 F), and some of

the more important disagreements occur in areas

Table 10.—The Optimist’s View of Gas Resources

●

●

●

●

●

b

●

—

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 extention of fields to lower permeability

areas that were previously uneconomic, the lowering of

abandonment pressures, and well workovers.

SOURCE: Office of Technology Assessment

Table 11.—The Pessimist’s View of Gas Resource

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 limits of hostile environments in 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.

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

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 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.

*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 wou Id no doubt disagree strongly with values near one

extreme or the other, however.
Ch. 4—The Natural Gas Resource Base ● 59

OTA believes that the minority who might like from this end of the range. * It should be added,

the range extended would consist mainly of those however, that some of those who are considerwho believe that the upper end should be higher. ably less optimistic than PGC, and even USGS,

Furthermore, OTA suspects that a thorough re- —

view of the production implications of the lower *As shown in chapter 5, a 280-TCF remaining resource implies

end of the range—as discussed in the next chap- that the year 2000 production of Lower 48 conventional gas, reter—would tend to push many scientists away

coverable with existing or foreseeable technology and at the current cost/price relationships, cannot be much greater than 4 TCF/yr.
60 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

are major oil and gas producers—e.g., Exxon* *—

who are very familiar with most of the areas that

are supposed to supply the United States with the

‘‘optimistic’ levels of new gas discoveries.

How Credible Are the Methods?

How credible the methods are is generally difficult to determine because few resource assessments using geologic approaches reveal many

details of their assessment processes. Generally,

more details are available for the assessments

based on historical, extrapolative approaches; in

addition, USGS makes available to the public its

open-file reports and data. OTA did not attempt

to review the extensive USGS backup information because of time and budget constraints. Historical approaches have been reviewed in a number of reports,26 and for the most part OTA chose

to use these reports 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 opin-

—.. . - ——

* *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.

26 For example, Wiorkowski, oP ~it.

ion, 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 implications 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:

● Does the assessment imply a substantial

break with past and recent discovery trends

and patterns?

27R. Nehring, The Discovery of Significant Oil and Gas Fields in

the United States, op. cit.
Ch. 4—The Natural Gas Resource Base ● 61

● 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 of the four at least 400 TCF below. I n

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 ini-

*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).

Table 12.—Returns to New Field Wildcat Drilling in

tial 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 difficuIties

in interpreting the trends.

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

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

1988 . . . . . . . . . . . . . . . . . 0.24 2.66 10.25 27

1989 . . . . . . . . . . . . . . . . . 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 Nehring, “Problems in Natural Gas Reserve, Drilling, and Discovery Date,” contractor report to the Off Ice of Technology Assessment, 1983
62 U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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 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 petroleum-directed 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 differentsized 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,

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

gas field 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) gas fields in all gas discoveries

decreased over the 30-year period, while the effort required to find a significant field increased

through the 1960s 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

*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.

zeR, Nehrlng, problems in Natural Gas Reserve, Drilling, and Discovery Data, contractor report to OTA, 1983.

* +! The record stops in 197s because AAPG classifies fieids as gas

or oil fields only after the passage of 6 years past the discovery

report.
Ch. 4—The Natural Gas Resource Base ● 63

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64 ● U.S. Natural Gas Availability: Gas Supply Through the year 2000

Figure 11.– Number of Gasfields Discovered As a Percentage of New Field Wildcats Drilled,

by Field Size Grouping

1.5

1.4

1.3

1.2

1.1

Field sizes (BCF): A >300

150-300

60-150

6-60

1955 1960

Year

1965 1970 1974

SOURCE: Office of Technology Assessment, based on data from table 16 in R. R. Johnston, “North American Drilling Activity in 1961,” AAPG Bulletin, vol. 66/1 1, November

1982.

Figure 12.-Number of Gasfields Discovered per Year, by Field Size Grouping

25

1960

Year

1946 1955 1965 1970 1974

SOURCE: Office of Technology Assessment, based on data from table 16 in R. R. Johnston, “North American Drilling Activity in 1981 ,“ AAPG Bulletin, vol. 66/11, November

1982.
Ch. 4—The Natural Gas Resource Base . 65

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 1950s 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 gas fields 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).

The impression gained from table 13 and

figures 11 and 12–that finding rates for the smallto-moderate 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 gas field 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, KS/TX/OK, 36 TCF

and Panhandle, TX, 31 TCF), 1921 (San Juan, NM,

18 TCF), 1928 (Jalmat, NM, 6 TCF), 1934 (Katy,

TX, 7 TCF), 1936 (Carthage, TX, 6 TCF), and 1952

(Puckett, TX, 4 TCF).30 However, according to the

1977 International Petroleum Encyclopedia,31 no

gas fields larger than 4 TCF were found between

—

* “Apparent” because some of the wells were aimed deliberately at small targets and should not be included in the “effort”

iniolved[n t[ riding large fie{ds, As noted, however, there IS no way

to separate data about these wells from the overall data.

~’]R. R, Johnston, “North American Drllllng Activity in 1981 ,“

AAPG f?u//et/rJ, \ol 66/1 1, No\ember 1982.

* ‘Some ot these fields–Hugoton, Panhandle, San juan–are considered rnultlple fields by some analysts, one field by others. Also,

there is considerable iarvatlon In reserve estimates from one murce

to another.

lo~jll and Gas Resources Data System, Energy Information AdminIjtratlon; and J. McCasl I n (ed. ), /nternat/orra/ Petro/eum Encyc/opedM, vol. 10 [Tulsa, Okla,: Petroleum Publl~hing Co., 1977).

] 1 MC Casl i n, op, c It.

1953 and 1967, and no gas fields larger than 1

TCF were found between 1967 and 1975.***

The trends in discovery up to the mid-1970s,

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 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

* * *It IS possible, howe~er, that further growth of fwlds that were

below the 1 TCF Ie\el in 1977 could have moved them into the

“greater than 1 TCF” category In later years.
66 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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 1970s (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

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, lowpayoff 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

JzThe latest is AGA, “Gas 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.
Ch. 4—The Natural Gas Resource Base 67

shallow Lower 48 area, and deep (below 15,000

ft) horizons. Its 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 drilling costs and risks of the high gas potential frontier areas necessitate a very cautious

attitude toward drilling, whereas the lower costs

33A(JA, “Drilling Activity and Potential Gas Resources, ” Gas

Energy Review, vol. 7, No. 11, September 1979.

*Of course, an alternate 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.

34AGA, “Gas Well Drilling and Expenditures. . . ,“ op. cit.

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

Jsjensen Associates, InC., “Early Effects of the Natural Gas Policy Act of 1978 on U.S. Gas Supply, ” report to the Office of Oil

and Natural Gas, U.S. DOE, April 1981.

MR p . .O’Neill,“Issues in Forecasting Conventional Otl and Gas

Prod uction, ” in Oi/ and Gas Supp/y Mode/ing, National Bureau

of Standards Special Publication 631, May 1982.

Figure 13.—Gas Potential, Gas Well Completions, and Expenditures—1978

1,019 TCF 13,306 gas wells $4,978.9 million

Ia

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 Well Drilling Activity and Expenditures in Relation to Potential Resource,” in Gas Energy Review, vol 9, No. 1 (Arlington, Va.. American Gas Association, January 1981).
68 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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

*The exten~ive investigation of the effects of new technology by

the National Petroleum Council in 1965 could find no credible

quantitative measurement of these effects.

decrease in minimum acceptable field sizes and

the 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 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

Figure 14.– New Field Wildcat Success Rate, 1966=81

1966

r

1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1978 1979

Year of reported discovery

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, Quarterly Review of Drilling Statistics
Ch. 4—The Natural Gas Resource Base 69

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 . . . . . . . . . . . . . . 1,518 8,878 17.1 544 5,271 10.3

1968 . . . . . . . . . . . . . . 1,440 8,879 16.2 442 5,205 8.5

1989 . . . . . . . . . . . . . . 1,700 9,701 17.5 535 5,956 9.0

1970. . . . . . . . . . . . . . 1,271 7,693 16.5 493 5,069 9.7

1971 . . . . . . . . . . . . . . 1,088 6,922 15.7 436 4,463 9.7

1972. . . . . . . . . . . . . . 1,285 7,539 17.0 566 5,086 11.1

1973. . . . . . . . . . . . . . 1,519 7,466 20.3 701 4,989 14.1

1974. . . . . . . . . . . . . . 2,009 8,619 23.3 805 5,652 14.2

1975. . . . . . . . . . . . . . 2,143 9,214 23.3 876 6,104 14.4

1976. . . . . . . . . . . . . . 2,449 9,234 26.5 986 5,840 16.9

1977. . . . . . . . . . . . . . 2,686 9,961 27.0 1,004 6,101 16.5

1978. . . . . . . . . . . . . . 2,728 10,677 25.6 983 6,505 15.1

1979. . . . . . . . . . . . . . 3,024 10,484 28.8 1,162 6,413 18.1

1980. . . . . . . . . . . . . . 3,574 11,916 30.0 1,340 7,034 19.0

1981 . . . . . . . . . . . . . . 4,585 15,168 30.2 1,423 8,052 17.7

1982. . . . . . . . . . . . . . 4,847 16,470 29.4 1,400 7,912 17.7

SOURCE’ American Petroleum Institute, “Quarterly Review of Drilling Statistics”

gas producers to reduce their standing inventory—i.e., proved reserves—by maximizing deIiverability and reducing exploration. Consequently, from the drilling Iow 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 occurrent 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

oi I.

‘“American Petroleum Institute, “Quarterly Re\lew of Drilling Statlstlc5,‘‘

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.

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.
70 . U.S. Natural Gas Availability: Gas Supply Through the year 2000

Historically, the cumulative number of gas and due to past economics; many small finds were

oil fields are distributed according to size in a too small to be economically developed and conmanner shown in figure 15. In this figure, the size sequently were reported as dry holes rather than

classes 1 through 20 (on the x axis) are scaled added to the historical record as a class D or E

so that the upper limit of size class 20 is one-half field. Because pipeline gathering systems are rethe upper limit of 19, and so on. As shown in the quired in order to develop gasfields no matter

figure, the cumulative number of fields increases what the field size, and also because the price

with decreasing size class as a geometric series, (per unit of energy) of gas has historically been

down to about size class 13 (or class D in the lower than that of oil, the minimum field size

AAPG notation), and then rapidly levels off. At suitable for development is larger—and thus the

least a portion of this “truncation,” or leveling truncation described above is more severe—for

off, of the field size distribution is undoubtedly gas than for oil. The crux of the current argument

Figure 15.—Slze Distribution of Discovered Oil and Gas Fields in the Lower 48 States

20 19 18 17 16 15 14 13 12 11 10 9 8 7 6

300. ’600

150. 300

9.38- 18.75 4.69- 9.38 2.34- 4.69 1.17- 2.34 .59- 1.17 .29- .59 .15- .29

5 4 3
Ch. 4—The Natural Gas Resource Base 71

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 tailingoff of the curve in figure 15 is almost entirely 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

costs are higher, which would be expected if the

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

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.

38j. 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 Geo/ogy, vol.

15, No. 1, 1983.

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

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

S9R. 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

Field 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 )oaquin, Los Angeles, and Ventura provinces

on the west coast. Delta provinces are small-to-medium sized,

circular-shaped, and derived from major continental drainage

centers. The one producing delta province in the United States is

the Mississippi Delta, which accounts for about 17 percent of U.S.

oil and gas resources in the RAND assessment.

GOR. Neh~ing, problems in Natural Gas Re~erve, Drilling, and Discovery DdL?, op. cit.
72 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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 19 18 17 16 15 14 13 12

Intervals

11 10

1200-3000

600-1200

300-600 150-300 60-150

6-60 <6

9 8 7 6

150- 300

75- 150

5432 1

Field size

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 projec-

*The projected distribution is drawn by assuming that the number of fields in each size interval smaller than 100 million BOE (0.6

TCF) is 50 percent greater than the number of fields in the next

larger interval.

tion. 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
Ch. 4—The Natural Gas Resource Base ● 73

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 of 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 or $6

per MCF,

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 recovery, gas recovery rates have long

been considered to be very high under most con-

*in other words, they are subeconomlc resources In the McKelvey

Box (fig. 8).

* * Reser\e estimates in some fields WIII decrease with time. Small

fields are generally considered to be more susceptible than large

fields to such reserve “shrink age,”

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

aDollars per barrel of oil equivalent (dollars per million Btu)

SOURCE Geological Survey Circular 828—Future Supply of 011 and Gas From

the Permian Basin of West Texas and Southeastern New Mexico, In.

teragency 011 and Gas Supply Project, 1980

ditions 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

mapping the boundaries 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 marginal areas

(with low permeability, thin pay zones, or other

conditions adversely affecting economic recovery), to well stimulations and well reworking, and

to infill drilling to well spacings lower than the

old norm of 640-acre spacing (see box G). For

example, from 1969 to 1979, ultimate recovery

in the Hugoton-Panhandle 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 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.

Claims about the likely future growth of older

fields have created substantial controversy. There

are several areas of disagreement. For lowered

abandonment pressures, analysts disagree about

the effectiveness of regulatory measures designed

to prevent premature abandonment of old wells

—e. g., incentive prices for low-production-rate

wells called “stripper” wells. They also disagree

about when the wells would be abandoned if the

current low prices did not change. This is important because the lower the “old” abandonment

pressure is, the lower is the volume of additional

gas that can be recovered in response to a higher

price. For well stimulation and infill drilling, a major disagreement concerns the extent to which

additional gas production from these measures

*However, the mre of recovery IS extremely wn~{t{~ e to thew

tactors, a~ is the econornlc threshold of development for a tleld

* *This field IS not considered a single field by all analyst>, nor

are Its reser~e levels corn pletely agreed on. As noted pre~ IOU \l\’,

the~e are not u n[ ommon pro blem~, espec-lall~, with large ~Ield\.

‘t Ibid.

38-742 0 -85 - 6
74 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

represents new gas that otherwise would not

have been produced, or whether the production

instead represents merely an accelerated draining from the field of gas that would eventually

have been produced by the existing network of

wells, without infilling or stimulation. And for all

the measures, there are substantive disagreements about the gas prices necessary to stir major activity, with producers tending to see the

need for higher prices and buyers tending to

blame poor markets for current disinterest in production enhancement measures.

Another complication in gauging the likely

future growth of older fields is the uncertainty surrounding future gas prices in these fields. Aside

from the ever-present difficulty of forecasting

future market prices for gas, it is not clear to what

extent the currently low prices in the old fields

will be allowed to rise to the higher market price,

or to some other set of defined prices. Although

the existing legislation—the NGPA—does define

a specific set of price revisions in 1985 and 1987,

it is not clear whether or not new legislation will

supersede the NGPA’s price schedule. Also, it is

not possible to accurately project all of the price

effects of the NGPA, for several reasons. First, the

volume of reserves in each NGPA price category

is not accurately known. Second, the eventual

price attained by reserves decontrolled by NGPA

will depend on unpredictable price negotiations

between purchasers and producers. Third, the

effects of NGPA provisions that provide higher

prices for gas from enhanced recovery are not

known because there are inadequate data on eligible reserves and because it is unclear how pro-
Ch. 4—The Natural Gas Resource Base . 75

ducers and pipelines will respond to the various

bureaucratic provisions in the incentive regulations.

OTA has calculated the potential reserve additions available from four of the five sources of

“new gas from old fields” listed in box G; we did

not estimate reserves from “extension of drilling

into formerly subeconomic portions of fields. ”

We attempted to account for some of the substantial uncertainties by examining two legislative

scenarios and by expressing the estimates as a

range. The calculations are explained in appendix A at the end of this report. The two legislative

scenarios are:

● Scenario 1: Continuation of the existing

NGPA with its partial price decontrol and

price escalation provisions; assume that no

new gas pricing legislation will be passed.

● Scenario 2: Assume that new pricing legislation is passed that allows any new gas from

growth of old fields to attain full market

prices without regulatory restraints.

We included only those reserves that are not

“new” reserves as defined by the NGPA; roughly

speaking, these “old” reserves are associated

with reservoirs that began to produce gas before

passage of the NGPA. Our conclusions, shown

in detail in table 16, are that continuation of the

NGPA in its present form (scenario 1 ) could eventually add at least 20 to 35 TCF to cumulative “old

gas” reserves if market prices reach $3.50 to

$4/MMBtu (1983$), whereas changes in the law

Table 16.—Potential Additions to “Old Gas”

Reserves From Lowered Abandonment Pressures,

Well Reworking, Infill Drilling, and Well Stimulation

(TCF)

NGPA Market

pricesa

Delayed abandonment and

well reworking . . . . . . . . . . . . 5-13 12-31

Infill drilling . . . . . . . . . . . . . . . . 13-20 25-28

Well stimulation . . . . . . . . . . . . 2 6

Total . . . . . . . . . . . . . . . . . . . . 20-35b

43-65

aAssumption: All additional reserves can obtain market Price of $3.50 to

$4.00/MMBtu. In infill drilling, drainage from original well network to new wells

is assumed not to prevent the necessary change in well spacing rules.

bDoes not include reserves added by stripper incentive, production enhancement

incentive,

SOURCE Office of Technology Assessment, “Staff Memorandum on the Effects

of Decontrol on Old Gas Recovery, ” February 1984.

that allowed additional reserves to attain the full

market price (scenario 2) would yield about 43

to 65 TCF at the same price level.

The above ranges do not reflect absolute minima and maxima because some uncertainties

were not accounted for. For example, the range

in scenario 1 does not include any contribution

to reserve growth from the NGPA price incentives for stripper production and for a variety of

production-enhancement measures. We had no

basis with which to quantify the effects of such

measures, although we do not believe them to

be insignificant. Also, the ranges do not include

additional reserves that might be added by largerthan-expected growth in reserves from new fields

discovered since 1978 and field growth resulting

from the development of formerly subeconomic

areas of fields. Recent annual reserve additions

have reflected a high level of “extensions” and

“revision s,” the two reserve categories that

would absorb new reserves from this latter type

of development. This might be a signal that there

is a substantial potential from this source of field

growth.

The numerical results reflect several intermediate conclusions of OTA’s analysis. In particular,

we discovered that the NGPA allows a substantial amount of old gas to attain higher prices. At

least one-third, and probably more, of U.S. “old

gas” reserves will attain substantial price increases

in 1985 or 1987 under the NGPA, and these increases will trigger significant levels of reserve

growth. Also, as a result of extensive discussions

with geologists and petroleum engineers, we concluded that infill drilling and well stimulation can

add moderately to gas recovery in most fields.

A considerable portion of this infill potential will

not occur until available gas prices reach $3.50

to $4/MMBtu, but some fields will be developed

at the current infill incentive price of about $2.85/

MMBtu. Unfortunately, we were not able to resolve disagreements about the validity of alternate estimates of abandonment pressures, and

consequently the ranges of expected reserve

growth reflect both extremes.

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
76 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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 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 Em bayment,

and the Baltimore Canyon have been expensive

failures 42 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

specuIative 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 1980s 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

price-controlled 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.

A counterpoint to pessimism about the economic viability of the deep resource is the recent

drop in drilling costs in response to the dropoff

in activity. Although costs probably will rise when

the oversupply in rigs eases, the costs during the

drilling boom period probably did not reflect the

——

‘2R. Nehrlng, “The Discovery of . . .,” op. cit.

equilibrium production costs that should be the

basis for defining the recoverable resource. Also,

deep drillers argue that their growing experience

and the rapid advancement of drilling technology

will overcome much of the effect of the price drops.

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 long-term economic viability but

rather the current lack 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 Iaid 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.43 Second, it is argued: 1)

‘d]l~id
Ch. 4—The Natural Gas Resource Base . 77

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. Nehring44 also cites geologic

arguments against the possibility 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.

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 proba41bid.

able 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 RAN D estimate implies that there will be at 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 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 430 to 900 TCF as of the end

of 1982. This is not really a very wide range, given

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.

‘Including gas in low-permeability reservoirs that otherwise satisfies the conditions. This recognizes the ambiguous boundary between “conventional” and “unconventional” gas in such reservolr~.
.

Chapter 5

Gas Production Potential
Contents

Page

Approach Number 1–Projecting Trends

in the Individual Components of

Reserve Additions. . . . . . . . . . . . . . . . . . . 82

New Field Discoveries . . . . . . . . . . . . . . . 82

Extensions and New Pool Discoveries . . 86

Revisions . . . . . . . . . . . . . . . . . . . . . . . . . . 90

Reserves-to-Production Ratio ....., . . . . 93

Production Scenarios . . . . . . . . . . . . . . . . 96

Approach Number 2—Projecting New

Pool Discoveries, Extensions, and

Revisions as a Single Growth Factor . . . . 98

Approach Number 3–Region-by-Region

Review of Resources and

Exploratory Success . ................100

Approach Number 4-Graphing the

Complete Production Cycle. . .........103

A Range for Future Gas Production .. ...,105

Public and Private Sector Forecasts of

Future Gas Production . ..............106

TABLES

Table No. Page

17. Additions to Lower 48 Natural Gas

Proved Reserves: Extensions and New

Pool Discoveries, 1966-83 (BCF) . . . . . 88

18. Summary of Projections of

Components of Reserve Additions and

Raps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

19. Lower 48 States Natural Gas

Production and Reserves 1981-2000

(in TCF) SCENARIO 1A: Optimistic

Exploration, Rapid Production . . . . . . . 97

20. Lower 48 States Natural Gas

Production and Reserves 1981-2000

(in TCF) SCENARIO 1B: Pessimistic

Exploration, Slowed Production . . . . . . 97

21. Arguments for the Question, “Will the

Reserve Growth in New Fields Be

Larger or Smaller Than the Growth

Recorded in Previously Discovered

Fields?” . . . . . . . . . . . . . . . . . . . . . . . . . . 99

22. Alternative Estimates of Growth

Factors for Initial Reserve Estimates for

Gasfields . . . . . . . . . . . . . . . . . . . . . . . . . 99

23. Lower 48 States Natural Gas

Production and Reserves, 1982-2000

(in TCF)–Scenario 2A: Very Optimistic 100

24. Lower 48 States Natural Gas

Production and Reserves, 1982-2000

(in TCF)–Scenario 2B: Pessimistic .. ..101

25. Lower 48 States Natural Gas

Production and Reserves, 1982-2000

(in TCF)–Scenario 2C: Very

Pessimistic ., . . . . . . . . . . . . . . . . . . . . .101

26. Lower 48 States Natural Gas

Production and Reserves, 1982-2000

(in TCF)–Scenario 3A . .............102

27. Lower 48 States Natural Gas

Production and Reserves, 1982-2000

(in TCF)–Scenario 3B . .............102

28. A Comparison of Conventional Lower

48 Natural Gas Supply Forecasts (TCF) 107

FIGURES

Figure No. Page

17. Natural Gas Production From 1981

Lower 48 Proved Reserves . . . . . . . . . . 81

18. Additions to Lower 48 Natural Gas

Proved Reserves: New Field Wildcat

Discoveries, 1966-83 (BCF) . . . . . . . . . . 84

19. Additions to Lower 48 Natural Gas

Proved Reserves: Extensions and New

Pool Discoveries, 1966-81 (TCF). . . . . . 87

20. Additions to Lower 48 Natural Gas

Proved Reserves: Revisions AS .

Reported, 1966-83 (BCF) . . . . . . . . . . . . 91

21. Additions to Lower 48 Natural Gas

Proved Reserves: Revisions As

Amended, 1966-83 (BCF) . . . . . . . . . . . 92

22, Reserve-to-Production Ratios for

Natural Gas in the Lower 48 States . . . 95

23. The Growth of Year-of-Discovery

Estimates of the Amount of

Recoverable Natural Gas Discovered

in the Lower 48 States . . . . . . . . . . . . . 98

24. Future Production Curves for

Conventional Natural Gas in the

Lower 48 States . ..................103

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 . ........104
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.

Of the four approaches used by OTA to project the mid- to long-term (1 990 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 with shocking rapidity to about

2 trillion cubic feet (TCF) by the end of the

century. *

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

“Concewably, the [nltlal reduction In production could be slowed

by drllllrrg additional development wells, eftectlvely lowering the

R/P ratio, The end result ot this strategy would be, however, an

even more rapid product ion collapse occurring a few years later

than that shown in fig. 17,

Figure 17.–Natural Gas Production From 1981

■

1982

■

Lower 48 Proved Reserves

■

✎

1985

R/P = 8.0 beginning in 1984

1990 1995 2000

Year

SOURCE: Office of Technology Assessment

(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. I n 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 * regionby-region examination of available gas resources

and past exploratory success. In all three cases,

production rates are 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 1956,1 tying future pro-

*joseph P. Rlva, jr., of the Congressional Research Service.

1 Described I n M, K, H ubbert, ‘ ‘Tee h nlques of Production as Applled to the Product Ion of 0!1 and Gas, ” 0// and Gas Supp/y ,A40de/fng, S, 1. Gass (cd.), National Bureau ot ‘jtandards Special PubIicatlon 631, May 1982.

87
82 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

duction 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 explicitly 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 1–PROJECTING TRENDS IN THE

INDIVIDUAL COMPONENTS OF RESERVE ADDITIONS

The first approach separately projects trends in

reserve additions from new field discoveries, new

pool discoveries and extensions, and revisions.

New Field Discoveries

The discovery of new 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.

Factors Affecting New Field Discoveries

The rate of annual additions to reserves from

new field discoveries depends on a variety of factors, but most importantly on:

●

●

The undiscovered resource base. –The 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, for example,

computer-aided seismic technology, affects

drilling success rates and, consequently,

overall discovery rates, Also, technological

improvements have opened up to commer-
Ch. 5—Gas Production Potential 83

●

●

●

●

cial exploitation some areas whose complex

geology had previously 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 .-lmprovements 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 stimulation 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 preferentially 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 activity.

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 elsewhere. The key determinants of the size and

character of this inventory 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

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

1983.) From 1967, the last year in which AGA

estimated that total reserve additions exceeded

production, until 1979, the average of new field

discoveries was 2.0 TCF. Similarly, nonassociated

new field discoveries were equally steady, with

a 14-year average of 1.7 TCF. Consequently, 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

*Actually, AGA compiled reserve additions data since 1947, but

only began separately estimating new field discoveries in 1967.

**Clearly they did not play a small indirect role since many of

the new pool discoveries and extensions in this period represented

development of the fields discovered earlier in the period.
84 . U.S. Natural Gas Availability: Gas Supply Through the year 2000

Figure 18.–Additions to Lower 48 Naturai Gas Proved Reserves: New Field Wildcat Discoveries, 1966.83 (BCF)

1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983

Reporting year

SOURCES: Office of Technology Assessment, baaed on data from Energy Information Administration, U.S. Crude Oil, Natural Gas, and Nafural Gas Liquids Reserves— 1983

Annual Report, DOE/EIA.0216 (83), October 1964, and American Petroleum Institute, American Gas Association, and Canadian Petroleum Association, ReServes of Crude 0il, Natural Gas Liquids, and Natural Gas in the United States and Canada as of December 37, 1979, vol. 34, June 1980.

average size of new gasfields became considerably smaller (reported year-of-discovery reserves

of 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. 14) 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.

*Class E fields contain less than 6 billion cubic feet of recoverable

gas.

The more recent (1977 to 1983) EIA new field

discovery data (fig. 18) show considerable yearto-year variation with no apparent trend aside

from the recent drop associated with the current

poor market, 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 first

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 gas-producing 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 48.2

ZEIA, (J. s. cru&Oil, Natural Gas, and Natural Gas Liquids Reserves, 1980 and 1981 Annual Repotts, DOEIEIA-0216 (80) and (81),

October 1981 and August 1982.
Ch. 5—Gas Production Potential ● 8 5

Implications

The following key issues pertaining to new field

discoveries remain essentially unresolved:

● Can the 1968-79 trend i n 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 1977-82 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,

assureing 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 recent high discovery rate did not depend 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 —conti nues.

To obtain the lower end of the 10-to 15-year

range, we assumed that the 1970s 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 10- to 15-year range

assumes that the EIA data accurately reflect a

major upward shift in the finding rate (volume

*Drilling is now in a substantial slump. The ranges of reserve additions discussed here would be unrealistically high if the current

“bubble” in gas deliverability and the related difficulties in marketing new gas were to continue.
—

86 ● U.S. Natural Gas Availability: Gas Supply Through the Year’2000

of 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 aligned 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 1960s

and 1970s 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 new

*The current gas “bubble” provides a disincentive for field development.

●

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 inground 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 year-of-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. Computerassisted 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”

“Because of the small size or low permeability of the reservoirs

or the low quality of the gas.
Ch. 5—Gas Production Potential ● 8 7

in the initial year-of-discovery, leaving less

room for followup discoveries. Advanced

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 17 illustrate the variation

of extensions and new pool discoveries** in the

Lower 48 States from 1966 to 1983. 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 1960s, 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 1970s.

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 these areas. Before 1968, field growth (primarily in relatively deep fields) in the Permian Basin

3

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, 1966-83 (BCF)

14,000 f

13,000

t

9,000 -

8,000 -

7,000 -

6,000 -

5,000 -

4,000 -

3,000 -

2,000 -

1,000 -

r ) -

1970

Year

AGA data EIA data

1975 1980

I

1982 1983

SOURCE: Office of Technology Assessment, based on AGA and EIA data,
88 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Table 17.—Additions to Lower 48 Natural Gas

Proved Reserves: Extensions and New Pool

Discoveries 1966-83 (BCF)

New pool

Year Extensions discoveries Total

1966 . ....8,767

1967 . ....9,472

1968 . ....7,037

1969 . ....5,800

1970 . ....6,146

1971 . ....6,375

1972 . ....6,154

1973 . ....5,931

1974 . ....5,693

1975 . ....5,926

1976 . ....5,337

1977 . . . . . 6,569 (8,056)a

1978 . . . . . 6,720 (9,582)

1979 . . . . . 7,112 (8,949)

1980 . . . . . (9,046)

1981 . . . . . (10,485)

1982 . . . . . (8,349)

1983 . . . . . (6,908)

3,110

2,420

1,426

2,043

3,363

3,361

3,096

1,970

1,952

1,649

1,994

2,144 (3,301)

1,964 (4,277)

1,690 (2,566)

(2,577)

(2,994)

(3,419)

(2,965)

11,877

11,892

8,463

7,843

9,509

9,736

9,250

7,901

7,645

7,575

7,331

8,713 (1 1,357)

8,684 (13,859)

8,802 (1 1,515)

(11,623)

(13,429)

(11,768)

 (9,873)

aThe values in parentheses are from EIA data; all other values are AGA reserve

data.

SOURCES: Office of Technology Assessment, based on data from Energy Infer.

mation Administration, U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves— 1983 Annual Report, DOE/EIA-0216 (83), October

1984, and American Petroleum Institute, American Gas Association,

and Canadian Petroleum Association, Reserves of Crude Oil, Natural Gas Liquids, and Natural Gas in the United States and Canada

as of December 31, 1979, vol. 34, June 1980.

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 1970s.

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 over-thrust Belt–probably also followed
Ch. 5—Gas Production Potential . 89

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 5 of the past 7 years by EIA.

As discussed in the “New Fields” section, OTA

suspects that part of the reason why ElA’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 ElA’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 hos-

*As discussed in ch. 4, “New Gas From Old Fields. ”

38-742 0 -85 - 7
90 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

tile environments–an increasing part of the

remaining resource—demand a more thorough

initial 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 1985-86 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 ElA’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 difficuIt 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

well-stimulation 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 1983, 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

+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 –2,91 1

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 sub-

*New reserves “discovered” by a development well would be

recorded as a revision if the gas is located in a pocket within the

established boundaries of a reservoir yet is physically isolated from

the reservoir’s main drainage system and would not otherwise be

produced.
Ch. 5—Gas Production Potential 91

Figure 20.–Additions to Lower 48 Natural Gas Proved Reserves: Revisions As Reported,a 1966-83 (BCF)

7,000

6,000

t

-1,000

t

1966

r

I I I I I I I I t I I

1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979

I I I I

1980 1981 1982 1983

‘tear

aNOTE: EIA plots for revisions + adjustments and Corrections.

SOURCES Office of Technology Assessment, based on data from Energy Information Administration, U S Crude 011, Natural Gas, and Natural Gas Liquids Reserves— 1983

Annual Report, DOE/EIA-0216 (83), October 1984, and American Petroleum Institute, American Gas Association, and Canadian Petroleum Association, Reserves of Crude Oil, Natural Gas Liquids, and Natural Gas in the United States and Canada as of December 31, 1979, vol 34, June 1980

stantial positive revisions in the mid-1960s

changed to net negative revisions in almost every

year in the 1970s, 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 1970s 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 1970s 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

1930s, 1940s, and 1950s, 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. The size, timing, and geographic distribution of the reported negative revisions that
92 . U.S. Natural Gas Availability: Gas Supply Through the year 2000

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 1970s appear to have

ended. The trends in revisions for the areas outside the source area for the negative revisions

seem 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

qlbid.

‘T. j. Woods, “On Natural Gas Trend s,” Gas Research Institute,

1982; R. Nehring, contractor report to OTA, op. cit.

“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, would be random if there were no incentives to be either pessimistic or optimistic in reserve 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

6,000 -

5,000 -

4,000 -

3,000 -

2,000 -

1,000 -

0 —

-1,000 -

-2,000 -

I

I

Year

aNOTE: EIA plots are for revisions + adjustments and corrections.

SOURCE: Off Ice of Technology Assessment
Ch. 5—Gas Production Potential ● 93

negative revisions of the 1970s 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 lowpriced 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

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.

*The sixth, knowledge gained from extension tests, yields only

negative revistons because an increase in reserves caused by this

source would be reported as an extension.

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, whiIe 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

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

bDouglas Boh i and Michael Toman, ‘‘Understanding Nonrenewable Resource Supply Behavior, ” Science, vol. 219, Feb. 25, 1983.

7P. A. Stockil (cd.), Our /rrduQry Petrcdeurn (London: British Petroleum Co. Ltd., 1977).
94 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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 undergrounds 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 ma-

*However, once the “propping effect” of the gas IJnder pressure is removed by partial production, the permeability of the reservoir may be reduced to “tight gas” levels, and production will slow.

B’ ‘Fletcher Area U nderscor~ Perils in Deep Gas Reservoirs, ” 0;/

and Gas Journal, Feb. 7, 1983, p. 25.

●

●

●

jor 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 over supply and resulting

wasteful gas production practices that

followed. 9

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/Ps and high

reserve requirements for pipeline approvals.

These requirements do not apply, however,

to mature areas where pipeline capacity is

already in place.

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 ex9R. E. Megill, An Introduction to Exploration Economics (Tulsa,

OK: Petroleum Publishing Co., 1971 ).

*Based on jensen Associates, inc., Understanding Natural Gas

Supply in the U. S., April 1983, contractor report to OTA.
Ch. 5—Gas Production Potential 9 5

ploration, 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 1960s and 1970s, 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 the R/P from 1946 to 1983 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 7 years from

1977 through 1983. *

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, and an actual increase in R/P thereafter

due to the weak markets for gas and relatively

strong reserve replacements during 1981-83.

Currently, the lowest R/P for the nonassociated

gas of a major producing State is 8.4 in Louisiana.

The lowest R/P for any geographical subdivision

published by the DOE/EIA reserves report was

a 5.0 for the State domain of the Texas offshore

* *These displayed ratios are developed using the year-end reserves estimate for the year prior to the production period. This

approach to calculating the R/P stems from a belief that production in a given year is more likely to be representative of reserves

that are available at the beginning of the year.

Figure 22.— Reserve-to-Production Ratios

for Natural Gas in the Lower 48 States

25}

20

10

1945 1950 1955 1960 1965 1970 1975 1980 1985

Year

SOURCES: Office of Technology Assessment, based on data from Energy information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas

Liquids Reserves— 1983 Annual Report, DOE/El-0216 (63), October

1964, and American Petroleum Institute, American Gas Association,

and Canadian Petroleum Association, Reserves of Crude Oil, Natural Gas Liquids, and Natural Gas in the United States and Canada

as of December 31, 1979, vol. 34, June 1980,

(for 1982). The total Texas and Louisiana offshore,

representing about one-third of Lower 48 State

production, stood at 6.5 in 1981 and 8.4 in 1983.

With the Gulf of Mexico excluded, the balance

of the Lower 48 States had a 1981 R/P of 9.8 and

a 1983 R/P of 11.7. Contrasting strongly with the

lower R/Ps of the gulf coast would be that of 26.3

for the heavily depleted reservoirs of Kansas and

23.6 in Wyoming, where field development for

newly discovered reserves was incomplete in

1983.

Implications

These recent examples of R/Ps for different

areas of the United States 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

throughout the 1970s as the Gulf of Mexico be-

*Some opinion exists, however, that some of the lower R/Ps are

due to underreporting of reserves rather than to extremely rapid

production. If true, this might indicate less potential for further

lowering the national R/P.
96. U.S. Natural Gas Availability: Gas Supply Through the Year 2000

came 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 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

IOE . . F Hardy and c. P. Neill, 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

R/P 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‘ I bid.

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

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 recent (pre-bubble)

levels–perhaps 7.0, or even somewhat lower–

to levels slightly higher–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 18 summarizes the ranges of reserve additions and R/Ps projected for Lower 48 natural

——

* *That is, a situation where additional supplies at prevailing prices

would be easily absorbed,

Table 18.-Summary of Projections of Components of Reserve Additions and R/Ps

New field discoveries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1985-86 2.0-3.5 TCF/yr

1987-2000 1.5-3.5 TCF/yr

Extensions and new pool discoveries. . . . . . . . . . . . . . . . . . . . . 1985-86 8.0-12 TCF/yr

1987-2000 6.0-11 TCF/yr

Revisions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1985-2000 0-2.0 TCF/yr

R/P . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2000 7.0-9.5

Scenario 1A: reserve additions. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1985-86 17.5 TCF/yr

1987-2000 16.5 TCF/yr

R/P . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2000 7.0

Scenario 1 B: reserve additions. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1985-86 10.5 TCF/yr

1987-2000 7.5 TCF/yr

R/P . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2000 9.5

SOURCE Office of Technology Assessment.
Ch. 5—Gas Production Potential 97

gas development. Tables 19 and 20 present pro- bability reserves where production rates are

duction and reserves projections that represent limited. Because each projection represents a

the two extremes of the ranges in table 18. The convergence of events of relatively low probabilfirst projection assumes an optimistic exploration ity—e.g., the lowest rates of new field discoveries,

future and rapid production of newly found re- extensions and new pool discoveries, zero reviserves-predicated upon high gas prices, high de- sions, and an upturn in R/P-the projections

mand, and an avoidance of large reserve addi- should be viewed as approximately bounding the

tions in low permeability areas that are hard to range of production and proved reserve levels,

develop rapidly. The second projection assumes rather than as identifying likely values.

low finding rates and an increase in low permeable 19.–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 (actual) . . . . . . . . . . . . . . . . . . 17.2 15.1 166.5 9.8

1983 (actual) . . . . . . . . . . . . . . . . . . 15.5 15.0 166.0 10.7

1984 . . . . . . . . . . . . . . . . . . . . . . . . . 16.0 15.0 165.0 10.4

1985 . . . . . . . . . . . . . . . . . . . . . . . . . 18.0 17.5 164.5 9.2

1986 . . . . . . . . . . . . . . . . . . . . . . . . . 18.3 17.5 163.7 9.0

1987 . . . . . . . . . . . . . . . . . . . . . . . . . 18.6 16.5 161.6 8.8

1988 . . . . . . . . . . . . . . . . . . . . . . . . . 18.8 16.5 159.3 8.6

1989 . . . . . . . . . . . . . . . . . . . . . . . . . 19.0 16,5 156.8 8.4

1990 . . . . . . . . . . . . . . . . . . . . . . . . . 18,9 16,5 154.4 8.3

1991 . . . . . . . . . . . . . . . . . . . . . . . . . 18.8 16.5 152.1 8.2

1992 . . . . . . . . . . . . . . . . , ... , . . . . 18.8 16.5 149.8 8.1

1993 . . . . . . . . . . . . . . . . . . . ... , >. 18.7 16.5 147.6 8.0

1994 . . . . . . . . . . . . . . . . . . . . . . . . . 18.9 16.5 145.2 7.8

1995 ......., . . . . . . . . . . . . . . . . . 18.9 16.5 142.8 7.7

1996 . . . . . . . . . . . . . . . . . . . . . . . . . 18.8 16.5 140.5 7.6

1997 . . . . . . . . . . . . . . . . . . . . . . . . . 18.7 16,5 138.3 7.5

1998 . . . . . . . . . . . . . . . . . . . . . . . . . 18.7 16.5 136.1 7.4

1999 ......., . . . . . . . . . . . . . . . . . 18.6 16.5 134.0 7.3

2000 . . . . . . . . . . . . . . . . . . . . . . . . . 18.6 16.5 131.9 7.2

Cumulative production after 1982 = 330,6 = 42%0 of USGS remaining resource.

aR/p calculated by dividing previous year’s (year end) reserves by production in the listed Year

SOURCE Off Ice of Technology Assessment,

Table 20.– 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 (actual) . . . . . . . . . . . . . . . . . .

1983 (actual). . . . . . . . . . . . . . . . . .

1984, . . . . . . . . . . . . . . . . . . . . . . . .

1985 . . . . . . . . . . . . . . . . . . . . . . . . .

1986 . . . . . . . . . . . . . . . . . . . . . . . . .

1987 . . . . . . . . . . . . . . . . . . . . . . . . .

1988 . . . . . . . . . . . . . . . . . . . . . . . . .

1989 . . . . . . . . . . . . . . . . . . . . . . . . .

1990 . . . . . . . . . . . . . . . . . . . . . . . . .

1991 . . . . . . . . . . . . . . . . . . . . . . . . .

1992 . . . . . . . . . . . . . . . . . . . . . . . . .

1993 . . . . . . . . . . . . . . . . . . . . . . . . .

1994 . . . . . . . . . . . . . . . . . . . . . . . . .

1995 . . . . . . . . . . . . . . . . . . . . . . . . .

1996 . . . . . . . . . . . . . . . . . . . . . . . . .

1997 . . . . . . . . . . . . . . . . . . . . . . . . .

1998 . . . . . . . . . . . . . . . . . . . . . . . . .

1999 . . . . . . . . . . . . . . . . . . . . . . . . .

2000 . . . . . . . . . . . . . . . . . . . . . . . . .

18.5

17.2

15.5

16.0

18.0

17.3

16.6

15.6

14.5

13.7

13.0

12.3

11.8

11.3

10.8

10.4

10.1

9.8

9.5

9.3

21.5

15.1

15.0

15.0

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

168.6

166.5

166.0

165.0

157.5

150.7

141.6

133.5

126.0

119.8

114.3

109.5

105.2

101.4

98.1

95.2

92.6

90.3

88.3

86.5

9.0

9.8

10.7

10.4

9.2

9.1

9.1

9.1

9.2

9.2

9.2

9.3

9.3

9.3

9.4

9.4

9.5

9.5

9.5

Cumulative production after 1982 = 236TCF = 310/o of USGS remaining resource.

aR/P calculated by dividlng previous year’s (year end) reserves by production In the listed Year

SOURCE Office of Technology Assessment
—

98 U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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 a field growth approach to calculate the amount of gas remaining to be discovered in the inventory of identified fields. 12 I n

that application, a curve was constructed that

describes 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 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

lzu.s. Geological Survey Circular 860, app. F.

I JThe data Came from table XIV of Reserves of Crude O;/, NahJral Gas Liquids, and Natural Gas in the United States and Canada,

VOIS. 21-34, 1966 through 1979, American Gas Association/American Petroleum Institute/Canadian Petroleum Association.

Figure 23.-The Growth of Year-of-Discovery

Estimates of the Amount of Recoverable Natural

Gas Discovered in the Lower 48 States

Years after discovery

SOURCE: D. H. Root, “Estimation of Inferred Plus Indicated Resevees for the

United States,” app. F in Estimates of Undiscovered Recoverable

Conventional Resources of Oil and Gas in the United States, U.S.

Geological Survey Circular 860, 1981.

that advances in exploration technology resulted

in the discovery of such reservoirs.14 Consequently, the year-of-discovery 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.15

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 21 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. *

14[bid.

I SR(3be~ pa~kiewicz, Jensen Associates, perSOnal communication.

*These conditions are the same as those affecting revisions, extensiclns, and new pool discoveries.
Ch. 5—Gas Production Potential . 99

Table 21 .-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. 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).

2. 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 discoveries reported by EIA were higher than those reported

by AGA during the 3 years the two reports overlapped

is probably that EIA reported reserve additions 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 generally believed

to have greater relative growth than small fields. Present and future field sizes will be smaller and should

be expected to have smaller 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 in 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.

aSome of these arguments are speculative. For example, in B.1., OTA has not

determined the cause of the AGA/EIA differences in reported new field

discoveries.

SOURCE Office of Technology Assessment

USGS’s estimate is not the only available estimate of field growth. Table 22 presents three

other estimates, with ultimate growth ranging

from 3,5 to 6.3 times the initial year-of-discovery

estimate.

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

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 23 through 25 present the results of

three scenarios representing the search for reasonable upper- and lower-bounds on future gas

Table 22.—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, “Estimation of Inferred Plus Indicated Reserves for the United

States,” app. F in G L. Dolton, et al , Estimates of Undiscovered Recoverable

Conventional Resources of Oil and Gas in the United States, U S Geological

Survey Circular 660, 1981,

2. J D. Haun, “Future of Petroleum Exploration in the United States,” AAPG

Bulletin 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 Oil Are We Really Finding, ” Oil and Gas Joumal, Apr

5, 1971, cited in Haun, op cit.

SOURCE: Office of Technology Assessment
—

100 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

production. * For each scenario, the “growth separately by applying a gas-to-oil production

curve” methodology was applied only to non- ratio of 1.3 MCF per barrel of crude oil to the

associated gas. Associated gas was projected ElA’s 1981 oil production forecast.16

*The production projections in the three tables should be viewed

as slightly pessimistic. This is because they were based on projected – ––

1982 nonassociated reserve additions of 8.7-10.2 TCF, whereas ac- 6U .S. De–p~rtment of Energy, 1981 Annua/ Repofi to Congress,

tual 1982 additions were about 14 TCF. VOI. 3, p. 62.

Table 23.–Lower 48 States Natural Gas Production and Reserves, 1982-2000 (in TCF)-

Scenario 2A: Very Optimistica

Total gas Nonassociated gas Assoc./dissolved

Year production Production 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

2.5

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.

aAssumptions: Nonassociated gas new field discovery rate = 3,000 BCF/yr

Growth factor = 5.0

Additional growth from price rises for old gas = 1000 BCF/yr from 1985 tO 1995.

bAssociated/dissolved gas–gas found in the same reservoir with oil.

SOURCE: Jensen Associates, Inc., contract submission to the Office of Technology Assessment, 1983.

APPROACH NUMBER 3–REGION-BY-REGION REVIEW

OF RESOURCES AND EXPLORATORY SUCCESS**

Using a region-by-region review to project fu- States and his subjective evaluation of their future

ture gas production involves a geologist’s exam- production potential.

ination of a variety of factors affecting produc- Fc]r this approach, the gas resource base was tion in 10 individual regions of the Lower 48 assumed to be a compromise between the assessments of USGS and PGC. For each region, a re-

—. --- .— —

**The analysis described in this section was performed by Joseph source value was selected by examining the field

P. Riva, Jr., Specialist in Earth Sciences, Congressional Research size and number implications of the two assessService (CRS). ments and choosing the value that seemed more
Ch. 5—Gas Production Pofenyial ● 101

Table 24.–Lower 48 States Natural Gas Production and Reserves, 1982.2000 (in TCF)–

Scenario 2B: Pessimistica

Total gas Nonassociated gas Assoc./dissolved

Year Production Production 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 . . . . . . . . . . . . . . . . . . . . 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.

aAssumptions: Nonassociated gas new field discovery rate = 1500 BCF/yr

Growth factor = 4.0

Additional growth from price rises for old gas = 500 BCF/yr from 1985 to 1995.

bAssocla{ed/dissolved gas—gas found in the same reservoir with oil

SOURCE. Jensen Associates, Inc, contract submission to the Office of Technology Assessment, 1983

18.7

18.0

17.4

16.9

16.4

15.9

15.4

15.0

14.6

14.2

13.8

13.4

13.0

12.6

12.2

11.8

11.5

11.2

15.7

15.1

14.6

14.1

13.6

13.2

12.7

12.3

11.9

11.6

11.2

10.9

10.5

10.2

9.8

9.5

9.2

8.9

8.7

8.4

8.3

8.3

8.2

7.6

7.6

7.7

7.7

7.7

7,7

7.7

7.7

7.2

7.2

7.1

7.1

7.1

131.3

124.6

118.4

112.6

107.2

101.7

96.6

92.0

87.7

83.8

80.3

77.1

74.4

71.4

68.8

66.5

64.4

62.6

8.8

8.7

8.5

8.4

8.3

8.1

8.0

7.9

7.7

7.6

7.5

7.4

7.3

7.3

7.3

7.3

7.2

7.2

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 25.–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 gasb production

1982 . . . . . . . . . . . . . . . . . . . .

1983 . . . . . . . . . . . . . . . . . . . .

1984 . . . . . . . . . . . . . . . . . . . .

1985 . . . . . . . . . . . . . . . . . . . .

1986 . . . . . . . . . . . . . . . . . . . .

1987 . . . . . . . . . . . . . . . . . . . .

1988 . . . . . . . . . . . . . . . . . . . .

1989 . . . . . . . . . . . . . . . . . . . .

1990 . . . . . . . . . . . . . . . . . . . .

1991 . . . . . . . . . . . . . . . . . . . .

1992 . . . . . . . . . . . . . . . . . . . .

1993 . . . . . . . . . . . . . . . . . . . .

1994 . . . . . . . . . . . . . . . . . . . .

1995 . . . . . . . . . . . . . . . . . . . .

1996 . . . . . . . . . . . . . . . . . . . .

1997 . . . . . . . . . . . . . . . . . . . .

1998 . . . . . . . . . . . . . . . . . . . .

1999 . . . . . . . . . . . . . . . . . . . .

2000 . . . . . . . . . . . . . . . . . . . .

Cumulative production after 1982 = 223.4 TCF = 29% USGS remaining resource.

18.5

17.7

16.9

16.1

15.3

14.5

13.8

13.1

12.5

12.0

11.5

11.1

10.7

10.4

10.1

9.8

9.3

9.1

15.5

14.8

14.0

13.3

12.5

11.8

11.1

10.4

9.9

9.4

8.9

8.6

8.2

7.9

7.7

7.4

7.2

7.0

6.8

8.7

8.0

7.5

6.4

6.1

5.4

5.4

5.4

5.5

5.5

5.5

5.5

5.6

5.6

5.5

5.5

5.5

5.5

5.5

131.3

124.7

118.1

111.2

104.9

98.5

92.8

87.9

84.4

79.6

76.1

73.1

70.5

68.1

66.0

64.1

62.4

60.9

59.6

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

8.9

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

Note Rows and columns may not add exactly due to rounding

aAssumptions Nonassociated gas new field discovery rate = 1,500 BCF/yr

Growth factor = 30

No additional growth from price rises for old gas

bAssoclated/dissolved gas—gas found in the same reservoir with 011

SOURCE Jensen Associates, Inc, contract submission to the Office of Technology Assessment, 1983
— —.

102 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

realistic. Then, future additions to proved reserves

were estimated, based on a subjective evaluation

of the following factors:

●

●

●

●

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 26 and 27 present two scenarios of

future gas production and reserve additions based

on the above approach. Scenario 3A projects that

one-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

* *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.

by 2000. Even under this more optimistic scenario, however, gas production will decline to

13.3 TCF by 2000.

Table 26.—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

maining resource.

SOURCE: J. P. Riva, Jr., A Projection of Converrtiona/lNatural Gas Production

in the Lower 48 States to the Year 2000, Congressional Research Ser.

vice/Library of Congress, June 10, 1983

Table 27.—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% USGS

remaining resource.

SOURCE: J P. Riva, Jr., A Projection of Conventional Natural Gas Production

in the Lower 48 States to the Year 2000, Congressional Research Service/Library of Congress, June 10, 1983.
Ch. 5—Gas Production Potential ● 103

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

bell-shaped 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 thencurrent 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 equal led the

remaining gas resources estimated by, respectively, Hubbert, USGS, and PGC (see table 6).

These curves are shown in figure 24.

17M, K, Hubbert, “fNuclear Energy and Fossil Fuels, ” in AmeriThe curves show that Hubbert’s assessment imcan Petroleum Institute, Dri//ing and Production Practice (1956),

plies an extraordinarily sharp decline in producclted in M. K. Hubbert, “Techniques of Prediction as Applied to tion, so that by 2000 the total Lower 48 producthe Production of Oil and Gas, ’ Oil and Gas Supply Modeling, S. tion rate would be about 3 TCF. Since there is

1, GaSS (cd.), National Bureau of Standards Special Report 631 ~ May

1982.

little flexibility in drawing this curve, it appears

Figure 24.—Future Production Curves for Conventional Natural Gas in the Lower 48 States

22

i

I

21

20

19

7

6

5

4

3

2

1 I

Year

SOURCE: Office of Technology Assessment.
104 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

unlikely that the range of uncertainty due to the

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 aligned

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.

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)

1900 1920 1940 1980 1980 2000 2020 2040 2080 2080 2100

Year

SOURCE: Office of Technology Assessment.
Ch. 5—Gas Production Potential ● 105

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. *

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 1970s 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

range of resource base estimates cited in table

6 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

430 TCF rather than Hubbert’s 244 TCF or

RAND’s 283 TCF. This higher value is compatible 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 14 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 (430 TCF) resource base assessment. It

must be stressed, however, that the additional 20

years or so of leeway implied by the more optimistic assessments seem likely to yield sufficient

changes in prices and technology to allow the

entry of nonconventional gas sources to the market and the movement of large amounts of conventional resources from “subeconomic” to

‘‘economic. These potential sources of gas production are outside the boundaries of the resource base assessments and production forecasts

discussed in Part I of this report, but they will be

extremely important to future U.S. gas production.

“It is important to remember that the kind of radical drop in production dictated by the most pessimistic of the resource base estimates will likely violate their baseline assumptions 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 difficulty to oil prod-

*One such possibility would be a resource base that, while large, ucts or to electricity (assuming supplies of these are available), a

had most of its resources in hard-to-find, slow-to-produce fields. rapid drop in production would still tend to push gas prices sharply

The future production “cycle” would then show a significant pro- upwards. This in turn would tend to Increase the resource base

duction drop in the next 20 to 30 years, followed by a very long by moving subeconomic resources into the economic, recoverable

period of low but stable production. category.

38-742 0 -85 - 8
106 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

PUBLIC AND PRIVATE SECTOR FORECASTS

OF FUTURE GAS PRODUCTION

Comparisons of alternative gas production forecasts have many of the same problems as comparisons of 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,18 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 28 presents the results of 21 public and

private sector production forecasts of conventional Lower 48 gas production.** All are a few

years old. Four of the forecasts explicitly include

tight sands and/or Devonian shale; these are

noted on the table.

The extent of agreement about future gas production displayed in table 28 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

spotential 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.

assumptions, forecasting methods, etc.—would

encompass 13 of the 15 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–1 2 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 from the standpoint of maintaining

production rates at high levels during the next

few decades.

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

one “dissenter” by 1995. It is important to recognize that these forecasters include some prominent

gas “optimists.” Much of the current optimism

about gas’s future must stem from confidence in

supplementary supplies 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,

which is the subject of Part II of this report.) However, it also seems likely that a resurvey of these

forecasts, using the latest 1984-85 results, would

show a higher range for the year 2000 production than in the original 1982 and earlier forecasts.
Ch. 5—Gas Production Potential ● 107

Table 28.–A Comparison of Conventional Lower 48 Natural Gas Supply Forecasts (TCF)

Company 1985 1990 1995 2000

1. Gulf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.4

2. Texaco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.9

3. Chevron. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.2

4. Exxon —

5. Sheila . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.0

6. Conocob . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.0

7. Union . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19.2

9. Standard Oil (Indiana)c . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.5

10. Tenneco . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.0

11. AIR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15.5

12. AGE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.0-18.0

13. GRI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.9

14. DOCK . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . —

15. GAO. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.5

16. E. Erikson . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.4-18.5

17. ERA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17.3

18. ICE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.1

18.8

16.1

18.0

14.6

13.9

18.0

18.0

17.7

15.4

13.6

5.0-17.0

15,1 —

14.8

—

14.9

14.3

19. IEA/OECDb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16.5-18.0 14.0-17.0

20. Chase Bankb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18.3 17.7

Average 18.1 16.6 —

16.7

14.0

16,5

—

11.5 —

—

16.5

13.5 —

3.5-15.5

12.8—

14.0

—

14.0

12.4—

—

15.3

13.8

13.0

14.0

14.1

8.9

14.6—

15.5

11,9—

12.0-14.0

11,6

12.8

13,5

—

—

11-15

—

14.3

aMarketed gas rather than actual total (dry) production Excludes increased production from fields that are “forever controlled” under NGPA and that Shell believes

could be obtained with decontrol

bNumbers Include tight sands

cAverages include interpolated data.

REFERENCES

1 GulfOti Corp, US Energy Analysis Task Group, Pittsburg, PA, US Errvironmenta/ Assessment 1982 Scenarios, June 1982 “Business as Usual” scenario (In.

eludes Lower 48 and southern Alaska)

“2 Texaco Inc. Economics Division, Finance and Economics Department, White Plalns, NY, Unifed Stafes Energy Outlook 1980-2000 February 1981 (Forecast of

Marketed ProductIon)

“3. Standard Oil Co of Callfornla, Economics Department, San Francisco, CA Preliminary forecast from forthcoming pubhcation

4 Exxon Co, USA, Houston, TX, Errergy Ouf/ook 1980-2000, December 1980

‘5 Shell OdCo, Exploration and Production Economics Department, Houston, TX, Natlona/ EnergyOut/ook tothe Year2U00, July 1982 (Fall 1981 Analysts Dry Marketed

Gas)

“6 Conoco, lnc, Coordinating and Plannlng Department, Stamford, CT, Wor/d Energy Ouf/ook Ttrrough 20@, January 1982

“7 Union Oti Co, Od and Gas Drwsion, Plannlng and Valuatron, Los Angeles, CA

“8 Marathon OflCo, Economics Department, Findlay, OH

“9 Standard O!l Co (Indiana), Chicago, IL Amoco’s forecast includes nonhydrocarbon gases and lsspeclflcally done on adry gas basis Its 1985 forecast number

IS demand-constrained

“1O Tennessee Gas Transmission Coq Economic Analysis and Long Range Planning Department, Houston, TX, Energy 7982.2000, August 1982

“11 American Natural Resources Co. Detroit, Ml, Urrited Sfates Errergy Out/ook 1980-2000.

12 American Gas Assoc!atlon, Gas Supply Committee, Arlington, VA, The Gas Energy Supp/y Outfook 1980-2000, January 1982

“13. Gas Research lnstltute, Washington, DC, Gas Research Insights, October 1982

14 US Department of Commerce, Washington, DC, US Energy for the Ffesfof tt?e Century, July 1982

15 General Accounting Office, Washington, DC, Ana/ysis occurrent Trendsjn US. Petro/eurn and Natura/ Gas Production, Dec 7, 1979

16 Dr. Edward W Erickson for Natural Gas Supply Association, Natural Gas Poficy Act A Pragrnat/c Ana/ys/s, January 1981

17 Energy Information Admln!stration, U.S Department of Energy, Washington, DC, 1981 Annua/ Report to Congress, February 1982

18 ICF Inc, Washlngtorr, DC, “The Economics of Gas Supply” as published in The Energy JournaL VOI 3, No 4, October 1982

19 International Energy Agency, OECD, Wor/d Energy Out/ook, Paris, 1982

20 Chase Manhattan Bank, Energy Economics Division, New York Best estimate forecast from forthcoming publication

SOURCE Jensen Associates, Inc , “Understanding Natural Gas Supply in the United States,” contractor report to the Office of Technology Assessment, April 1983
Chapter 6

Gas Imports —An Overview
Mexico . . . . . . . . . . . . . .

Canada . . . . . . . . . . . . . .

Alaska . . . . . . . . . . . . . .

Page

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114

Liquefied Natural Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............115

TABLE

Table No. Page

29. Natural Gas imports Summary Table . . . . . . . . . . . . . . . . . . . .............111
Chapter 6

Gas Imports—An Overview

Natural gas imports in 1983 totaled 918 billion

cubic feet (BCF)1 and composed 5.5 percent of

the total U.S. dry gas consumption. The current

import status and future import projections are

summarized in table 29.

In evaluating potential import supplies of natural gas to the Lower 48 States, 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 will depend on U.S. demand and

competitive pricing. An important uncertainty in

this regard is the effect of recent Canadian initiatives to price their gas more competitively in

‘ U.S. Department of Energy, Energy Information Administration,

“U.S. Imports and Exports of Natural Gas, 1981 ,“ june 1982.

the current U.S. market. In the long run, the increase in allowable exports will probably help encourage frontier development.

Exports from Mexico will probably remain at

or below 300 million cubic feet per day (MMCF/

day) in the near term, consistent with what they

have been since the present contract was negotiated in 1979. In fact, Mexico temporarily ceased

gas exports to the United States in the fall of 1984

because of the pressure for lower gas prices in

the current weak U.S. market. 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

Table 29.—Natural Gas Imports Summary Table

Natural gas supplied Allowable imports Proved reserve Range of

to Lower 48 States under recent estimates future export estimates

Source in 1983 licenses/contracts (Dec. 31, 1982) 1990 2000

Mexico 0.07 TCF 0.11 TCF 76 TCF 0.1-1.0 TCF 0-1.5 TCF

(AGA/GER) (AGA/GER) (OGJ) (AGA, LA-Mexico)

Canada 0.7 TCF 1.75 TCF 97 TCF 1.0-2,5 TCF 1.0-3.0 T C F

(AGA/GER) (AGA/GER) (OGJ) (AGA, LA-Canada)

Alask a o — 35 TCF ANGTSb

(EIA) 0.7-1.2 TCF

Pacific-Alaskan LNG

0.1-0.2 TCF

(AGA)

LNG 0.13 TCF 0.9 TCFC235 TCF (OGJ)d Variable—depends on future U.S.

(AGA/GER) policy and pricing.

Total 0.9 TCF

(EIA)

aThis range represents the highest and lowest estimates of the references cited.

bAlaskan Natural Gas Transportation System.

cThis value represents the total contract volumes for completed terminals.

dReserve of SIX countries (other than U S.) currently exporting LNG

REFERENCES

AGA—American Gas Association, The Gas Energy Supply Outlook: 198.3-2000, October 1983.

AGA/GER—American Gas Association, Gas Energy Review, various dates

EIA– Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids, 1982 Annual Report

LA–Canada– Lewin & Associates–Canadian Natural Gas: A Future North American Energy Source? January 1980

LA– Mexico– Lewin & Associates–Future Mexican Oil and Gas Production, July 1979.

OGJ —Oil and Gas Journal, December 1982 and other issues.

SOURCE’ Office of Technology Assessment.

111
112 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

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 current 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. A rival 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,

Throughout the early to mid-1970s, 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.

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

could in the future become a limiting factor to

export levels. Mexico’s current export maximum

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 policy makers, 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.

Because of the low gas demand and low market

price in the United States, actual import levels

had been reduced to the 60 percent minimum

take-or-pay level, causing 1983 imports to be

‘Border Gas is owned and controlled by six interstate pipeline

companies: Tennessee Gas Transmission Co., Texas Eastern Transmission Corp., El Paso Natural Gas Co., Transcontinental Gas Pipeline Corp., Southern Natural Gas Co., and Florida Gas Transmission Co.

about 72 BCF.3 Mexican exports to the United

States have now been temporarily suspended because of the unfavorable market conditions.

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.4 Because Mexico’s financial condition has precluded investment in distribution 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.

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. s The factors that

wiII determine the actual value of future imports

include the progress of Mexico’s economic growth

and attempted reliance on gas for domestic

‘j. L. Wingenroth and A. A. Bohn, “Mexican Gas Supplies to the

United States, ” Gds Energy Review, American Gas Association,

August, 1984.

4Petro/eum Intelligence Week/y, Special Supplement, “Mexico’s

Expanding Role in World Oil Markets, ” June 28, 1982.

51 bid.
Ch. 6—Gas Imports—An Overview . 113

needs, the levels of demand for Mexican oil,6 any

changes in Mexico’s view of gas as a natural

patrimary, and future U.S./Mexican export/import

agreements. Also, development of its substantial

resources of non associated gas could greatly affect future exports.

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 & Associates estimate that anWi I demand is a factor not on Iy because oi I production drives

associated gas prod uctlon, but also because 01 I revenues are necessary for the Mexican economy, ~nd low 01 I exports W’OU Id exert

pressure on Mexico to increase gas exports.

nual exports will rise to 766 BCF in 1990 and then

decrease to 255 BCF by 1995 and O by 2000.7

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 1990s and between 100

and 1,500 BCF/yr will be available by 2000.8 The

upper end of the range reflects a potential Mexican response to inadequate oil revenues using

increased gas exports to stabilize its national

income.

7Lewin & Associates, Future Mexican Oi/ and Gas ProductIon,

July 1979.

8Amerlcan Gas Association, The Gas Energy Supp/y Out/ook:

198.3-XXX), C)ctober 1983,

Canada also has large natural gas reserves, estimated at 97 TCF. 9 Its ultimately recoverable

resource base estimate of 420 TCF10 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, and, until recently,

Canadian exporters had succeeded in marketing

only about 40 percent of their allotment of exportable gas. 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. In July 1983, an

incentive sales program was added that made additional gas available at $3.40 per MCF to purchasers buying specified quantities of regularlypriced Canadian gas. In July 1984, the Canadian

Government announced a policy, effective November 7, 1984, that gave gas exporters the option of negotiating prices with their customers,

—— .-. -

‘Robert ]. Enrlght, ‘‘World 011 Flow, Refining Capacity Down

Sharply; Rew~r\es I ncreaw, ’ 0// and Gas joum,I/, December 1982.

10R M. pr[jc~er, p, j. Lee, ,ind D, N. Skl bo, ‘‘cd nada’s conventional 011 and Gas Rew)urce\, ” Geological Survey of Canada, ()~)en

File 767, March 1981, p. 27.

with a price floor at the wholesale price of natural gas at the Toronto City gate. 11 Despite these

efforts, decreased U.S. demand and improved

short-term domestic supply prospects may still

keep U.S. imports of Canadian gas low in the near

term. There is, however, considerable disagreement about the effect of the new Canadian pricing policies, and some Canadian producers have

been newly successful in selling to the U.S. market. The price considered acceptable by the

Canadians will be a dominant factor affecting the

level of exports to the United States. In the longer

term, if the U.S. surplus disappears, Canadian exporters should be well-positioned to substantially

expand their gas sales to the United States.

The 1980 National Energy Plan (NEP) has had

important 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;

——

‘ ‘0// ,]nd G-as joum,?/, “Canada Allo\\(\ Gas Exporters to Negotiate Prl(cs, ” july 23, 1984.
114 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

●

●

●

stimulate frontier exploration off the East

Coast and in the Arctic;

allow a 25 percent back-in interest for the

Canadian Government on federal leases; and

increase the Canadian Government’s share

of petroleum revenues relative to those

received by industry and the producing

provinces.

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, if not reversed,

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 1980s and 3 percent per year throughout the 1990s.12 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 2000.13 AGA estimates that between

0.8 and 1.8 TCF/yr will be exported by 1990 and

1.0 to 2.4 TCF/yr by 2000.14 Lewin & 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.15

.

‘National Energy Board, “Omnibus ’82 Backgrounder, ” Jan. 27,

1983.

1‘Ibid.

I ~American Gas Association, The Gas Energy SUpplY Out/ook..

1983 -2W0, October 1983,

15Lewi n & Associates, Canadian Natural C,Is: A Future North

American Energy Source, January 1980,

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 35 TCF, and resource

base estimates are as high as 169 TCF.16

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

lbfJOtentia{ GaS cornrnlttee, Potentia/ Supp/y Of Natura/ Gas in

the U. S., June 1983.

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-miIe 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 billion17 and deliver gas at prices

1‘America n Gas Association, Gas Energy Review, vol. 10,

No. 1, january 1982.
Ch. 6—Gas /reports-An Overview 115

estimated between $4.85 per MCF 18 and $20 per

MCF. 19 ANGTS is the only pipeline transportation scheme designed to market North Slope natural gas in the Lower 48 States. AGA currently

does not project any pipeline imports from Alaska

by 1990 but expects imports of 0.7 to 1.2 TCF

by 2000, assuming that the pipeline is built.20

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

I H/ntern,~tlon,l/ G,I\ Techno/og) } ilgh/i~~hts, ‘ ‘Alaskan PI Pel I ne

Co$t$ Cou Id Be Lower Because ot Delay Northwest tieat, Aug.

30, 1 98.?.

“’()// and Gaj /ourna/, ‘‘Angt~ %en Top option for Alaskan GaJ, ’

Aug. 9, 1982, }), 61

‘

{ JAmertc an Ga\ ,A\soclatlon, Tht Ga\ Energ) Supp/y out/ook

1 %4?-2(XX), ()( tober, 1983,

range between $14.24 and $17,24 per million Btu

(MM Btu).21

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 between 0.1 and 0.2 TCF could be supplied by 2000, depending on the construction

schedule.22

<‘ Con~re~slonal Rewarch Ser\ Ice, , {Iajor l~+ut~f d~wx [atecl \\’/t}]

~he A/aska ,Natura/ Ga+ Trarwportatlon tt’,]li [’ri Dec. 18, 1981.

J~An?erlc an Gas Aijoclatlon, The G,I\ Energ\ Su/)/)/\ out/[xjL

1983-2000, odoher, 1983

LIQUEFIED NATURAL GAS

During the early to mid-1970s, 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/yr, the United States imported

only 132 BCF of LNG in 1983 at two of four existing receiving faciIities. The Distrigas faciIity in

Everett, MA, received 36,4 BCF and the Lake

Charles, LA, facility received 119.9 BCF since its

first shipment in September 1983. Small amounts

of LNG were also trucked from Canada to New

England. Also in 1982, the United States exported

60 BCF from Cook Inlet, AK, to Japan, and in

1981 was a net exporter of LNG.23

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 Algeria24). 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 faz ~lj s OplJ,l ~nl~n! of Efler~y, Energy I nformatlon Admlnlstratlon,

“U. S.” lrnports and Exports of Natural Gas, 1981 ,“ june 1982,

j~{]ffice of TCJCh no Iogy Assessment, A hematli e Energy Futures,

Part. 1, The Future of L, WC, March 1980,
116 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

cility (1 BCF/day) including production and liquefaction, transportation, and receiving and

vaporization facilities is around $3 billion to $7

billion (1982$),25 depending on shipping distance.

Although the cost of service is dependent on interest rates and shipping distance, a cost of

$3/MMBtu to cover liquefaction, transportation,

and reconstitution of the gas would not be

unusual .26

The future of LNG depends principally on pricing and policy. If the producing country demands

a high price at the wellhead—as an extreme example, a price approaching parity with oil on a

$/Btu basis–then the delivered price of the gas

- —

‘SD. Napoli, R. N., “Economics of LNG Projects, ” Oi/ and Gas

Journal, Feb. 20, 1984.

zGBecause many of the capital costs are sunk, however, this cost

will not necessarily be added to the price of the gas.

generally will be much higher than the price of

competing fuels. Currently, the price of LNG is

higher than market-clearing levels in the United

States, and could be sold only by mixing the gas

with lower cost gas and charging a price in line

with the average cost. In fact, because the current cost of liquefaction, transportation, and reconstitution may be almost equal to the average

wellhead price of new gas,27 future imports of

LNG will probably require both a substantial increase in U.S. domestic wellhead prices and a

marketing policy on the part of the exporting nations that considers the transportation costs in

pricing the gas at the well head.

—

‘according to the February 1984, Natura/ Gas M (Energy information Administration, DOE/EIA-0130 (84/OZ), the average price

for New Gas (NGPA sees. 102, 103, 108, and 109) was $3.59 per

MCF.
Part II

Unconventional Gas Supplies
Introduction and

Chapter 7

Summary:

Availability of Unconventional

Gas Supplies
Contents

Page

Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ... ... ... ..I21

The Definition Problem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....122

Relative Uncertainty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .........,122

Tight Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............................123

Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .........................123

Resource Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .............125

Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ................125

Resource Estimates . . . . . . . . . . . . . . . . . . . . . . . . . .......................126

Production Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ................128

Gas From Devonian Shale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .........128

Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......................,128

Resource Characteristics . . . . . . . . . . . . . . . . . . . . . . ......................129

Technology. ,. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........130

Resource Estimates . . . . . . . . . . . . . . . . . . . . . . . . . .......................131

Production Estimates . . . . . . . . . . . . . . . . . . . . . . .........................133

Coalbed Methane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................133

Definition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........................133

Resource Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .........,.,.133

Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...,...........134

Resource Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................134

Production Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....136

TABLES

Table No. Page

30.Gas-in-Place Estimates for Tight Gas . . . . . . . . . . . . . . ...................126

31. Economically Recoverable Gas at Two Technology Levels . . . . . . . . . . .. ...127

32. Devonian Shale Recoverable Resource Estimates (TCF):

Appalachian Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131

33. Coalbed Methane Resource Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .135

34. Comparison of Recoverable Resource Estimates (TCF) . .................135

FIGURES

Figure No.

26. Location of Principal Tight Formation Basins .

27. Primary Area of Devonian Shale Gas Potentia

Page

. . . . . . . . . . . . . . . . . . . . . . . . . 124

. . . . . . . . . . . . . . . . . . . . . . . , 129
Chapter 7

Introduction and Summary: Availability of

Unconventional Gas Supplies

INTRODUCTION

The unconventional natural gas resources include low-permeability sandstone and limestone

formations (commonly known as tight sands or

tight gas formations), Devonian shales, methanerich coal seams, and geopressurized aquifers.

Methane hydrates—gas trapped with water in an

ice-like state—and abiogenic, or “deep earth”

gas–gas supposedly originating from the venting

of methane from the Earth’s core—have recently

been added to the unconventional roster. Due

to a combination of technical difficulties and high

costs of production, gas found in these geologic

circumstances has not, for the most part, been

included in natural gas resource base estimates.

However, higher gas prices and advances in technology developments have recently made some

of the unconventional resources more attractive.

During the past 10 years, several Government

and private organizations initiated studies to determine the size of these additional resources and

the conditions necessary to develop them. The

first comprehensive study of the unconventional

resources was completed by the Federal Power

Commission in 1973 as part of the National Gas

Survey. 1 It was followed by studies by the National Academy of Science,2 the Federal Energy

Regulatory Commission,3 Lewin & Associates

under contract to the Department of Energy,4 and

the National Petroleum Council. s Results of these

‘ U.S. Federal Power Commlsslon, Task Force Report of the

Supply-Technical Ad\lsory Task Force–Natural Gas Technology,

In /VatIorra/ Cas SurIwy, Lot. 2, 1973.

] Natlona I Academy of Scwnces, Natural Gas From Uncon \entmna/ Geologic Sources, 1976, Energy Research and Development

Admlnlstratlon Report FE-2271-1.

~Fecieral Energy Re8u Iatory Comm isslon, U.S. Department of

Energy, Nat/onal Gab Survey: Noncon~ent/onal Natural Gas Resources, DOE/FERC-0010, June 1978,

W. A. Kuuskraa, et al. ( Lewl n & Associates, Inc.), Enhanced

Reco~ery of Uncon\entiona/ Gas, Executl~e Summary, Vo/. 1, (Xtoher 1978, and 2 other vols,, U ,S. Department of Energy Publication tiCP/T270S-01, 02, 03.

5Natlonal Petroleum Courx II, Uncon~ entlorra/ Ga$ Sources, 5

\’o15,, 1980.

studies, and of other studies of individual resources, will be discussed in more detail in subsequent chapters.

A general consensus emerges from these studies that the total size of the unconventional natural gas resource base is extremely large, that with

higher prices and more sophisticated technologies, significant quantities of gas could be recovered. Findings of the early studies undoubtedly provided the impetus to include gas from

tight formations, Devonian shales, coal seams,

and geopressurized brines in the high cost category (sec. 107) of the 1978 Natural Gas Policy

Act (NGPA). The higher allowable prices for this

category were intended to promote near-term development of these resources.

OTA’s assessment deals only with the gas resource potential of the tight formations, Devonian shales, and coal seams. These resources are

the best understood of the unconventional resources and appear to have the most potential

for contributing to supply within the next 20

years. Gas from tight formations and, to a lesser

extent, from Devonian shales currently is being

produced in quantities sufficient to cause substantive problems with the definition of “unconventional,” as discussed below. Gas from coal seams

is also being produced, but in much smaller

quantities. In contrast, our present level of understanding of the geopressurized aquifers suggests that they are less likely to be commercially

viable gas producers within this century, although

some researchers vigorously disagree with this

view. Too little is known about the methane hydrates and their production requirements to allow

an adequate assessment of their supply potential. Finally, the potential of “deep earth gas” is

only conjecture at this time because there is no

generally accepted proof of its existence in commercial concentrations.

121

38-742 0 -85 - 9
122 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

The Definition Problem

“Unconventional” is not, perhaps, the best

term to characterize the gas resources under discussion, although we will continue to use it in

this report for the sake of simplicity and adherence to customary usage. Tight gas and gas from

Devonian shales, in particular, are not newly recognized resources. Certain fields that fit in these

two categories have been producing gas for many

years. These and other currently economic tight

gas and Devonian shale formations are partly included in the conventional resource base estimates of the Potential Gas Committee, and a

small amount may be included in the estimates

of the U.S. Geological Survey and others. To evaluate its potential as an additional source of

supply, the unconventional resource should include only those parts of the tight formations and

Devonian shales which have not been considered

economic to produce under existing economic

conditions and technology. Coal seam methane

resources can be more easily categorized since

past production has been low. They are unlikely

to have been included in past estimates of conventional resources.

As noted in Part 1, conventional resources generally are categorized by defining boundary conditions in terms of “existing economic conditions,” “current technology,” and other vague

terms. Unfortunately, there currently are no

widely accepted criteria defining these terms to

allow a clear division between conventional and

unconventional gas resources. Further, the

boundary dividing conventional and unconventional resources is continuously changing through

time due to changing economic conditions, increased geologic understanding, and greater

technical sophistication. The poorly defined

boundary causes considerable confusion in determining the size of the unconventional resource

and the amount that it can potentially contribute to total U.S. natural gas supply.

The level of confusion is likely to continue.

Most current estimates of the unconventional gas

resource base and its supply potential have attempted to eliminate overlap with conventional

gas resource estimates by excluding areas with

existing production. But data sources for new production from unconventional formations do not

clearly distinguish between existing and new producing areas. Since passage of the NGPA, most

of the production data comes from Federal Energy Regulatory Commission (FERC) filings for section 107 (high cost gas) designation and from Purchase Gas Adjustment (PGA) filings that record

gas purchases according to the NGPA categories.

The FERC intended to exclude gas from existing

producing formations when it determined criteria

for designating formations eligible for section 107

classification. It was inevitable, however, that new

wells drilled in a number of existing producing

formations would satisfy the FERC criteria and be

granted section 107 prices. As a consequence,

it is no longer possible to distinguish between

areas which previously were excluded from assessments of the unconventional resource and

those which were included. Thus it is difficult to

determine the extent to which resources classified

as unconventional in past assessments are now

being developed.

We will attempt to clarify and identify overlap

between conventional and unconventional estimates of natural gas resource potential in the

subsequent chapters. The reader should keep in

mind that there are limited data available to make

such distinctions and our conclusions are necessarily tentative.

Relative Uncertainty

Estimates of gas-in-place, recoverable resources, and future production of conventional

natural gas are characterized by a high level of

uncertainty, as described in the previous chapters. Inevitably, similar estimates for the unconventional natural gas resources will be more uncertain still. Many of the same categories of

uncertainty, such as lack of geological understanding, are magnified for the unconventional

resources. Further, whereas estimates for the conventional resource focus on existing and relatively

well understood technologies, most resource and

production estimates for the unconventional resources attempt to foresee new technological developments, adding additional uncertainty. Finally, for the unconventional resources, there often

is little of the production and discovery history
Ch. 7—introduction and Summary: Availability of Unconventional Gas Supplies . 123

that serves as a guide to projections for conventional gas, and what history does exist applies

only to the small part of the overall resource that

was accessible to past discovery and production

technology.

The general level of uncertainty associated with

estimates of the unconventional resource base

is somewhat different from that associated with

projections of future unconventional production.

Although resource and production estimates

share some uncertainties about the geology of the

resource, generally production estimates focus

on the most accessible, and best understood portion of the resource—at least for shorter term projections. On the other hand, projecting future

production requires making assumptions about

drilling rates and development schedules, about

the pace of production research programs, about

pipeline accessibility, and about the future progress of a number of institutional issues such as

controversies about the ownership of coal seam

gas, leasing difficulties in Devonian shale development, etc. In OTA’s opinion, long-term projections of future unconventional gas production

should be viewed as at least as uncertain as, and

probably more uncertain than, estimates of gasin-place and of recoverable resources at an

assumed price and level of technological development.

Finally, it cannot be overstressed that any estimates of future production and recoverable resources that would purport to be “most probable” estimates are explicitly relying on an

assumption both of the level of effort that GovTIGHT

Definition

Tight gas is natural gas that is found in formations of sandstone, siltstone, silty shale, and

limestone that are characterized by their extremely low permeability–i.e., liquids and gases do not

flow easily through them. Figure 26 shows the

main tight gas-bearing basins in the Lower 48

States. Tight gas reservoirs represent the Iowpermeability end of a continuum of gas-producernment and industry will put into the massive

research and development necessary to gain access to the greater part of the unconventional resource, and of the success of that R&D program.

past disappointments in technological forecasting should serve as a reminder that this type of

estimate must always be viewed with a certain

degree of healthy skepticism. In addition, these

estimates are relying on assumptions of future gas

prices and, in the case of production estimates,

on assumptions of future gas demand. Both future

prices and demand must be considered highly

uncertain. For these reasons, virtually all recent

estimates of recoverable resources and future

production rely on a scenario approach wherein

the effect of different price and technology

assumptions are examined.

In the following summaries, the term “gas-inplace” denotes the total gas present in formations

where some economic gas production is feasible; it therefore does not include every last molecule of gas present in the Earth. “Technically

recoverable resources” denotes gas expected to

be recoverable from these formations up to the

limits of known technology, with little regard to

price. 6 “Remaining recoverable resources” denotes gas that is expected to be recoverable

under a set of price and technology assumptions

defined by the estimator.

eTh is category IS meant to I nc I ud e on Iy those rewu r( e$ that c a n

be extracted by technologies ordinarily used tor ~a~ production

For example, gas that theoretically could be obta[ned by ml nlng

and retorting shales wou Id be excl ucied.

GAS

ing reservoirs rather than a unique type. Over the

past several decades, rising gas prices and improvements in production technology have encouraged gas producers to move to lower and

lower permeability formations, and thus the

boundary between “conventional” and “unconventional, tight gas” has continually shifted. In

1978, in order to allow price incentives to encourage production of high cost gas under the

NGPA, FERC formally defined “tight gas” as hav-
124 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Snake River

Cownyarp

\

Greater Green

River Basin

\

Figure 26.—Location of Principal Tight Formation Basins

Northern

Big Horn Great Plains

Basin Province

I

Ft. Worth

Basin

Anadarko

Basin

SOURCE: Morgantown Energy Technology Center, (modified by OTA) Department of Energy

ing a specified range of permeabilities and production rates.7 The FERC definition is not universally accepted by resource appraisers, though,

and all estimates of resources and future production from tight formations must be evaluated in

——— 7Under this definition, a tight gas reservoir is one having an average permeability of less than 0.1 md and a maximum production

rate prior to stimulation, dependent on depth, of 44 MCF/d at 1,000

ft up to 2,557 MCF/d at 15,000 ft.

the context of their defined boundary conditions.

For example, the current estimate of potential gas

resources published by the Potential Gas Committee—generally considered to be an estimate

of conventional resources—contains over 150

TCF that PGC now categorizes as tight gas resources. OTA estimates that at least 30 TCF of the

gas counted as unconventional tight gas by the

National Petroleum Council in its 1980 report are

included as well i n the PGC resource estimate.
Ch. 7—introduction and Summary: Availability of Unconventional Gas Supplies 125

Resource Characteristics

Although gas from tight formations generally

is considered to be one resource, there are two

distinct types of tight formations with significantly

different producing characteristics. Blanket formations extend laterally over large areas, as

befits their name. They occur either as one thin

(10 to 100 ft thick) gas-filled layer or as many even

thinner gas-filled layers alternating with clay-rich

layers. LenticuIar formations consist of many

small discrete reservoirs, often shaped like lenses,

separated by shales and sometimes by coal seams.

They occur interspersed throughout formations

hundreds of feet thick.

Three characteristics of the reservoir rocks in

these formations are responsible for their low

permeability. First, the grains that form the rock

are small, which causes the individual pores in

the rock and the connections between these

pores to be small. This yields a very high ratio

of pore surface area to pore volume, allowing

high absorption of water which can physically

obstruct gas flow; also, the small size of the pore

connections inhibits flow. Second, the process

of dissolution and precipitation of minerals in the

rock, which has continued over geologic time,

has blocked or impaired some of the pore space

and connections between pores, further blocking gas flow. Third, the considerable amount of

clay often present in the formations can swell in

the presence of water and block flow paths, or

can break apart and plug openings. The net permeability of the tight reservoirs also will be affected by any natural fracture systems in the rock,

which provide alternative pathways for gas flow.

Technology

Because of the poor flow characteristics of the

reservoir rock in tight formations, economic levels

of gas production generally can be achieved only

by creating a manmade increase in permeability,

by fracturing the reservoir rock surrounding the

wellbore. This is most commonly achieved by hydraulic fracturing, which involves pumping a fluid

u rider high pressure into the well until sufficient

pressure is achieved to break down the rock. Because the fractures would tend to close when the

fluid is removed–especially in deep reservoirs

where the pressure of the rock is great—sand or

other materials are added to the fluid. These

“proppants” settle out of the fluids and are left

behind in the fractures when the fluid is removed,

serving as wedges to prevent the fractures from

closing.

Successful fracturing in tight formations is complex and faces substantial obstacles. Although

fracturing dates from the 1800s, and hydraulic

fracturing dates from 1947 and has the benefit

of the experience gained by thousands of separate fracturing treatments, the process is not fully

understood and extrapolation to new geologic

situations is difficult. Aside from the difficulty of

forecasting what a fracture will do, it is hard to

tell in any detail what a fracture has done even

after it has been completed and the well is producing (or has proved to be unproductive). This

is a primary reason why our extensive experience

in fracturing has not been as much benefit in projecting future performance as might have been

expected.

Despite the difficulties, fracturing has realized

considerable success in tight formations, at least

for the blanket formations. Achievement of long

fractures has become fairly consistent, and fractures over 2,000 ft long have been reported. Substantial problems do remain, however. Operators must reduce the extent to which fractures

grow vertically beyond the gas-bearing layers,

lowering the overall efficiency of the treatment

and losing reserves through water intrusion or

degradation of the reservoir “cap.” Problems

associated with transporting proppants deep into

the fracture, to prevent fracture closure, and with

drilling fluid damage to formations from the swelling or dislodging of water-sensitive clays must be

overcome. The degradation of permeability over

time, associated with gradual fracture closure or

with the blockage of pores and fractures by accumulated clay or sand, must be prevented. Also,

the level of success achieved in the blanket formations has not been transferred to the Ienticular

formations, where large-scale fracturing treatments have apparently been unsuccessful in connecting remote gas pockets, called lenses, to the

well bore—a necessary prelude to fully developing the Ienticular resource. Developers of lenticuIar formations have tended to return to shorter,
126 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

less expensive fracture treatments which may imply lower gas recovery.

Resource Estimates

Gas-in-place estimates for tight gas have been

made by the Federal Power Commission (1972),

the Federal Energy Regulatory Commission (1978),

Lewin & Associates for the Department of Energy

(1978-79), and the National Petroleum Council

(1980). These are shown in table 30. All but the

NPC study limited their estimates to basins where

detailed appraisals could be made, primarily basins in the West and Southwest. The NPC used

a method of extrapolation to incorporate basins

where less data were available, and thus it is the

only estimate for the total U.S. resource.

In general, the later estimates build on the

earlier ones, are more sophisticated, and have

had access to better data. The Lewin and NPC

estimates should be considered the most credible estimates to date of the in-place resource.

However, there are substantial remaining uncertainties in even these estimates. Especially important are uncertainties in porosity and water saturation (which affect both the amount of gas present

and its flow properties), in the areal extent and

thickness of the gas-producing portions of the

tight formations, and, in some basins, in the

geologic history as it affected gas formation and

preservation. These uncertainties are important

in the appraised basins and are critical in the

NPC’s extrapolated basins.

s porosity and water saturation limit the

amount of gas that may physically be present in the reservoir rock. These parameters

are both extremely difficult to measure accurately and may vary over a wide range

within a small area. This implies that the use

of a limited number of data points to charTable 30.—Gas-in-Place Estimates for Tight Gas

Study Gas-in-place, TCF

FPC , . . . . . . . . . . . . . . . . . . . . . . 600

FERC . . . . . . . . . . . . . . . . . . . . . 793

Lewin . . . . . . . . . . . . . . . . . . . . . 423

NPC (appraised basins) . . . . . . 444

NPC total . . . . . . . . . . . . . . . . . . 924

SOURCE’ Office of Technology Assessment.

●

●

acterize a basin—a characteristic of all the

estimates—leaves considerable room for

error.

Areal extent and thickness of the gasbearing (pay) zones are direct determinants

of gas volume. These are difficuIt to measure in several circumstances, for example,

pay thickness for blanket formations containing multiple thin gas-bearing layers

(stringers), or a real extent for Ienticular sands

when surface outcrops are not present.

Geologic history affects the volume of gas

present because’ it determines the presence

of source materials, temperature and pressure histories critical to the formation and

preservation of gas, and the availability of

a trapping mechanism. Substantial uncertainty occurs in any areas that have not been

tested by drilling, and may also exist for certain potentially productive layers in explored

territory. Areas affected by this uncertainty

include the Northern Great Plains, the Piceance Basin, the northern part of the Denver

Basin, and most of the extrapolated basins.

Although arguments have been made favoring

both higher and lower estimates of gas-in-place

than those found in the NPC estimate, with an

important exception, the arguments for neither

view seem preponderant. The exception is the

argument, based on geologic theory and on the

current low level of development activity, that

the NPC’s estimate of 150 TCF for the Northern

Great Plains’ gas-in-place is considerably too

high. In OTA’s opinion, this is a distinct possibility. Otherwise, the NPC estimate of gas-inplace for the remaining 11 appraised basins–

444 TCF minus 148 TCF for the NGP, or 296

TCF–should serve as a reasonable “most likely”

estimate for those basins. A considerable error

band-perhaps +/- 100 TCF–must be assigned to

the latter value, however. The NPC’s gas-in-place

estimate for the entire United States—924 TCF—is

considerably less reliable because of extreme

uncertainty in the 480 TCF associated with the

101 basins whose resources were estimated by

extrapolation rather than direct appraisal.

Estimates of the recoverable tight gas resources

have been made by Lewin & Associates and the

National Petroleum Council in conjunction with
Ch. 7–introduction and Summary: Availability of Unconventional Gas Supplies 127

their gas-in-place resource estimates, and by the

Gas Research Institute. These estimates are extremely sensitive to assumptions made about

price, level of technology, and gas-in-place.

Lewin and NPC first estimated technically

recoverable gas. Lewin computed a 50 percent

recovery of the gas-in-place while NPC computed

a 66 percent recovery; this reflects NPC’s more

optimistic technology assumptions, as discussed

later. Thus, Lewin’s estimate for recoverable gas

from its appraised basins is 212 TCF, whereas

NPC’s is 292 TCF for a comparable set of appraised basins, NPC estimated a total U.S.

recoverable resource of 607 TCF.

Estimates of economically recoverable gas resources vary over a wide range, from a conservative 30 TCF (base technology, $3/MCF in 1979$,

Gas Research Institute) to 575 TCF (advanced

technology, $9/MCF in 1979$, total United States,

NPC), as shown in table 31.

At one extreme, GRI’s relatively low estimates

appear to reflect its desire to be conservative and

to include only those tight resources that have

a very high probability of occurrence and recoverability. At the other extreme, the NPC’s considerably higher estimates reflect the extension

of its analysis to the entire United States, its favorable assessment of gas resources in the Northern Great Plains, and its confidence in the effectiveness of tight gas production technologies. As

noted in the discussion of gas-in-place, the extrapolated portion of the resource base and the

Northern Great Plains resource appear to be

highly uncertain. In addition, three key technology assumptions made by NPC appear to be quite

optimistic, especially if taken together. These

assumptions are:

1.

2.

3.

In

Fractures in Ienticular sands will contact

lenses distant from the wellbore. Without

such contact, gas recovery in the Ienticular

basins will be drastically reduced. At present, the ability to contact remote lenses has

not been demonstrated.

Present fracturing technology allows 1,000-ft

fractures to be consistently achieved, and

advanced technology will achieve 4,000-

ft fractures. The 1,000-ft fractures do not

appear to be the current state of the art i n

shallow (e.g., Northern Great Plains) or lenticular formations, and 4,000-ft fractures appear optimistic for advanced technology in

these same geologic situations.

The longer fracture lengths can be

achieved while reducing fracture heights,

and thus reducing fracturing costs per

foot. This is opposite to current experience.

On the other hand, there are approaches

to achieving these conditions that do appear

plausible.

OTA’s opinion, the optimism of this set of

assumptions implies that the NPC estimates of

recoverable resources shouId themselves be considered optimistic, that is, higher than a “most

likely” estimate.

In OTA’s view, all available estimates of recoverable tight gas are highly uncertain because of

poorly defined reservoir characteristics and

Table 31 .–Economically Recoverable Gas at Two Technology Levels (TCF)

Price per MCF Base Advanced

$ (study date) $ (1983) technology technology

Lewin (1977) . . . . . . . . . . 1.75 2.75 70 149

3.00 4.70 100 182

4.50 7.00 108 188

GRI (1979) . . . . . . . . . . . . 3.12 4.20 30 100

4.50 6.00 45 120

6.00 8.00 60 150

Total Appraised Total Appraised

NPC (1979) ., ... , ., . . . 2.50 3.35 192 97 331 142

5.00 6.70 365 165 503 231

5.00 6.70 365 165 503 231

9.00 12.00 404 189 575 271

SOURCE Office of Technology Assessment
128 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

technologic uncertainties. However, despite our

criticism of certain aspects of the NPC analysis,

it seems basically sound to us, and we have little

doubt that large quantities–at least a few hundred TCF–of tight gas will be recoverable provided gas prices reach at least moderately high

levels in the future (e.g., $5 to $7/MCF in 1984$).

Production Estimates

Estimates of future production of tight gas have

been made by Lewin, NPC, and GRI, as well as

by the American Gas Association (AGA).

GRI’s production estimates for the year 2000

range from about 2 to 6 TCF/yr depending on

price and technology. Because its estimates of

recoverable resources are unexplained, the

validity of this estimate is impossible to judge.

Both Lewin and NPC project high year 2000

production: 4.0 to 6.8 TCF/yr for Lewin (at $3/

MCF, 1977$), 4.1 to 15.5 TCF/yr for NPC (at

$5/McF, 1979$) depending on the phasing in of

advanced technology and the drilling schedule.

The NPC estimate is deliberately structured to

represent a goal attainable by a concerted effort

at developing the necessary technology and accelerating the pace of development.

AGA used the NPC analysis as a starting point

and superimposed more conservative assumptions about drilling rates, implementation of new

technologies, and initial production rates per

well. The result is a projected year 2000 production rate of 4.3 TCF/yr, or 3 TCF/yr if definitional

overlap between tight and conventional reservoirs is eliminated and a less optimistic outlook

for the potential of the advanced technologies is

assumed.

Several factors imply that the more conservative estimates should be considered more likely.

The slow rate of technology development in the

Ienticular formations coupled with the importance of the lenticular Rocky Mountain Basins in

the optimistic estimates is a critical factor. Similarly, the Northern Great Plains would normally

be expected to play a major role in future development because much of the resource is projected to be recoverable at relatively low cost;

however, here, too, there is controversy about

the magnitude of gas available. The absence of

pipelines in many potential tight gas production

regions also implies a lower rate of development

unless the market for new gas supplies improves

dramatically in the near future.

Aside from being sensitive to geologic (accessibility of Ienticular resource, magnitude of Northern Great Plains gas) and technologic assumptions, future production is also extremely sensitive

to gas prices and to the availability of competing,

and less costly, conventional gas prospects. OTA

is extremely skeptical of the possibility of reliably

forecasting either gas prices or conventional gas

availability in the time frame in question. Consequently, the range of plausible scenarios for

future incremental tight gas production encompasses a year 2000 production rate of only 1 or

at most 2 TCF/yr if conventional gas production

remains at high levels or if gas markets do not

rebound from their current slump, or a rate of

3 to 4 TCF/yr, or perhaps even somewhat higher,

if there are major technology advances and a

combination of strong markets and high prices

for unconventional gas, the latter in response to

disappointing prospects for conventional gas supply or a surge in gas demand.

——

80ver and above product mn from tight format Ions now bw ng

exploited. Current production is about 1 TCF/yr.

GAS FROM DEVONIAN SHALES

Definition from the accumulation of organic-rich sediments

in a shallow sea covering the eastern half of what

Devonian shale gas is gas produced from shales now constitutes the continental United States.

formed approximately 350 million years ago– The first Devonian shale gas well was drilled in

during the Devonian period of geologic time– 1821, near Fredonia, NY, and moderate levels
Ch. 7—introduction and Summary: Availability of Unconventional Gas Supplies ● 129

of gas production (recently somewhat less than Resource Characteristics

0.1 TCF/yr) have continued to the present. However, despite its long history, the Devonian shale The Devonian shales occur primarily in the Apresource is still considered “unconventional” be- palachian, Illinois, and Michigan basins, shown

cause of its highly complex geology and because in figure 27. Past production has been primarily

new technology and higher prices will be re- in a small portion of the Appalachian Basin, in

quired to exploit the major share of its potentially the Big Sandy Field in Kentucky and adjacent

recoverable gas. West Virginia. The shales are highly variable in

Figure 27.—Primary Area of Devonian Shale Gas Potential

\ \ Basin/’

)

SOURCE Johnston & Associates, OTA contractor
130 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

their makeup; they can be grouped according to

color, with black and brown shales having higher

organic content and gas content than the gray

shales. The shales are a rich source rock for natural gas, but their porosity and permeability are

very low compared to conventional gas reservoirs.9 Consequently, gas content and flow rate

also are low by conventional standards. Further

complicating exploitation of the gas resource, the

shales are sensitive to “formation damage’’—an

induced decrease in permeability—because they

contain water-sensitive clays that can be dislodged by fracturing fluids and block pores and

fractures.

Portions of the shale contain networks of natural fractures, which tend to be predominantly

i n a vertical pattern. These fractures also tend to

be somewhat lined up rather than random in direction, a characteristic called “anisotropy.” The

fracture systems provide potential flow paths for

shale gas.

The shale gas occurs as free gas in the fractures

and pores of the shale and also as gas bound to

the physical structure of the shale (adsorbed gas).

The amounts and production mechanisms of the

different modes of occurrence of gas are not fully

understood, and this lack of understanding complicates estimation of the recoverable resource.

A primary uncertainty is the contribution of adsorbed gas to total production. Most early estimates of shale gas resources are based on the notion that the primary source of producible gas is

the free gas in the shale’s fracture network.

Recently, many in the research community have

shifted to the view that gas adsorbed on the shale

makes the major contribution to gas production.

Technology

As with the tight sands, production of Devonian shale gas depends on well stimulation to overcome formation damage and the naturally low

permeability of the reservoir and open up path9Porosities generally are 1 or 2 percent compared to 8 to 30 percent in conventional reservoirs; permeabilities range from 0.001

to 1.0 md compared to 1 to 2,000 md in conventional reservoirs.

The permeability difference means that, all else being equal, gas

WI II f]~w 1 m i Illon to 2 m I I lion times faster i n a conventional reservoir than in the Devonian shales.

ways for the gas to flow to the well bore. Unlike

the tight sands, however, production using current technology generally cannot succeed unless

the well intersects a natural fracture network, either directly or through an induced fracture. An

important uncertainty is the extent to which new

technological development will allow production

from portions of the shale that do not contain a

well-developed natural fracture network. Also

unlike the tight sands, producers generally have

used small fractures in the shales, a few hundred

feet or less, not the massive 1,000-to 2,000-ft fractures becoming more popular in the Western

tight sands.

Because of their extreme sensitivity to formation damage, the Devonian shales have been a

primary target for the development of new fracturing techniques that avoid such damage. Stimulation by the use of explosives has been prevalent in the shales’ production history, and more

sophisticated explosive techniques may be promising for future development. Also, the shales

have been a testing ground for new fracturing

fluids, including gas-in-water emulsions, nitrogen,

liquid carbon dioxide, and others. The gas-inwater emulsions, or foams, have dominated fracturing in the Devonian shales in recent years, but

nitrogen has also grown in use for shallow wells

because it does not cause formation damage. Nitrogen has limited ability to carry proppants, so

it is less useful at depths where the induced fractures would close under the overburden pressure

of the rock.

Fracturing has been extremely successful for

many Devonian shale wells, but its overall record is very erratic. problems include extreme

variation in the natural fracture systems from site

to site, lack of a systematic scientific method in

applying and evaluating fracture treatments, and

difficulties in accurately locating the gas-bearing

zones. An unfortunate result of the trial-and-error

approach is that no scientific basis for selection

of appropriate well stimulation techniques has

been developed.

Aside from problems encountered in fracturing, development of the Devonian shale resource

also is hindered by problems in exploration and

well location. in general, sophisticated explora-
Ch. 7—Introduction and Summary: Availability of Unconventional Gas Supplies ● 131

tion technology, such as seismic reflection, is not

used in shale development. Besides the technical problems, which include adverse terrain and

lack of effectiveness of existing technology, the

usual incentive for expensive geologic surveys—

the ability to exclusively develop the surveyed

area—is hampered by diverse land ownership

and inadequate State regulatory systems that do

not fully protect discovery rights.

Resource Estimates

Several estimates have been made of the Devonian shale gas-in-place and recoverable resources. For example, recent estimates of the gasin-place by the National Petroleum Council

(1980), U.S. Geological Survey (1982), and Monsanto’s Mound Facility (1982) encompass a range

of 225 to 2,579 TCF for the Appalachian Basin,

the most significant of the three shale basins by

far. Differences in the estimates are caused primarily by the following factors:

. the use of different boundary conditions for

inclusion in the estimated gas-in-place resource;

s including or excluding the less productive

gray shales;

● substantial differences in the shale thickness

calculations because the measurement techniques were different;

varying levels of geochemical analysis undertaken (this analysis can identify areas where

temperature and pressure conditions were

poor for gas formation and preservation); and

different views about the amount of gas in

each “mode” of occurrence within the shale

(in fractures, in micropores, or bound to the

shale), and the extent to which it is properly

measured in available studies of gas content. ‘O

Although no consensus about all of these factors currently exists, OTA considers it likely that

the Devonian shale gas-in-place is large, at least

500 TCF and more likely well over 1,000 TCF.

The size of the in-place resource is not really the

major issue, however, Because, in general, the

shale is a low-quality gas resource and economic

returns will be low, the major issue is the size of

the economically recoverable resource.

Table 32 shows seven different estimates of Devonian shale recoverable resources. The estimates

are not easily comparable because of differences

in technology and economic assumptions, but

they appear to display a fairly broad range of expectations about future shale gas development.

For example, the 1977 OTA study estimates a

~~Recent studies have ind Icated that most gas content measu r~-

ments must be adjusted to account for gas that has escaped from

the shale samples prmr to measurement.

Table 32.—Devonian Shale Recoverable Resource Estimates (TCF): Appalachian Basin

Organization Year Estimate Conditions

Office of Technology Assessment. . . . . 1977 15-25

23-38

Lewin & Associates . . . . . . . . . . . . . . . . . 1978-79 2-1o

4-25

Traditional Advanced

National Petroleum Council . . . . . . . . . . 1980 3.3 - 38.9

15.3 - 49.9

Pulle and Seskus (SAI). . . . . . . . . . . . . . . 1981 17-23

Zielinski and Mclver (Mound) . . . . . . . . . 1982 30-50

Lewin & Associates . . . . . . . . . . . . . . . . . 1983 6.2-22.5

Lewin & Associates . . . . . . . . . . . . . . . . . 1984 19-44

After 15 to 20 years

After 30 to 50 years

At $2-$3/MCF (1976$), current technology

(borehole shooting or hydrofracturing),

150-acre spacing

Base case

Advanced case for prices between $1.75-$4.50

For price levels between $2.50-$9, 160-acre

spacing

Technically producible

“Shot” wells, 160-acre spacing

For States of West Virginia, Ohio, and Kentucky

only, ’’shot” wells, 160-acre spacing

Technically recoverable, for most promising formations in Ohio. Maximum represents 80-acre

spacing, advanced technology

Technically recoverable, for most promising formations in West Virginia. Preliminary values

SOURCE” Off Ice of Technology Assessment
132 U.S. Natural Gas Availability: Gas Supply Through the Year 2000

large recoverable resource–up to 40 TCF–at

moderate prices and using conventional technology. The 1977 Lewin study and the NPC study

are considerably more pessimistic for similar technology/price conditions, with estimates centering on about 10 TCF or lower. ” Both Lewin and

NPC expect sharp increases in recoverable resources with higher gas prices and improved

technology, however. Lewin, for example, projects a rough doubling of recoverable resources

through advanced technology that allows a sharp

reduction in dry holes, completion of multiple

zones through each well, and more effective fractures. And NPC projects a similar doubling of resources as prices move from the $2.50 to $5.00/

MCF range to the $5.00 to $9.00/MCF range. Finally, recent studies by Lewin of currently producing portions of the shale in Ohio and West

Virginia, using a new reservoir simulation model,

indicate that a substantial increase in gas recovery

can be obtained with improved fractures, reduced spacing of wells, and more efficient well

placement that take account of the shale’s low

permeability and anisotropy.

Aside from differences in assumptions about future gas prices and other economic conditions,

differences in estimates of Devonian shale gas

recoverable resources arise from several technical uncertainties. One type is the set of geological uncertainties that underlie differences in the

gas-in-place estimates, as described previously.

Other uncertainties are associated with the:

● ability of new stimulation technologies to immediately increase the flow rate and maintain an economic rate over the long term;

● ability of new exploration techniques to

overcome the problems of finding areas with

well-developed natural fracture networks;

● ability of advanced well-logging techniques

to accurately identify gas-bearing zones and

allow greater stimulation success;

● development of production techniques that

will allow economic production from shale

formations that do not have a well-developed fracture network; and

● the extent to which methane bound to the

shale matrix plays a major role in production.12

[n OTA’s view, all of the existing studies that

estimate recoverable shale gas resources for specified gas prices and technologies have significant

methodological and/or data shortcomings. For example, because of data limitations, the 1977 OTA

study did not undertake a quantitative analyis of

the geology of the Appalachian Basin; instead,

it was forced to assume that 10 percent of the

basin area would allow gas production at levels

similar to the small area now under production.

The early Lewin study evaluated recoverable resources using the assumption that most of the

recoverable gas was fracture gas, an assumption

now being challenged. And the NPC study uses

an empirically derived equation for calculating

the recoverable gas that does not include several

variables—e.g., fracture density and thermal maturity of the shale—that appear to be critical to

the existence of recoverable gas. However, the

recent Lewin analyses do combine a detailed reservoir simulation approach with the latest available data, and probably should be considered the

most credible analyses to date. Based on our interpretation of the Lewin work, OTA considers

it plausible that moderate increases in gas prices

coupled with a vigorous research program to improve well stimulation, well diagnostics (e.g., logging), and exploration techniques and to advance

the state of knowledge of shale geology and production characteristics could yield substantial

quantities of recoverable gas from the Devonian

shales in the Appalachian Basin, Although the

level of uncertainty associated with any estimate

is high, a figure of 20 to 50 TCF for the recoverable resources in the fractured portions of the

basin seems reasonable, assuming prices somewhat higher than today’s (perhaps $5/MCF), optimization of fracturing technology currently in

development, and easing of institutional barriers

to development (including rationalization of well

spacing rules). A combination of still higher

prices–in the range of $7 to $10/MCF–and advanced technology might boost the recoverable

I I However, the Lewin estimate is predicated on a higher discount

rate because of its perception of higher risk.

12A major role in production for adsorbed gas implies a substantially increased gas resource.
Ch. 7—introduction and Summary: Availability of Unconventional Gas Supplies ● 133

resources to the 80 to 100 TCF level or higher.

Development of methods to produce gas economically from shales that do not contain welldeveloped natural fracture systems could substantially increase the recoverable gas resource still

further; however, it is important to recognize that

the problems associated with developing these

unfractured shales may be insurmountable.

Production Estimates

As with the tight gas analyses, those studies that

projected future production from Devonian

shales did so by relying on “educated guesses”

about available rigs and well drilling rates. All of

the Devonian shale studies concluded that production within the next few decades would be

limited to relatively moderate levels. For example, the 1977 OTA study concluded that 1.0

TCF/yr could be achieved 20 years after commencing an intensive drilling program. The first

Lewin study projected a maximum production

rate of 0.9 TCF/yr in 1990 with advanced technology and $4.50/MCF gas in 1977$ ($7.00/MCF

in 1983$), but this was predicated on starting the

development effort in the late 1970s. Also, the

Lewin study projected a maximum rate of only

0.3 TCF/yr with currently available technology.

Finally, the NPC study projected a high of about

1.4 TCF/yr in 2000 with advanced technology and

very high gas prices ($9/MMBtu in 1979$). At prices

more in line with today’s, however, production

would have been only a fraction of this.

Development of the Devonian shales will be

critically dependent on market conditions, which

today are distinctly unfavorable to rapid advances

in production and certainly have delayed the development schedules projected in the early studies. Furthermore, a rapid buildup of production

would be hindered by institutional problems,

divided land ownership, and difficult terrain. On

the other hand, the most recent Lewin studies

of Ohio and West Virginia conclude that advanced extraction technology and improved well

placement could substantially increase individual well productivity and total recoverable resources. This implies a potential for a rapid

buildup of production under the right price and

technology conditions. if market conditions improve very soon and exploration and production

technology advances are achieved, OTA considers a production rate of 1.0 to 1.5 TCF/yr from

the Devonian shales by the year 2000 or soon

thereafter to be plausible, although optimistic.

COALBED METHANE

Definition

Coalbed methane is natural gas formed as a byproduct of the coal formation process and trapped

thereafter in the coal seams. Unlike gas from tight

sands and Devonian shales, past production of

coalbed methane has been very low. ’ 3 However,

some important commercial recovery operations

have begun in New Mexico’s San Juan Basin, in

Alabama’s Warrior Basin, and elsewhere. Also,

in the United States roughly 80 billion cubic feet

(BCF) of coal gas is deliberately vented to the

atmosphere each year from working coal mines,

to remove the danger of explosion created by the

1 JHowever, gas formed i n coal seams and trapped i n adjacent

formations has been produced In quantity.

buildup of methane concentrations in the mine

shafts.

Resource Characteristics

Methane is found in all coal seams, although

its amount per unit volume or weight of coal

tends to be proportional to the rank (carbon content) of the coal: higher rank coals such as anthracite and bituminous coals may have from 200

to 500 cubic feet of methane per ton of coal,

whereas the lowest rank lignite may contain 30

to 100 cubic feet per ton (CF/t). Gas content also

increases significantly with depth; Kuuskraa and

Meyer, in their analysis of coalbed methane gasin-place, assign an average gas content to bituminous coal of 150 CF/t for 1,000 to 3,000 ft
134 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

depths, and 400 CF/t for depths greater than

3,000 ft.14

The methane is found either adsorbed to the

coal surfaces-by far the most abundant source—

or trapped in the coal’s natural fracture system,

or “cleat.’ The fracture system tends to be

aligned so that, in an idealized form, the fractures

resemble a series of vertical, parallel slices made

in a block of coal—the “face cleats’ ’—with another,

less well-developed series of vertical slices, the

“butt cleats, ” perpendicular to the face cleats.

Because most coal beds are aquifers, water is also

present in the fracture network, and its hydrostatic pressure plays a key role in keeping the

methane from desorbing from the coal.

Technology

Because coal is essentially impermeable, methane production depends on intersecting the natural fracture network to provide pathways for the

gas to flow to the well. A second condition necessary for economic levels of production is to promote the resorption of the gas from the coal into

the fracture system by reducing the pressure in

the fractures. This usually involves dewatering the

coal to reduce hydrostatic pressure. Because the

rate of resorption is not a linear function of

pressure–as reservoir pressure drops, resorption

may remain low until a critical pressure is

reached, and then accelerate rapidly as the pressure drops further-effective gas recovery may

require drilling wells on relatively close spacing

and pumping water from them rapidly and simultaneously in order to maximize the pressure drop.

This production method will also help to outrun

water infiltration into the coal seam. This practice of close spacing is in sharp contrast to the

wide spacing used in conventional gasfields, because the close well spacing tends to reduce

recovery per well in conventional fields.

A variety of methods can be used to enable

wells to intersect the vertically oriented natural

fracture network. Horizontal wells may be drilled

I ~V. A. Kuuskraa and R. F. Meyer, ‘‘Review of World Resources

of Unconventional Gas, ” IIASA Conference on Conventional and

Unconventional World Natural Gas Resources, Luxenburg, Austria,

june 30-july 4, 1980.

from within a working mine or a specially drilled

shaft. The latter method is extremely expensive,

however. Vertically drilled wells may be slanted

towards the horizontal, ideally so as to run parallel to and within the coal seam. Keeping the

well within the seam is difficult, however, and

there are substantial operating problems leading

to increased costs. Hydraulic fractures also can

be used to connect the well bore to the fracture

system. However, induced fractures in the coal

seams tend to be short and tend to parallel rather

than intersect the planes of the natural fractures.

in minable seams, the tendency of the fractures

to propagate vertically may result in damage to

the rock above the seam, a potential hazard to

future mining. Finally, a variety of problems associated with well dewatering, formation damage,

etc., still face future efforts to recover coal seam

methane. Although for the most part these problems appear to be a matter of refining and upgrading existing methods and technology rather

than accomplishing major innovations, considerable basic research is required to understand

the controlling gas production mechanisms, develop an exploration rationale for identifying attractive drilling sites, and develop advanced well

stimulation technology.

Resource Estimates

Gas-in-place estimates for coal seam methane

have been made by a variety of analysts and organizations, including most recently the Gas Research Institute (1980), National Petroleum Council (1980), Kuuskraa and Meyer (KM) of Lewin &

Associates (1980), and the Department of Energy

(1984). These and others are shown in table 33.

The three 1980 studies all use basically the

same method—to multiply USGS-derived estimates of coal tonnage, subdivided according to

rank, by estimates of gas content for each rank.

The narrow spread of estimates–398 TCF (N PC)

to 550 TCF (KM) —reflects the methodological

similarity. These estimates should be considered

as quite crude, because the available data on gas

content are limited and variable, and the USGS

estimates of deep coal resources below 3,000 ft—

particularly important because gas content increases with depth—are uncertain.
Ch. 7—introduction and Summary: Availability of Unconventional Gas Supplies ● 135

Table 33.—Coalbed Methane Resource Estimates

Resource in place

Studv TCF

Department of Energy (1984) . . . . . . .

Kuuskraa and Meyer (1980) . . . . . . . .

National Petroleum Council (1980) . .

Gas Research Institute. . . . . . . . . . . .

Federal Energy Regulatory

Commission (1978) . . . . . . . . . . . . .

Deul and Kim (1978) . . . . . . . . . . . . . .

Wise and Skillern (1978) . . . . . . . . . . .

TRW (1977 . . . . . . . . . . . . . . . . . . . . . . .

National Academy of Sciences

(1976) . . . . . . . . . . . . . . . . . . . . . . . . .

68-395

550

398

500

300-850

318-766

300-800

72-860

300

Table 34.—Comparison of Recoverable Resource

Estimates (TCF)

Technically or economically recoverable gas:

KM 40-60a

NPC . : : : $2.50 $5.00 $9.00

5 25 45 10% RORb

2.5 20 38 15% ROR

2.0 17 33 20% ROR

GRI . . . . $3.00 $4.50 $9.00

10-30 15-40 30-60

aTechnically recoverable resource.

bRate of return

SOURCE Office of Technology Assessment

SOURCES Adapted from AGA Gas Energy Review, September 1982, and C W

Byrer, T H Mroz, and G L. Covatch, “Production Potential for Coalbed

Methane in U S. Basins,” SPE/DOE/GRl Unconventional Gas Recovery

Symposium, 12832 1984

The recent DOE study, a portion of its Methane Recovery from Coalbeds Project, is a basinby-basin analysis targeting only the most likely

gas-bearing seams in each basin. Although all

basins are not included and each individual basin

estimate does not include all potential gas-bearing

areas i n that basin, the focus on the most promising coal seams implies that the estimates may

represent a good starting point for evaluating

recoverable resources. However, the range of

uncertainty in the multi-basin estimate, 68 to 396

TCF, was exaggerated by the method used to calculate the extremes of the range.

Estimates of the recoverable resource base have

been made by the NPC (1 980), KM (1980), and

GRI (1981). A summary of results appears in table

34. The GRI estimate is the result of a poll of experts. The NPC estimates are derived by first differentiating the gas-in-place resource according

to estimated production levels (million cubic feet

per day per well), and then comparing per well

revenues at any given price to the estimated costs

of an ‘‘average’ well in order to determine

whether the gas is economically recoverable at

that price. Uncertainties in the NPC results stem

from a series of very broad assumptions about

gas content, recovery efficiency, the relationship

between coal seam thickness and gas production,

the expected long-term production behavior of

gas wells in coal beds, and several other factors.

An important criticism of the NPC analysis is that

it relies for its data base on isolated, previously

drilled wells that are considerably less productive than new wells drilled according to the modern practice of close pattern drilling, and thus is

too pessimistic. OTA concurs with this criticism

but feels that the other areas of uncertainty, some

with less predictable effects, are at least as important.

The Kuuskraa and Meyer analysis differs substantially from the others in that it uses an analytic

model of gas production from coal seams, treating production as a simple diffusion process. The

results are extremely sensitive to assumptions

about the spacing of the vertical fractures in the

coal seam and the magnitude of the diffusion constant. Also, while simple diffusion may be the

controlling factor in some coal beds, it is likely in

most cases that the actual physical process is considerably more complicated and the simple model used in the analysis will yield only very approximate results.

In OTA’s opinion, none of the existing analyses provide an adequate basis for reliably estimating the size of the coal bed methane recoverable

resource. It is possible that recent basin analyses sponsored by DOE might provide enough

new basic data to form a basis for a more credible estimate of recoverable gas. However, it is

not clear that we have sufficient understanding

of the production mechanisms to provide a truly

new, credible estimate as yet. Because of this lack

of understanding, an estimate of recoverable resources that attempted to encompass the credible resource possibilities would have to span a

wide range, probably on the order of 20 to 200

TCF or so.
136 ● U.S. Natural Gas Availability.’ Gas Supply Through the Year 2000

Production Estimates

Both NPC and GRI calculated annual production estimates based on assumed drilling

schedules. The NPC estimate assumes a continuously rising gas price from the present to

2000, with prices reaching as high as $9/MMBtu

(in 1979$) by 2000. production is projected to

peak at more than 2 TCF/yr in the late 1990s. The

GRI estimates are both price and technology dependent. At $3/MCF (1979$) and using existing

technology, only 0.3 TCF/yr of production is projected for the year 2000. At $6/MCF and advanced technology, 1.4 TCF are projected,

The level of uncertainty associated with these

estimates is very high. The physical character of

the resource base is highly variable, so that past

experience, which is limited anyway, cannot

serve well as a guide to future production, The

physical mechanisms controlling gas production

from coal seams are not well understood. Furthermore, there are important uncertainties concerning legal ownership of the gas, environmental

constraints associated with water disposal, unresolved mine safety issues, and other factors that

may serve to constrain future gas development;

the effects of these factors is difficult or impossible to predict.

On the other hand, successful development efforts such as U.S. Steel’s effort in the Black Warrior Basin and others provide encouragement that

coal seam methane could prove to be an important future gas source. Estimates projecting production of 2 TCF/yr by 2000 may seem excessive from

our present vantage point but conceivably could

become more credible with advanced technology and strong demand. Key targets for technology development and research include characterization of the deep coal resource, improvement

of fracturing technology and deviated drilling

technology, and improved understanding of the

geologic characteristics affecting gas recovery,

leading to a reliable estimate of the recoverable

resource.
Chapter 8

Tight Gas
Contents

Page

Introduction . . . . . . . . . . . . . . . . . . . . .. ...139

Characteristics of the Tight

Gas Resource . .....................139

1) l--low Much Gas is Present?. . .......140

2) How Well Can the Gas Flow? .. ....141

3) How Will Technology Perform .. ....142

Gas-In-Place Estimates . ................142

Methodologies . . . . . . . . . . . . . . . . . . . . .142

Estimate Comparison and Discussion

of Uncertainties . . . . . . . . . . . . . . . . . . . .145

Technology. . . . . . . . . .................149

Hydraulic Fractures . ................149

Reservoir Characterization

Technologies . . . . . . . . . . . . . . . . . . . . .. .154

Exploration Technologies . ............156

New Technologies and the Industry .. ..156

The Recoverable Resource Base and

Production Potential . . . . . . . . . . . . . . . . . . 157

Methodologies and Results . . . . . . . . . . .. .157

Comparison of Estimates and

Discussion of Uncertainties . ..........161

Annual Production Estimates . .........168

TABLES

Table No. Page

35.

36.

37.

38.

39.

Tight Gas-in-Place Estimates (in TCF) ..144

National Petroleum Council’s Gas-inPlace Estimates. . ..................145

Conventional and Tight Gas Wells

Compared . . . . . . . . . . . . . . . . .......150

Maximum Recoverable Tight Gas

Resources, TCF . ..................157

Economically Recoverable Gas at

Two Technology Levels (TCFs) . ......158

Table No. Page

40.

41.

42.

Lewin & Associates Base v.

Advanced Technology. . ............158

NPC Base v. Advanced Technology

and Regulation. . . . . . . . . . . . . . . . . . . .160

Projections of Annual Tight Gas

Production, TCF . . . . . .: . ............169

FIGURES

Figure No.

28. Primary Tight Gas Basins

29. Problems With Reservoir

Page

. . . . . . . . . . . 1 4 3

Mapping in

30

31

32

33

34

Lenticular Formations . .............148

Conceptual Fractures Created by

Massive Hydraulic Fractures for

Blanket and Lenticular Formations. .. .151

Comparison of Recoverable

Estimates. . . . . . . . . . . . . . . . . . . . . .. ..162

Comparison of NPC Study Results

With GRI Present Case–Tight Gas

Sands Recoverable Gas. . ...........164

Annual Tight Gas production

Estimates. . . . . . . . . . . . . . . . . . . . . .. ..170

Incremental Tight Gas Sands

Production Rates As a Function

of R&D Advances . . . . . . . . . . . . . . . .. 172

35. Annual Production by Basin–NPC

$5.00/MCF (1979$), 150/0 DCF ROR

Standard Scenario . ................173

36. Incremental Tight Sands Gas

37

38

Production Rates With and Without

the Northern Great Plains Resource .. 173

Incremental Tight Sands Gas

production Rates As a Function

of Rate . . . . . . . . . . . . . . . . . . . . . . . . . . .174

Incremental Tight Sands Gas

Production Rates As a Function

of Discount Rate . . . . . . . . . . . . . . . . . .174
Chapter 8

Tight Gas

INTRODUCTION

“Tight gas” is natural gas that is found in rock

formations of extremely low permeability. Such

low-permeability formations are found in all gasproducing basins in the United States. Depending

on the volume of gas-in-place and the economic

viability of its extraction, tight gas formations may

constitute a large potential gas resource.

Because of the low permeabilities, fluid flow

(both gas and liquid) through tight gas formations

is highly restricted. Commercial volumes of gas

can only be recovered by artificially fracturing the

rock to increase the area of the reservoir in contact with the wellbore. Considerable difficulties

in measuring key reservoir parameters in tight formations and establishing the productive areas and

zones leads to high uncertainty about the commercial viabiIity of the well until after an expensive fracturing treatment is completed and the

well has produced for some time.

The tight gas resource, of all the unconventional natural gas resources, is thought to have

the most potential for contributing to U.S. supply

in the next 20 years. Low levels of gas have been

produced from tight gas formations for many

years; significant development began in the early

1970s with the successful use of massive hydraulic fracturing techniques in the Wattenberg Field

in Colorado. Incentive prices established in 1979

by the Natural Gas Policy Act (NGPA) increased

the relative attractiveness of the resource and promoted development in the early 1980s. Since

then, however, interest in gas production from

this difficult resource setting has declined as price

levels for tight gas dropped in response to the current supply surplus.

CHARACTERISTICS OF THE TIGHT GAS RESOURCE

Tight gas formations are defined in this report

as low-permeability sandstone, siltstone, silty

shale, and limestone’ formations deposited in

continental, shoreline, or marine environments.

Earlier studies have used the terms “tight sands”

or simply “tight” formations in addition to tight

gas to refer to this resource. Some of the early

studies included Devonian shales as tight gas formations, but later studies dealt with the shales

separately because of their different production

mechanisms and characteristics. This chapter also

excludes Devonian shales from the “tight gas”

category, treating them in chapter 9 as a separate unconventional resource.

I Except for the Edwards LI me format Ion I n the Southwest,

limestone formations have not been Included In tight ~as resource

aswssments. ]oh n S h a rer, Gas Rewarc h I n st It ute, persona I com

munl[ atlon, 1984,

Tight gas reservoirs represent the low permeability end of a continuum of gas-producing reservoirs rather than a unique type. In the past, the

cutoff between a conventional and a tight gas

reservoir has been somewhat arbitrary, based primarily on the economics of production or requirements for special production techniques.

The permeability levels used to define the upper

boundary for tight gas have ranged from 0.01

millidarcy (md)2 to 1 md; most formations identified as tight have permeabilities less than 0.1 md.

(For comparison, the permeability of cement is

on the order of 0.001 red.) The granting of a speciaI price incentive to tight gas under the NGPA

necessitated a more precise definition. In 1978,

the Federal Energy Regulatory Commission de-

—..—

2 A millidarcy, abbreviated a~ ‘‘red, ” is a standard unit of

permeability, which measures the ease with which flulds (llquld\

and gases) can flow through porous rock.

139
140 ● US. Natural Gas Availability: Gas Supply Through the Year 2000

fined a tight gas reservoir as one having an average permeability of 0.1 md or less at subsurface

(in situ) conditions of confining pressure and

water saturation, and a maximum production rate

prior to stimulation, dependent on depth, of 44

MCF/D at 1,000 ft up to 2,557 MCF/D at 15,000 ft.

The boundary between conventional gas and

unconventional tight gas is still changing and will

continue to change with changing economics

and the further development of production technology for low-permeability reservoirs. Consequently, all estimates of resources and future production from tight formations must be evaluated

in the context of their defined boundary conditions. Currently, the American Gas Association

is reexamining its definition of the conventional/unconventional boundary. It appears likely that

a result of this process will be to transfer resources

from the unconventional to the conventional category. The subsequent decline in the projected

tight gas potential actually would reflect the

recognition that current technology can allow access to a substantial portion of this resource.

In evaluating the potential gas recovery from

a well drilled into a tight gas formation, three

questions need to be answered: 1) How much

gas is present? 2) What conditions exist that control the flow of gas? and 3) Can extraction technology be successfully applied in this setting?

1) How Much Gas is Present?

The occurrence of gas in a given section of a

formation is dependent on whether adequate

source rocks and appropriate temperature conditions have existed which allowed gas to form.

The ability of the gas to migrate and the presence

of a trapping and a sealing mechanism are further requirements.

In the case of most tight gas reservoirs, the presence of interbedded organic shales or coal seams

ensures an adequate source for gas formation,

By the same token, migration is not a problem

since the gas does not have to travel far. The low

permeability of the formations themselves, together with the overlying shales or other sealing

rocks, confine the gas within the sandstones. In

many areas, gas is being produced from nearby

conventional reservoirs, and the required temperature conditions may sometimes be inferred.

However, any estimation of potential tight gas resources in unexplored areas should consider

these temperature conditions as additional uncertainties.

Some of the tight gas formations deposited

under shallow marine conditions, such as those

in the Northern Great Plains, may represent an

unusual type of natural gas occurrence. In these

areas it has been suggested that the methane has

formed biogenically (and at low temperatures and

pressures) through decomposition of organic material by micro-organisms. s Biogenic gas formation allows gas to be present in areas that otherwise might be assumed not to be gas-bearing,

because they have never been exposed to the

higher temperatures and pressures generally associated with gas formation (see ch. 3).

Given that gas is present, the amount present

in any portion of a tight gas formation is primarily a function of the porosity, temperature, and

pressure. These parameters define the space

available to be occupied by gas molecules and

the amount of gas that can be found in each unit

volume of available space. Water saturation is

also an important criterion as water competes

with gas for the available space.

Porosity is the fraction of the rock that is void

space, i.e., the space remaining between and

within mineral grains, after the grains are packed

together. Dissolution and precipitation of material by fluids percolating through the rock may

alter the original porosity. Porosity of tight gas formations typically ranges from 3 to 12 percent.4

Conventional reservoir porosities range from 14

to 25 percent or more.

Pore size is an important determinant of the

water saturation of the rock, and thus of gas volume. Very fine grained rocks such as siltstones

and chalks, may have high porosities but the individual pores are very small, resulting in a high

pore surface area to pore volume ratio. Water

3D. D. Rice and E. C. Claypool, “Generation, Accumulation, and

Resource Potential of Biogenic Gas, ” AAPG Bu//etin, vol. 65, No.

1, january 1981.

4

That is, 3 to 12 percent of the rock volume is void space.
Ch. 8—Tight Gas ● 1 4 1

molecules may be adsorbed on pore surfaces, reducing the volume available to be filled by gas

and increasing the water saturation. Because of

small pore sizes, tight gas formations are generally characterized by high to very high water

sat u rations.

2) How Well Can the Gas Flow?

The most important reservoir characteristic to

consider in terms of the recovery of gas from tight

gas formations is permeability because this ultimately controls how fast the gas can be produced.

Permeability is a measure of the ease with which

fluids can move through interconnected pores of

the reservoir rock in response to a pressure gradient. Thus, a volume of rock can be both porous—have a high percentage of void space—

and have very low permeability if the individual

void spaces are not interconnected or the channels are too narrow to allow gas to move freely.

Permeabilities of conventional gas reservoirs

range from 1.0 md to several darcies (thousands

of millidarcies). In contrast, the permeability of

a tight gas reservoir can be as low as 0.00001 md

(although at present, recovery generally is limited

to reservoirs with permeability greater than about

0.007 red).

The low permeabilities of tight gas formations

result from a combination of factors that close

off connections between pores, including small

grain size, high clay content, and the cementation of grains resulting from the precipitation of

dissolved materials.

In very fine grained and recrystallized rocks,

where connections between pores are very small,

the level of water saturation is a key factor in

determining relative gas permeability. Several

studies have demonstrated that water saturations

on the order of 60 to 70 percent can effectively

reduce the permeability to gas to zero.

Clay content and composition in a formation

is another important factor in determining its

permeability. Many clays are formed after deposition and tend to grow in such a way as to block

pores and pore throats. Certain types of clays are

expandable on contact with freshwater. The large

volumes of water introduced during driIIing into

a formation by drilling muds and fracturing fluids

can cause such clays to swell, further reducing

permeability of the formation. Gas and water flow

can also reduce permeability by displacing and

plugging openings with loosely aggregated or

platey clays.

All the factors discussed above affect the matrix permeability of the reservoir rock itself,

disregarding any faults or fractures. The bulk

permeability of the entire reservoir, however, may

be greater if there is a well-developed natural fracture system. Natural fractures occur as a result

of unequally distributed stresses at any time during or after formation of the rock. They are ubiquitous in all rock formations and occur at all

scales. Large fractures may extend for long distances, while microcracks are found at the scale

of the smallest grain. At greater depths, under

high overburden pressures, most small cracks and

some larger fractures are closed. Deposition of

crystalline materials by migrating fluids also can

seal off fractures. s Nevertheless, the existence of

natural fractures is extremely important to the net

permeability of tight gas formations.

The flow of gas in tight formations is also a function of the shape of the reservoirs and their lateral

continuity—whether or not they exist as continuous bodies spread over large areas or instead

occur as multiple smaller, discontinuous units.

Lateral continuity and geometry of gas-bearing

units control how much gas can find a flow path

to the wellbore. Most studies have responded to

the differences in these characteristics among the

various tight formations by subdividing the formations into two categories commonly referred

to as blanket formations and Ienticular formations.

Blanket formations consist of continuous gasbearing deposits that extend laterally over a large

area. Blanket reservoir units, 10 to 100 ft thick,

may be composed of sandstone, siltstone and silty

shale, or chalk or limestone interbedded with

very low permeability shales or non marine de-

‘However, If fractures form after hydrocarbons ha~e d)splared

the water layer, the fractures usually remain open. The mineral

saturated water is no longer present to precipitate solid crystals (Ovid

Baker, Mobile Research & Development Corp., personal commu -

nlcatlon, 1984).
142 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

posits, including coal seams. Alternatively they

can occur as millimeter to centimeter thick sandrich layers, or “stringers,” alternating with clayrich layers. The bulk of current tight gas production is from reservoirs in blanket formations.

Lenticular formations consist of many relatively

small, laterally discontinuous sandstone and

siltstone units, or “lenses,” intermingled with

shales and sometimes coal seams. These units are

similar in mineral composition to the blanket

sandstones except that they tend to have higher

clay contents. They occur stacked vertically one

over the other, in formations hundreds of feet

thick. The size, orientation, and geometry of the

Ienticular units are variable. For example, some,

such as units formed by the filling of stream channels, are long and narrow and may have a preferred orientation. Other deposits formed at the

bends of stream meanders tend to be shorter and

wider and more randomly oriented.

The discontinuous nature of Ienticular formations and the variable geometry of the lenses

makes them a more difficult resource to quantify, in terms of both gas-in-place and potential

for recovery, For these reasons, despite their extensive occurrence, they have only recently been

targeted as a potential resource.

3) How Will Technology Perform?

The third critical variable for economic recovery of tight gas is the viability of massivescale well

stimulation and other extraction technologies in

the geological settings containing tight gas. Here

the issues encompass a large number of specific

technology issues ranging from the ability to identify, using well logs, the attractive zones for gas

recovery, to developing fluid systems that can

help contain a large vertical fracture within a

given rock interval. While work is progressing in

these areas, much new research and development is required before efficient technologies will

exist for tight gas extraction. The key technologies

are discussed later in this chapter.

GAS-IN-PLACE ESTIMATES6

A number of estimates have been made of the

resource base and production potential of tight

gas formations, beginning in 1972 with the Federal Power Commission’s (FPC) National Gas Survey report. In 1978, the Federal Energy Regulatory Commission’s (FERC) report updated and

expanded on the FPC estimate of the tight gas

resource. In 1978 and 1979, Lewin & Associates

(Lewin), under contract to the Department of

Energy, made a detailed appraisal of 13 tight gasbearing basins. In 1980, the National Petroleum

Council (N PC) published its extensive study on

the total U.S. resource in tight formations, combining resource estimates for 12 basins that had

undergone an extensive appraisal, and 101 additional basins whose estimates were based on ex61 n this section, a ncf the section on recoverable resources later

in the chapter, OTA has chosen to emphasize the 1980 National

Petroleum Council Study on Tight Gas In its discussions of previous resource estimates. This emphasis is based on the excellent

reputation of the NPC report, which is widely cited in discussions

of the tight gas resource and future production potential, the report’s extensive documentation of assumptions and methodology,

and the fine level of detai I i n the basin and subbasi n analyses.

trapolation from the appraised basins. Finally, in

1984, the Gas Research Institute conducted a

series of sensitivity analyses of the tight gas resource base, based on the NPC methodology.

Early estimates of the tight gas-in-place by the

FPC and FERC only determined the resource for

specific basins. Subsequent estimates expanded

the number of basins under consideration and

undertook more detailed appraisals within the individual basins as more data became available.

The basins included in the various studies are

shown in figure 28. A chronologic representation

of the changing resource estimates for the appraised basins is given in table 35. Note that increasing the area under consideration has not

necessarily increased the estimated size of the resource.

Methodologies

The FPC and FERC studies defined the amount

of gas within a unit reservoir volume by estimat-
Ch. 8—Tight Gas ● 143

Figure 28.—Primary Tight Gas Basins

Basins included in resource assessments

FPC 3, 5, 6 \J

FERC 1, 2, 3, 5, 6, 8

Lewin 1-8, 10, 12, B, D, H

NPC 1-12 excluding Cotton Valley “sour”

1. Western Region

1. Northern Great Plains

2. Williston

3. Greater Green River

4. Wind River

5. Uinta

6. Piceance

7. Denver

A. Snake River

B. Big Horn

C. Wasatach

D. Douglas Creek

E. Western Shallow Cretaceus Trend

NOTE Coastal regions include offshore areas

SOURCE National Petroleum Council

Il. Greater Southwest Region Ill. Eastern Region

8. San Juan L. Appalachian

9. Val Verde-Ozona Trend M. Black Warrior

10. Val Verde-Sonora Trend

11. Edwards Lime Trend

12. East Texas/North Louisiana Basin—

Cotton Valley Trend

F, Raton

G. Anadarko

H. Ouachita

1. Arkoma

J. Fort Worth

K. Western Gulf Coast

ing average gas-filled porosity7 and average reservoir temperature and pressure conditions for

each of the formations or sections of formations

that they evaluated. Using these figures together

with the net “pay” (i. e., gas-bearing) thickness

and the total productive area of the formation,

each study team calculated the total gas-i n-place

in the reservoir.

—.

~otal porosity times the fraction of void space filled with gas.

The FPC, in its 1972 study, set minimum criteria defining its interpretation of gas that could

conceivably be considered as recoverable. It restricted its evaluation to reservoirs with a minimum net pay thickness of 100 ft, less than 65 percent water saturation, 5 to 15 percent porosity,

and permeabilities of 0.05 to 0.001 md. It included only formations at depths between 5,000

and 15,000 ft and defined a minimum reservoir

size of 12 square miles. It also only considered
144 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

reservoirs in remote areas, and, among these,

only reservoirs not interbedded with high-permeability aquifers.8 Its study concluded that the three

Rocky Mountain Basins alone contained some

600 TCF of tight gas (table 35).

The FERC study used the same methodology

as the FPC to calculate the gas-in-place but

revised some of the criteria and expanded the

area evaluated to include the San Juan Basin and

the Northern Great Plains. They included formations with thinner pays (to 20 ft thick) and depths

as shallow as 1,500 ft, and allowed lower gasfilled porosities. Despite the expanded area and

modified formation parameters, the size of the

tight gas resource only increased from 600 to 793

TCF (table 35).

Both the FPC and the FERC recognized that

tight gas resources probably existed in other

gas-bearing basins. Since little data existed in

these areas, however, they felt the size of the additional resource could not be properly evaluated.

The Lewin and NPC studies used considerably

more elaborate methodologies to calculate the

gas-in-place. Their methods were designed to

8These last two criteria were included because nuclear explosives

were being considered as a stimulation mechanism. The FPC excluded large portions of known tight gas resources which occurred

in more populated areas. The FERC study removed these exclusions because by 1978 it seemed evident that nuclear explosives

would not be used.

take into account the variability of physical proper-ties, such as permeability, porosity, and net pay

(total thickness of gas-bearing zones), within a format ion.

The Lewin study used available well data to

divide each formation into “subareas” based on

homogeneous physical characteristics. The potentially productive portion of each subarea was

determined by multiplying by the wildcat success

rate (fraction of wildcat wells that are commercial successes) for that region, The volume of gasin-place calculated for each subarea was further

adjusted to reflect a log-normal distribution of

“pay quality.” 9

The Wattenburg Field in the

Denver Basin, a relatively well-developed tight

sands gasfield, was used as a model to determine

a characteristic distribution of pay qualities.

The NPC methodology for calculating the gasin-place in its appraised basins was similar to the

Lewin approach. Instead of using the same pay

quality distribution across all fields, however, the

NPC determined a distribution of pay quality and

other reservoir properties for each individual

basin or subbasin based on existing well data. In

this way it could calculate the gas-in-place for up

to six permeability levels. The NPC study also

evaluated a slightly larger area (13,000 more

qln the ~ewin report, pay quality is a funCtiOn of porosity,

permeability, and thickness of the gas-bearing zone.

Table 35.-Tight Gas-in-Place Estimates (in TCF)

FPC 1973 FERC 1978 Lewin1978 NPC 1980

Appraised basins (gas-in-place) (gas-in-place) (gas-in-place) (gas-in-place)

Northern Great Plains/

Williston . . . . . . . . . . . . . . . . . — 130 74 148

Greater Green River . . . . . . . . . 240 240 91 136

Uinta . . . . . . . . . . . . . . . . . . . . . . 210 210 50 20

Piceance. . . . . . . . . . . . . . . . . . . 150 150 36 49

Wind River . . . . . . . . . . . . . . . . . — — 3 34

Big Horn. . . . . . . . . . . . . . . . . . . — — 24

Douglas Creek. . . . . . . . . . . . . . —

—

— 3

Denver . . . . . . . . . . . . . . . . . . . . —

—

— 19 13

San Juan . . . . . . . . . . . . . . . . . . — 63 15 3

Ozona . . . . . . . . . . . . . . . . . . . . . — .— — 1

Sonora . . . . . . . . . . . . . . . . . . . . — .— 24 4

Edwards Lime . . . . . . . . . . . . . . — .— — 14

Cotton Valley “sweet” . . . . . . . — .— 67 22

Cotton Valley “sour” . . . . . . . . — .— 14

Ouachita. . . . . . . . . . . . . . . . . . . —

—

. - 5 —

Total . . . . . . . . . . . . . . . . . . . . 600 793 423 444
Ch. 8—Tight Gas ● 1 4 5

square miles) of potentially productive land than

Lewin, although the two sets of appraised basins

were similar (Lewin appraised 10 of the 12 NPC

basins). In addition, the Lewin study did not

evaluate gas-in-place for permeabilities less than

0.001 md, whereas the NPC study included a

number of areas with permeabilities as low as

0.0001 md and some areas with permeabilities

as low as 0.00001 md. Despite these differences,

however, the Lewin and NPC reports do not differ substantially in their total estimates of gas-inplace in the appraised basins (423 v. 444 TCF,

respectively). On the other hand, the estimates

for individual basins do differ considerably.

In addition to the 12 basin appraisals, the NPC

study made the first attempt to estimate the total

tight gas resource occurring in all gas-producing

basins in the Lower 48 States. To do this it extrapolated the results of its detailed basin appraisals to 101 remaining potential gas-bearing

basins. Extrapolated basins were classified according to their similarity to appraised basins; certain

formations in the appraised basins were chosen

as analogs to formations in the extrapolated

basins. The NPC estimated an additional 480 TCF

in place in the extrapolated basins as shown in

table 36. Its total gas-in-place resource estimate

for the U.S. Lower 48 States is 924 TCF.

Estimate Comparison and

Discussion of Uncertainties

Appraised Areas

The sequence of gas-in-place estimates for tight

gas represents a continuing refinement of the estimation process. Each estimate builds on the

former–adding new data and evaluating new

areas. In general, the more detailed analyses have

tended to produce lower gas-in-place estimates

for a particular area. For example, the early FPC

and FERC estimates of gas-in-place for the Uinta

Table 36.—National Petroleum Council’s

Gas-in-Place Estimates

Appraised Extrapolated Total

(12 basins) (101 basins) (113 basins)

Potential productive

area (square miles) 53,000 68,500 121,500

Gas-in-place (TCF). 444 480 924

SOURCE NPC Reporl vol V part I table 1

Basin are 150 TCF. The later Lewin and NPC estimates for the Uinta are only 50 and 20 TCF, respectively. These reductions can be in part accounted for by an increasing realization of high

water saturation in the tight gas reservoirs and

its negative effect on both gas content and gas

permeability. 10 As discussed above, high water

saturations tend to reduce the total volume of gas

in the reservoir rock as well as restrict the gas

flow. The NPC study also reduced the assumed

thickness of total pay intervals in the Uinta from

a 500- to 1,000-ft range to less than 500 ft, reducing the overall volume of the gas-producing

zone and thus the total gas-in-place.

The NPC estimate represents the most comprehensive estimate of the gas-in-place resource base

that exists to date. Because of its level of detail

and its attempt to include gas in all gas-bearing

basins, it probably represents the best available

quantitative assessment of the size of the gas-inplace resource for tight gas. It shares, however,

a drawback common to all the estimates: in

OTA’s opinion, none of the estimates adequately

quantifies the extent of the uncertainty associated

with the gas-in-place calculation.11 This may result in the impression that the gas-in-place has

been very narrowly defined, whereas the actual

range of uncertainty may be quite large.

In most cases the estimators were fully aware

of factors contributing to uncertainty. To the extent that their estimates are used by producers

and others familiar with the industry, the level

of uncertainty may be understood. When the estimates are to be used by those without such a

common background, the inherent uncertainties

need to be explained in some detail. The following discussion describes the important factors

IoStrictly speaking, permeability does not affect the magn Itude

of gas-in-place, whereas gas content most certainly does. l-iowe~er,

most estimates of gas-in-place do not attempt to Include every molecule of gas, and may exclude gas from formations that have no

recoverable gas. Because permeability does atfect recot era blltty,

an altered estimate of permeability may cause a change In est)mated

gas-in-place. Nevertheless, gas content is the more closely related

of the two variables to gas-in-place.

I IThis statement IS not meant to imply that the NPC report dld

not discuss uncertainty. To the contrary, the technical reports presented substantive d iscusslons of the u ncertai ntles I n key parameters, and used probability distributions rather than point estimates

I n several key calcu Iatlons. However, these d Iscusslons and calculations were not translated Into error bands around the report’s projections of resources and future production.
146 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

contributing to uncertainty and their implications

for gas-in-place estimates.

Differences and uncertainties in volumetric estimates of the tight gas resource are often a function of the level of understanding of the geologic

history of the basins and the physical characteristics of the formations. Critical parameters include the porosity and water saturation, the areal

extent and thickness of the gas-producing portion of a formation, and the actual presence of

gas and its geologic origins.

As discussed earlier, porosity and water saturation constrain the amount of gas present in a

discrete volume of rock. However, these parameters are extremely difficult to measure accurately

and may vary over a wide range within a small

area, Available data consist of extrapolations from

existing wells and are often insufficient for a valid

statistical analysis of a potential producing formation. Furthermore, conventional techniques

for measuring and interpreting reservoir parameters, where they have been used in the tight gas

intervals, are often not applicable to these types

of formations. For example, conventional interpretation of well log data frequently results in

higher measured porosities than those actually

observed by laboratory analysis of core samples.

Errors in porosity measurements can lead to even

larger errors in computed levels of water saturation, compounding errors in the estimates of gasin-place. In the last few years, interpretative techniques have been modified to apply specifically

to low-permeability intervals, but these techniques are not yet routinely used.

The extent to which measurement problems of

this sort have affected tight gas resource estimates

is difficult to determine, although these problems

are likely to have been acute for the earlier studies. I n the NPC analysis, well performance calculations for future wells were compared with

actual well performance in producing wells to

check the procedures for estimating porosity and

permeability .12 However, despite recent advances

in logging systems and interpretation techniques,

there still were severe measurement problems at

the time the NPC estimates were developed. In

llovld Baker, Mobil Research & Development cOrP., Pf?rsOnal

communication, 1984.

fact, the discussion of measurement problems

that appears in the NPC report itself, reproduced

in box H, implies that the NPC analysts could not

have been overly confident about the precision

of their resource calculations.

The areal extent of some tight formations, particularly blanket formations, may be fairly well

documented in developed basins from data collected from exploration and development wells

drilled for conventional gas resources. Pay thickness may be fairly easy to determine for some

blanket formations in which sandstone beds are

clearly defined. I n other blanket formations, thin

gas-bearing sand stringers occur finely interbedded with shales, making determination of the

net productive thickness extremely difficult.

The lateral continuity, thus areal extent, of the

gas-bearing portions of Ienticular formations may

be more difficult to determine than for blanket

formations since the geometry of the individual

lenses cannot be readily understood just by drilling and logging multiple wells within a formation.

For example, sand-rich intervals occurring at approximately the same stratigraphic level in two

or more wells may or may not represent the same

lens (see fig. 29). Extrapolation from mapped surface features of these formations is the best way,

at present, to determine dimensions, distribution,

and orientations of the sand lenses. However, visible surface manifestations of Ienticular formations

are not always conveniently present. Another way

to approximate the volume of Ienticular tight gas

formations is to determine an average sand-toshale ratio based on well log data for a portion

of the formation and extrapolate this over the area

covered by the formation. The accuracy of this

method depends on the number of wells drilled

through the formation.

The presence of appropriate source materials

and temperatures and/or biologic agents for hydrocarbon generation is a function of the geologic

history of a basin. Many tight gas resource estimates consider a large portion of the tight gas interval in the Rocky Mountain Basins to be gasbearing. There is, however, a dissenting opinion:

that temperature, pressure, and source rock composition throughout many Ienticular basins, such

as the Piceance, were not appropriate for the gen-
Ch. 8—Tight Gas ● 147

Box H.—What the NPC Report Had to Say About Measuring

Key Tight Gas Resource Parameters

“Experience to date indicates a broad variation of the critical parameters even within the same formation. Permeability routinely varies by orders of magnitude; gas-filled porosities can vary by factors

of 2 to 5; net pay can vary by factors of 2 to 50. Few data are available on the distribution of lens size

and geometry, but extremely wide variations can be expected. Experience indicates that expensive,

time-consuming measurements and analyses made for one well may not be sufficiently applicable to

another well in the same basin to design a fracture treatment . . . The significance of this is that it substantially reduces the ability to extrapolate from one well to another. Thus, extrapolation over a wide

area is difficult.

“In very low-permeability gas reservoirs, existing methods and tools for measuring critical parameters have been found to be inadequate for accurately characterizing the producing formations. Extremely

low permeability renders data from drill stem tests nearly useless. Well logging has failed to adequately

distinguish gas-productive from water-productive zones. Net pay thickness and gas-filled porosity are

measured with very low reliability. Current coring techniques tend to alter the rock properties prior

to laboratory testing. Conventional laboratory tests of permeability have been shown to produce results

that vastly overstate actual permeability under reservoir conditions of water saturation and pressure.

The distortion is greater at lower permeabilities, where recovery is more sensitive to permeability. Laboratory measurements and tests of rock strength and hardness are only now being developed and standardized. No downhole permeability measurement technique has proved reliable in tight formations.

Pressure testing of wells in tight formations requires vastly longer time periods than for conventional

formations (e.g., weeks v. hours) for comparable precision. Measurements of lens geometry have been

limited to studies of outcrops of the formations. The nature and distribution of the subsurface gas-bearing

lenses have not been characterized. Reservoir modeling also needs improvement. Competent

two-dimensional flow models are available, but three-dimensional models have only begun to be developed and are exceedingly costly to operate.

“Net pay is one of the most important parameters required for reservoir performance evaluation . . . Current methods for determining net pay have a very high probability for error.

“Accurate knowledge of permeability is essential for , . . predicting potential well performance . . . Current methods for obtaining permeability . . . exhibit questionable reliability.”

SOURCE: National Petroleum Council, Unconventional Gas Sources: Tight Gas Reservoirs, Part 1, December 1980,

eration of large quantities of gas.13 This opinion

holds that only a small proportion of the thousands of feet of vertical section of tight sandstones

is actually gas-bearing. If confirmed, this would

substantially reduce the estimated gas-in-place,

and make basins like the Piceance much less attractive for potential production. Similarly, the

NPC estimate of the gas-in-place in the Denver

Basin included a caveat that as much as 30 percent of the estimated gas-in-place in that basin

may not actually exist. Temperature and pressure

conditions in the northern part of the basin may

never have been high enough to generate gas.

1‘j.W. ~ratton, ‘‘Fracturing Technologies for Gas Recovery From

Tight Sands, t’ contractor report to OTA, September 1983,

The volumetric estimate of gas-in-place in the

Denver Basin is based on gas contents extrapolated from the known gas-bearing portions of the

formations occurring in the southern part of the

basin.

The most controversial of the appraised areas

is the Northern Great Plains, estimated by the

NPC to have nearly 150 TCF of gas-in-place in

shallow formations. Two-thirds of this gas is estimated to be technically recoverable. The controversy centers around the origin of the gas,

whether it is early thermogenic or biogenic,14 and

.— 14That Is, ~ormed by physical processes associated with high temperatures (thermogenlc) or else by biological processes, usually

anaerobic d}gestlon (blogenlc).
148 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Figure 29.—Problems With Reservoir Mapping in

Lenticular Formations -- 

-

1 2 3

Physical

reality

I Lenticular

sand/shale

sequence

Blanket

sandstone

some argue that there is likely to have been significant gas loss since the time of formation,

unless sealing mechanisms have been unusually

effective.

Given the large discrepancies in estimates of

gas-in-place, and the important implications for

the natural gas resource base, the questions associated with the origin of the Northern Great Plains

gas and its preservation need to be resolved.

As might be expected, dissent from the NPC

estimates is not restricted to those who are more

pessimistic or are simply skeptical of the accuracy

of the estimates. For example, several panelists

at OTA’s Workshop on Unconventional Gas

Sources felt that the NPC’s resource estimates

reflected an overly conservative approach which

tended to discount or dismiss resource potential

unless there existed definitive evidence of its existence. It was claimed that, in some basins where

extensive drilling records were available, NPC

geologists assigned either zero or a heavily discounted value of gas-in-place to sections where

there had been no “gas shows, ” even when the

“no shows” resulted simply from a lack of drilling. A case in point is the Denver Basin, mentioned previously; in this basin, the NPC assumed

that only 1,600 of a total of 45,000 sections, or

3.6 percent, are gas-bearing. In the words of one

of these critics, this approach “places an unjustified premium on the exploration technology and

wisdom of our predecessors in the petroleum

business.” 18

In the opinion of these same critics, the conservatism displayed in the NPC study’s estimates

of productive area is duplicated in its estimates

of the thickness of the gas-bearing rock in the productive formations. For example, in the NPC analysis of the Piceance Basin, one of the Ienticular

basins where high gas-in-place estimates have

been questioned, the four gas-bearing formations

have a total thickness averaging about 6,400 ft

but are assigned estimated “net pay ranges, ” or

gas-filled thicknesses, of:

Formation Net pay range (ft)

1. Ft. Union. . . . . . . . . ... . . . . 12-80

2. Corcoran Cozette . . . . 16-70

3. Mesaverde. . . . . . . . . . . . . . . . 20-200

4. Lower Cretaceous-Jurassic . 7-35

. —

18Ovid Baker, Mobil Research & Development Corp., letter of

Aug 3, 1984, to OTA.
Ch. 8—Tight Gas 149

The ranges are not additive, but at no point does

the NPC assume that the gas-filled portion of the

formations occupy more than 6 percent of the

total thickness of sediment.

It is unlikely at this time that the existing arguments about the relative “optimism” or “conservatism” of the NPC’s estimate of gas-in-place can

be resolved. In OTA’s opinion, the NPC estimate

of gas-in-place for the appraised basins, excluding

the Northern Great Plains, probably should still

serve as a reasonable “most likely” estimate, even

though a considerable error band—at least +/- 100

TCF—must be assigned to the estimate. As for the

Northern Great Plains, there appears to be a substantial possibility that the NPC estimate is too

high, but the evidence is by no means conclusive.

Extrapolated Areas

In the NPC analysis, the uncertainties that apply

to the appraised basins are magnified in the extrapolated basins. Not only is there a lack of exploration and production data for these basins,

but also the gas-in-place estimates were not generated by geologists experienced in those basins,

as was the case for the appraised basins. Extrapolations were made by assigning gas-in-place

values to the estimated productive area in each

extrapolated basin using formations in appraised

basins as analogs. In some cases this approach

has a high potential for error, since different parts

of the country have undergone significantly different geological histories which may have affected the amount of gas formed and preserved,

but which could not be properly accounted for

in the estimation process.

For example, the Eastern region (primarily the

Appalachian and Black Warrior basins) was estimated to contain 49 TCF i n shallow formations

based on analogies with formations in the Northern Great Plains. However, the Northern Great

plains estimates assume a biogenic origin for the

gas, leading to the large volumes of gas-in-place.

Even if biogenic gas formed in the Appalachian

and Black Warrior basins, given their age (300

million to 400 million years relative to 75 million

to 100 million years) and complex geologic history, it is unlikely that much biogenic gas would

have been preserved to the present day. Therefore, the gas content per unit rock appears unlikely to be the same in the two regions.

There was widespread agreement among the

NPC study participants interviewed by OTA that

the gas-in-place estimates for the extrapolated

basins were highly uncertain.

TECHNOLOGY

The characteristics of the tight gas resource

base present gas producers with a variety of important problems in locating and exploiting this

gas. Many of these problems result from the very

low permeability of the tight gas reservoirs and

the consequent need to use fracturing to achieve

commercial levels of gas production. For example, full exploitation of the Ienticular reservoirs

requires the ability to contact lenses remote from

the wellbore, yet our current ability to predict or

control fracture length and direction is poor. In

addition, the presence of water-sensitive clays

raises the potential for formation damage from

the fracturing fluids. Difficulties in accurately

measuring reservoir characteristics greatly complicate fracture placement and add to the economic risk of stimulation. Also, the depth and

structure of some of the tight formations lead to

extremely demanding requirements for fracture

fluids and proppants. In this section, these problems and the technologies available to overcome

them are briefly discussed. A longer discussion

of fracturing technologies is presented in ap

dix B.

Hydraulic Fractures

Gas flows from a reservoir towards a well

penbore

because of a pressure difference between the

reservoir and the well bore. The rate of flow is dependent on the difference in pressure and the

permeability of the formation. Fracturing is designed to increase flow rates by cracking the

reservoir rock, exposing more of the reservoir sur-
150 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

face to the lower wellbore pressure. Hydraulic

fracturing is accomplished by pumping large volumes of fluid down the wellbore, increasing the

pressure on the rock formation until it breaks

down and fractures. Because the fractures would

tend to close when the fluid is removed—especially in deep reservoirs where the pressure of

the rock is great—sand or other materials are

added to the fluid. Left behind when the fluid is

removed, these “proppants” are wedged into the

fractures and prevent them from closing,

Hydraulic fractures tend to be unidirectional,

generally extending out in opposite directions

from the wellbore. By convention, their length

is measured along one wing (see fig. 30). Their

direction and orientation (vertical, horizontal, or

inclined) are controlled by the regional stress

regime and the depth of the target formation. Induced fractures at depths greater than 2,000 ft

are oriented in the vertical plane. At shallower

depths, such as might be found in the biogenic

gas reservoirs of the Northern Great Plains, fracture orientation may be horizontal.

Table 37 illustrates the need for fractures in tight

formations and the substantial benefits that may

be gained from larger fractures. As shown in the

table, a well in a highly permeable (10 md) reservoir can drain all the gas in two sections, or 1,280

acres, of a field over a 15-year production life.

An unfractured19 well in a tight (0.001 md) blanket sand can drain only about 20 acres of the field

during a 30-year production life, and during that

I gActually, the process of ‘‘completing” the Wel I involves an eXplosive perforation of the well lining that creates a small tracture,

here assumed to be 100 ft in length.

time would average less than 40 MCF/D of gas

production, a very low rate. A massive hydraulic fracture creating a 1,000-ft fracture would increase the average production rate by nearly fivefold and allow complete drainage of the field with

six wells per section rather than nearly 30 with

unfractured wells. An advanced technology producing a 4,000-ft fracture would increase the

average production rate by a factor of 15 and

allow the tight field to be drained with a 320-acre

(two wells per section) spacing, a fairly common

spacing in conventional gasfields.

Successful fracturing in tight formations is complex and faces substantial obstacles. A few critical points should be understood. First, the great

majority of tight gas recovery heretofore has been

restricted to areas “characterized by thick, fairly

uniform, blanket-type formations , . . (where) . . .

only a limited knowledge of the formation characteristics is necessary to stimulate economic production rates.”20 The majority of the resource,

however, is more complex, and greater understanding of the geology and production mechanics is critical .21 Second, although fracturing dates

from the 1800s, and hydraulic fracturing dates

from 1947 and has the benefit of the experience

gained by thousands of separate fracturing treatments, the type of massive hydrauIic fracture

needed to begin to fully exploit the tight resource

has only been developed in the last 10 years or

so. The process is not fully understood and extrapolation to new geologic situations is difficult.

————

Zocas Research Institute, Status Report.” GRI’s Unconventional

Natural Gas Subprogram, December 1983,

Z’ Ibid.

Table 37.—Conventional and Tight Gas Wells Compared

Wells per Reservoir area

Fracture Ultimate Production section to Exposed by

Perm. length production life produce fracture

Type well (red.) (ft) (MMCF) (years) (all gas) (sq. ft)

Conventional . . . . . . . . . . . . . . . 10 100 31,700 15 0.5 34,000

Tight—unfractured . . . . . . . . . . 0.001 100 390 30 29 34,000

Tight—present technology ., . 0.001 1,000 1,838 30 6 340,000

Tight—advanced technology . 0.001 4,000 6,015 30 2 1,360,000

NOTES Net pay = 85 ft.

Initial pressure = 5,500 psi

Maximum recovery, gas/section =16 BCF for conventional,

11 BCF for tight gas wells.

SOURCE: R. W. Veatch, Jr and O Baker, “How Technology and Price Affect U S Tight Gas Potential, ” Petroleum Engineer International, January 1983.
Ch. 8—Tight Gas ● 757

Figure 30.—Conceptual Fractures

Blanket and

Created by Massive Hydraulic Fracturing in

Lenticular Formations

r

Blanket formations ~

Well

bore

Casing

v

1

\ \ ”

Sand-filled

region of

fracture

Fractur

SOURCE: National Petroleum Council, Unconventional Gas Sources Tight Gas Reservoirs, Part /, December 1980
152 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Third, aside from the difficulty of forecasting what

a fracture will do, it is hard to tell in any detail

what a fracture has done even after it has been

completed and the well is producing (or has

proved to be unproductive). In addition, as with

any new and rapidly developing technology,

state-of-the-art techniques are not necessarily

standard practice in commercial ventures. For

these reasons, our extensive experience in fracturing has not been as much benefit in projecting future performance as might have been expected.

Despite these difficulties, however, well service companies and producers have been responding vigorously to the various problems

encountered in tight formations and have developed a number of variations to the standard fracture treatments. Of particular importance are the

development of new fracture fluids and proppants which can increase fracturing efficiency and

fracture conductivity. In addition, improved techniques for fracture containment (i. e., keeping the

fracture within the gas-bearing layer), fracture

prediction, and onsite monitoring will result in

more accurate production estimates, greatly reducing the risk of developing these high-cost resources.

Proppants.–Development of new proppants is

an important area of innovation by the service

companies in response to a need for material that

will not crush at high pressures and is light

enough for the fluid to transport to the end of

the fracture. Recent developments include ceramic beads and resin-coated sands that have

lower densities than bauxite–the material currently used in high pressure situations—and thus

can be more efficiently transported by the fluid.

They appear to have sufficient strength for most

fracture applications.

Fracturing Fluids.–The need for a fracture fluid

that simultaneously can avoid formation damage

(clay swelling, etc.) and maintain a high capacity

to carry proppants in suspension into the fracture has led to the development of very sophisticated fluids. A particularly significant development is “cross-l inking,’ which temporarily

increases the viscosity of the fluid—and thus its

fracturing and proppant-carrying capability–by

linking together polymer chains. After emplacement of the proppant, this viscous fluid alters to

a low-viscosity fluid so that it can flow back to

the wellbore, minimizing formation damage.

Fracture Containment.–A common problem in

thin blanket sands is the difficulty of keeping the

fracture within the blanket, or pay zone, so that

it does not waste its energy fracturing nonproductive rock or actually cause reserves to be

lost by fracturing into a water zone or fracturing

the reservoir “cap.” In general, readily available

techniques have not been successful at containing fractures within the pay zone. New techniques have been proposed (including careful

placement of the fracture initiation point, very

careful control of the fracturing fluid viscosity and

pressure, and use of floating proppants to seal

off upper non producing portions of the fracture)

and are being tested, as discussed in app. B.

Fracture Prediction. -Understanding the mechanisms of fracturing and thus being able to predict fracture behavior is critical to reducing the

economic risk of tight sands development to manageable levels. The state of the art of fracture

prediction, however, comes from sophisticated

mathematical models and laboratory experiments

with very little field verification.

Current practice in the field is to use relatively

simple analytical models against which to compare fracture behavior, proppant placement, tracture length, and well performance. These simple

models will often be inadequate in complex tight

gas situations, but the more sophisticated models

currently available are expensive, time-consuming, and dependent on input data that often are

not readily obtained. And, although laboratory

experiments allow interesting possibilities for

tightly controlled conditions and parametric analysis, it is difficult to be confident that field-scale

fractures will behave in the same manner as the

small-scale laboratory fractures.

Field-scale testing, using experimental wells or

excavating a created fracture, can overcome

some of these problems but is extremely expensive. Only a few field-scale tests have been completed and ongoing projects have been curtailed

due to Federal funding cuts. Nevertheless, they
Ch. 8—Tight Gas 153

are providing valuable information on actual fracture configuration.

The difficulties of fracture prediction are particularly acute in the early stages of field development, when theoretical models and analogy

with other fields provide the only forecasting

guides, Continued development of the field provides data for performance matching of prospective sites with producing wells, and the percentage

of successfuI well stimuIations should increase

with experience, As discussed below, however,

this learning process may be disrupted by problems associated with monitoring fracturing success and interpreting well performance.

Monitoring Fracture Behavior.–The ability to

monitor fracture behavior is critical to tight sands

development for two reasons. First, it is the means

by which the existing experience in fracturing can

be translated into an ability to predict fracture

behavior for new wells. The inability to measure

what has actually occurred underground in past

fracture treatment is responsible for our poor

predictive capability. Second, it is critical to field

development, because knowing fracture location

is necessary in planning additional wells so as to

minimize interference between wells. Most of the

technologies under development to monitor fractures in the field are adaptations of existing geophysical and well logging techniques, They are

discussed in greater detail in appendix B. Some

success has been realized in determining fracture

height adjacent to the borehole, and in some

cases, total fracture length and propagation direction. Problems still exist in determining propped

length of the fracture and vertical growth22 at a

distance from the wellbore.

Most of these technologies are still experimental and costly, and are difficult to use. However, fracture diagnostics has received major attention from service companies in the past few

years, and innovation has been rapid. improvement and widespread commercial use of these

monitoring techniques would have a major effect in lowering the economic risk of tight sands

development.

~~vertical ~rO1~th is a n I m portant parameter because of the

cie~lrabl I Ity of keeping the fracture with In the pay lnter~ al. See Fractur~ Ccmt<?/nmcmt abotfe.

Current Fracturing Success.—In tight gas formations, improved fracturing technologies, developed in blanket sands, have for the most part

realized considerable success. Increased fracture

lengths in blanket formations often appear to be

attainable simply by increasing the volume of

fluid and proppant pumped. Fractures over 2,000

ft long have been reported.23 Where design

lengths have not been achieved, failure can generally be attributed to fracturing out of the pay

interval, inadequate proppant transport, or extensive formation damage.

An additional but less obvious major problem

may still exist i n blanket formations. Because

massive hydraulic fracturing in low-permeability

formations is still a relatively new technology,

there are no data on whether the permeability

of the fractures can be maintained through time.

There is concern that the fractures may close or

become plugged before the 30-year production

histories are complete. Counteractive measures,

such as periodic cleanup treatments or multiple

small fracture treatments over the life of the wells,

have not been evaluated in terms of their costs,

risks, and effect on well performance.

The overall success rate of massive hydraulic

fracturing in tight formations is likely to improve

to the extent that new technologies are developed to counteract problems such as formation

damage and inadequate proppant transport. A

certain number of reservoirs, however, may

never be amenable to production using massive

hydraulic fracturing. For example, adequate fracture containment in some reservoirs may never

be possible due to the intrinsic characteristics of

the rock. If reservoir boundary layers are substantially weaker than the reservoir rock, the fracture

will grow vertically at the expense of horizontal

growth. In effect, much of the fluid and proppant

is being used to create a fracture i n a nonproductive interval. Recovery from such reservoirs cannot be based on the creation of 1,000-ft fractures.

More work needs to be done in identifying such

formations and determining the optimal fracture

treatment to maximize recovery at minimum

cost .

Z3B. A, )vlatthewsr W. K. MI I Ier, and B. W. Schlottman, ‘‘Record

Massive Hydraulic Fracturing Treatment Pumped In East Texas Cotton Valley Sand5, ” [III <~nd G,IS }ourn,~l, Oct. 4, 1982, pp. 94-98.

38-742 0 -85 - 1 1
154 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Lenticular reservoirs represent a situation

where new technologies have not been effective.

The NPC-estimated base technology (1,000-ft

fractures) is not yet the acknowledged state of the

art, nor is there substantive evidence that fractures will penetrate lenses not actually intersected

by the well bore. Where large-scale fracture treatments have been attempted in Ienticular formations, results have been disappointing. Commercial flow rates were not attained. Insufficient data

were collected both before and after treatment

to evaluate why fracture treatments failed, 24

Currently, most producers have returned to less

expensive shorter fractures. In some cases they

are drilling wells in areas with thick vertical sequences of Ienticular sands and stimulating multiple pay intervals by fracturing each interval with

fractures on the order of 100 to 500 ft long,

Although per well stimulation costs are lower

in this case, cumulative production per well may

be less, since a smaller gas-bearing area is in contact with the well bore. This technique may limit

the potential recovery from Ienticular formations,

particularly in the short term. However, there are

some data indicating that, over the long term, gas

flow from wells in Ienticular reservoirs, with relatively short fractures, may not exhibit the expected production decline rates of a limited reservoir. 25 Because the nature of natural fracture

systems and gas flow behavior in Ienticular formations is not well understood, it may be premature to draw conclusions about the long-term

gas recovery of alternative fracturing strategies in

these formations.

Reservoir Characterization Technologies

Techniques and instrumentation to quantify

more accurately the physical properties of the

ZqAn alternative explanation of the production failure (instead of

failure of the fractures to reach design lengths) is that the fractures

may have achieved design lengths but that other problems, such

as water infiltration, and production problems caused by backflow

of the sand proppant, were primarily responsible for the disappointing gas flows. The originator of this explanation concurs, however,

that the “wells have not been tested and studied sufficiently to

decide if the fractures are successful or not.” Ovid Baker, Mobil

Research & Development Corp., personal communication, 1984.

25D. H. Stright, jr.,and J. 1. Gordon, “Decline Curve Analysis

in Fractured Low Permeability Gas Wells in the Piceance Basin, ”

SPE/LWESymposium on Low Permeability Gas Reservoirs, SPE/DOE

11640, 1983, pp. 351-356.

reservoirs and to help determine their relationship to one another are crucial to designing more

efficient stimulations and making accurate estimates of reserves and recovery rates for economic analysis, Accurate reservoir characterization reduces both the costs and risks of field

development.

Conventional methods for determining reservoir parameters include: geologic mapping of

exposed areas of the reservoir formation, laboratory analysis of core samples and detailed subsurface correlation of reservoirs, well logging, and

well tests. Considerable data have been collected

using each of these techniques. Problems with

the techniques themselves have been identified.

Only limited progress has been made to date in

modifying existing techniques and developing

new techniques to overcome their problems.

Laboratory analysis of core samples recovered

from a well provides the best estimate of reservoir properties at that particular site. The data can

be correlated with information from other wells

to derive a broader regional picture of the subsurface conditions. Date from laboratory analyses can also aid in the interpretation of well logs.

Most samples for laboratory analysis are recovered using conventional coring techniques, The

depth of recovery is known, and temperature and

pressure information often is available. The recovered samples are subjected to a range of laboratory tests to determine porosity, pore volume,

permeability, water saturation, mechanical rock

properties, and mineralogy.26 Electrical and gammaray logs are also run on the samples for correlation with well logs.

Because small changes in reservoir properties

can substantially alter estimates of the recoverable gas, the laboratory measurements need to

give an accurate picture of actual reservoir conditions. Alteration of the physical properties of

the rock during its collection represents an important problem for tight formations, contributing to inaccuracies in measurements of permeability, water saturation and other parameters.27

26A. R. Sattler, “The Multiwell Experiment Core Program, ”

SPE/DOESymposium on Low Permeability Gas Reservoirs, SPEIDOE

11763, 1983, pp. 437-442.

ZTNational petroleum Council, Unconventional/Gas sources: Executibre Summary, December 1980.
Ch. 8—Tight Gas 1 5 5

Techniques for unaltered core recovery exist

(e.g., the use of pressurized core barrels), but at

present are too expensive and too unreliable for

routine use. The available techniques are most

practical for research purposes or possibly for use

in the early stages of developing a large field, to

assist in planning a development strategy,

Well logs are among the more commonly used

techniques to determine reservoir properties.

They are comparatively inexpensive to use, and

results generally can be obtained quickly. Unfortunately, many of the logging techniques used

in conventional reservoirs have given inaccurate

results in the unconventional formations,28 partly

because some conventional methods of log analysis are not appropriate for low-permeability formations and partly because some analysts are not

properly accounting for the low-permeability

conditions .29

The complex mineralogic content, including

clays and cement, and poorly defined interfaces

between producing and nonproducing zones in

tight formations distort log responses. Resulting

porosity and water saturation measurements may

be too low or too high. Often the precision of

the tools is not sufficient for these reservoirs; e.g.,

a small error in porosity measurement can result

in a large error in inferred fluid saturation. Failure to distinguish gas-productive from waterproductive zones, a common problem,30 drastically complicates the selection of fracture

locations.

A prototype logging tool has recently been developed using nuclear magnetic resonance (NMR)

to determine porosity, fluid saturation, pore size

distribution, and bulk permeability of a formation. Laboratory tests of the tool have been successful; however, the time required to obtain accurate measurements (on the order of several

days) is likely to severely restrict its commercial

application. 31 NMR logs may end up being most

z8G, c. Kukal, et al., “critical Problems Hindering Accurate Log

Interpretation of Tight Gas Sand Reservoirs, ” SPE/DOE Symposium

on Low Permeability Gas Reservoirs, SPE/DOE 11620, 1983.

z9S. A. Ho]d; tch, Texas A&M University, PfYSOnd] COfYIm UniCdtion, 1984.

JoNational petroleum Council, Ur?corrvent;of?a/ ~a5 SOUIC6’5: ~~-

ecutive Summary, December 1980.

31 K. H. Frohne, Morgantown Energy Research Center, PerSOfIal

communication, 1984.

useful on experimental wells where they would

be used to gather baseline data for extrapolation.

In the long term, it may be a less expensive technology for obtaining reservoir data than coring.

Another approach to improved logging is to use

available equipment with specialized interpretive

techniques to account for the log distortions associated with the tight formations. An example of

new interpretive techniques is a system called

“TITEGAS,” which is based on equations which

define the response of conventional logging

tools.32 The system deals primarily with data from

density, neutron, and resistivity logs and makes

a number of claims to accurately measure, among

other parameters, porosity, gas saturation, clay

content, and the presence of natural fractures in

complex, tight formations.

Improved interpretation of conventional logs

clearly is an important element of better reservoir characterization for tight formations. The

need for new interpretive techniques is not clear,

however. OTA found some in the research community who felt that, with available techniques,

it was now possible to accurately measure reservoir characteristics in most tight gas situations;

they blamed current problems on the failure of

most practitioners to assimilate the latest advances. 33 There are many others who conclude

that logging of tight formations is still error-prone

and basically unreliable.

Well tests are also frequently used to empirically determine breakdown pressures (e.g.,

the pressure required to initially fracture a formation) and gas flow rates. From these data, such

reservoir properties as in-situ stress and gas

permeability can be inferred. Creation of smallscale fractures is particularly useful in determining the difference in the stress characteristics of

the rock in the producing and non producing intervals, which in turn allows prediction of fracture containment.

3ZC, c, Kuka], “A Systematic Approach for the Effective Log AJMysis of Tight Gas Sands, ” 1984 SPE/DOE/GRl Unconventional Gas

Recovery Symposium, SPE/DOE/GRl 12851, Pittsburgh, PA, May

13-15, 1984.

JJS. A. Ho[ditch, Texas A&M University, persOnal communication, 1984.
156 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Pressure-transient testing is the most common

technique used to get a rough estimate of gas

permeability prior to stimulation. These tests consist of producing or shutting in the well for a specified period of time and measuring the pressure

drawdown or buildup. In low-permeability reservoirs, however, this technique does not always

produce useful results, especially during the short

time periods feasible for shutting in the well.

Exploration Technologies

No new technologies have been developed

specifically for exploration for unconventional resources, and they are not perceived to be a high

priority need because considerable resources

have been identified by past drilling efforts. Some

existing state-of-the-art technologies used in conventional hydrocarbon exploration are applicable to the unconventional resources. These include aerial and satellite imagery and geophysical

surveying.

In tight sands, mapping of surface features from

aerial and satellite imagery has proved useful in

determining dominant structural trends.34 Such

data may be useful in locating wells so that they

make the best use of existing fracture systems.

In tight sands, there may be some potential for

using seismic data to delineate the character of

beds in a formation.35 36 If clusters of sand-rich

lenses and their orientation could be identified,

these data in conjunction with data on regional

stress patterns would determine the best location

for a well. Three-dimensional, vertical, and cross

34J. A. Clark, “The Prediction of Hydraulic Fracture Azimuth

Through Geological Core and Analytical Stud ies, ” SPE/DOE Symposium on Low Permeability Gas Reservoirs, SPEIDOE 11611 pp.

101-111.

35T. L. DO&cki, “AppllcatiOrl of Areal Seismics to Mapping Sandstone Channels, ” Low Permeability Gas Reservoir Symposium,

SPE/DOE 9847, 1981, pp. 205-209.

36C A, SearIs, M. W. Lee, j. j, Miller, J. W. Al bright, J. Fried, and

J. K. Applegate, “A Coordinated Seismic Study of the Multiwell Experiment Site,” SPE/DOE Symposium on Low Permeability Gas

Reservoirs, SPE/DOE 11613, pp. 115-117

borehole seismic surveys are being tested at the

DOE multi-well site to delineate Ienticular bodies

and fracture zones in the Ienticular formation.37

Initial results have been disappointing; the data

are not of sufficiently fine a scale to map the

spatial relationship of the lenses. Detailed geophysical surveys are not likely to be used commercially in the near future due to high costs and

complex time-consuming data reduction.

New Technologies and the Industry

It appears that both tight gas producers and

well service companies are willing to experiment

with new stimulation techniques. This may have

contributed to the rapid development of sophisticated fracturing fluids and proppants.

In contrast, state-of-the-art diagnostic techniques both for reservoir characterization and for

predicting and monitoring fracture behavior are

not commonly in use among producers. The primary problem appears to be that these techniques are costly and time-consuming. For small

and midsize producers in particular, with limited

acreage, there is little cost benefit to developing

information leading to improved stimulation if

they will only be drilling and fracturing a few

wells. Larger producers are more likely to make

this investment.38

The diagnostic techniques may ultimately be

the most important factor in making tight gas an

economically viable resource. However, because

of the limited interest, the rate of development

of these technologies is likely to be slow, particularly in the transition from proven concept to

commercial product. For these reasons, the industry may continue to be dependent for some

time on external research efforts, such as those

supported by the Department of Energy and the

Gas Research Institute, to develop the tight gas

resource.

~71bid.

38J. W. Crafton, “Fracturing Technologies for Gas Recovery From

Tight Sands, ” contractor report to OTA, September 1983.
Ch. 8—Tight Gas ● 1 5 7

THE RECOVERABLE RESOURCE BASE AND

PRODUCTION POTENTIAL

Estimates of economically recoverable gas from

tight gas formations are extremely sensitive to

assumptions made about price, level of technology, and the volume of gas-in-place. Existing estimates range from a conservative 30 TCF to almost

600 TCF.

Some recoverable gas estimates include an

assessment of the technically recoverable gas

(also called maximum recoverable gas) in addition to the economically recoverable gas. Technically recoverable gas represents that gas recoverable from tight formations under optimistic

assumptions of technological development, assuming price is relatively unconstrained. The economically recoverable gas, in contrast, is subject

to both economic and technological constraints.

It is usually calculated for several price and technology levels and reflects the sensitivity of recoverability to these parameters.

Detailed estimates of both technically and economically recoverable tight gas were made by

Lewin Associates and by the National Petroleum

Council in conjunction with their gas-in-place resource estimates. The Gas Research Institute (G RI)

has also estimated the economically recoverable

resource in tight formations. The NPC study is the

most comprehensive of these analyses and is discussed here in the most detail. The other studies

are included for comparison, particuIarly where

different methodologies or assumptions are shown

to substantially affect estimates. All these estimates assume two levels of technology. The

“base case” uses technologies currently available

or thought to be available in the near future. The

“advanced case” represents technologies that

might be developed given a concerted research

effort.

Methodologies and Results

Lewin Estimate

The Lewin report calculated the technically

recoverable gas using its “advanced case” technology criteria, which assume a maximum well

spacing of six wells per section (107-acre spacing) and a maximum fracture length of 1,500 ft.

They determined that 211 TCF, close to half of

the total gas-in-place resource, was technically

recoverable. The percent of gas-in-place estimated to be recoverable for the individual basins

ranges from 10 to 80 percent, as shown in table 38.

Table 38.—Maximum Recoverable Tight Gas Resources, TCF

Lewin NPC

Maximum Percent Maximum Percent

Appraised basins GIPa

recovery recovery GIPa

recovery recovery

Northern Great Plains/Williston . . . . . . . . . . . . 74 35 47% 148 100 68 ”/0

Greater Green River . . . . . . . . . . . . . . . . . . . . . . 91 36 40 136 87 61

Uinta . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50 18 36 20 15 75

Piceance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 12 33 49 33 67

Wind River . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 33 34 23 68

Big Horn . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 8 33

Douglas Creek . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 0.3 10

Denver . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 13 68 13 8 62

San Juan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 12 80 3 2 67

Ozona. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 0.6 60

Sonora . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 16 67 4 2 50

Edwards Lime. . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 9 64

Cotton Valley “sweet” . . . . . . . . . . . . . . . . . . . . 67 50 75 22 13 59

Cotton Valley “sour”. . . . . . . . . . . . . . . . . . . , . . 14 10 71

Ouachita . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 1 20

Total . . . . . . . . . . . . . . . . . . . . ., . . . . . . . . . . . . 423 212 500/0 444 292 66%

Extrapolated basins. . . . . . . . . . . . . . . . . . . . . . . 480 315 66

aGIP = Gas-in-place.
158 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Lewin determined that 70 to 108 TCF could be could be produced under advanced case techeconomically produced under base case technol- nology conditions and the same price range, as

ogy conditions for well head prices ranging from shown in table 39. The different assumptions used

$1.75 to $4.50/MCF (1977$) and $2.75 to $7/MCF for the base and advanced case estimates are

(1983$), They determined that 150 to 188 TCF given in table 40.

Table 39.- Economically Recoverable Gas at Two Technology Levels (TCF)

Price per MCF

Study date 1983 Base Advanced

dollars dollars technology technology

Lewin (1977) . . . . . 1.75

3.00

4.50

GRI (1979). . . . . . . 3.12

4.50

6.00

NPC (1979) . . . . . . 2.50

5.00

9.00

(2.75)

(4.70)

(7.00)

(4.20)

(6.00)

(8.00)

(3.35)

(6.70)

(12.00)

70

100

108

30

45

60

Total Appraised

192 97

365 165

404 189

149

182

188

100

120

150

Total Appraised

331 142

503 231

575 271

Table 40.—Lewin & Associates Base v. Advanced Technology

Parameter Base case Advanced case

Fracture height , . . . . . . . . . . . .

Fracture length (one way)

Shallow gas sands . . . . . . . .

Near-tight sands . . . . . . . . . .

Tight gas sands. . . . . . . . . . .

Fracture conductivity . . . . . . . .

Field development

Lenticular . . . . . . . . . . . . . . . .

Blanket . . . . . . . . . . . . . . . . . .

Net pay contacted

Lenticular sands

320 acres drainage . . . . . .

107 acres drainage . . . . . .

Blanket sands . . . . . . . . . . . .

Dry hole rate:

Lenticular ., . . . . . . . . . . . . . .

Blanket . . . . . . . . . . . . . . . . . .

Discount rate. . . . . . . . . . . . . . .

4 times net pay

(200’ minimum, 600

maximum fracture

height)

200 ‘

500’

1,000 ‘

Decreases with

using current

and methods

depth

proppants

320 acres per well

(2 wells per section)

160 acres per well

(4 wells per section)

17%

—

100%

300/0

20%

26°/0 (20°/0 real)

3 times net pay

(150’ minimum, 400

maximum fracture

height)

500 ‘

500 ‘

1 ,500‘

(Using improved proppants

and methods to maintain

adequate conductivity)

107 acres per well

(6 wells per section)

160 acres per well

(4 wells per section)

—

800/0

100%

200/0

10%

16°/0 (10°/0 real)

SOURCE: V. A. Kuuskraa, et al., Enhanced Recovery of Unconventional Gas: The Program- Volume II, US, Department of Energy

report HCP/T2705-02, October 1978.
Ch. 8—Tight Gas ● 159

The Lewin estimates were developed using

reservoir simulation-based production curves for

blanket and Ienticular reservoirs to determine

cumulative reserves from a well over a 30-year

period. Input parameters included reservoir characteristics for the individual basins and pay quality

intervals, fracture lengths, fracture conductivity,

and drainage area of a well.

Production per year per well for the assumed

wells, multiplied by the assumed gas price, gives

the positive cash flow for the economic model.

Offsetting costs include the initial investment in

exploration, drilling, and stimulation, plus operating and maintenance costs, royalties, and taxes.

A required rate of return of 20 percent (real) was

used for the base case estimates, dropping to 10

percent in the advanced case to reflect lower risks

associated with the greater predictive capabilities

and higher efficiencies associated with advanced

technology,

National Petroleum Council

In contrast to the Lewin method of calculating

the technically recoverable gas using its advanced

technology criteria, the NPC determined the maximum recoverable gas directly from the gas-inplace estimates. The maximum recoverable gas

is defined as the total amount of gas that can be

produced from a reservoir before the gas pressure in the reservoir reaches the “well bore drawdown pressure.”39 This quantity is further modified by a “recovery adjustment factor” meant to

take into account the existence of very low permeability areas within a field that are unlikely to

be productive, Recovery adjustment factors range

from 50 percent for blanket reservoirs with average permeabilities of 0.00001 md, to 95 percent

for blanket reservoirs with average permeabilities

of 0.3 md.40 Lenticular reservoirs use more conservative adjustment factors. The NPC study de-

~qThe production of gas depends on a pressure gradient eXiSting

between the wellbore and the rest of the reservoir. As the pressure in a formation IS reduced through production, the reservoir

pressure and the wellbore pressure approach equilibrium. Eventually no further gas WIII flow naturally, The INPC assumed that the

reservoir pressure .at this point would be approximately 10 percent

of the original formation pressure. Any gas remaining in the reservoir cannot be produced except by expending energy to induce

an artificial pressure gradient.

40NPC Report, vol. V, part 1, table 15.

termined the technically recoverable gas for a set

of appraised and extrapolated basins to be 292

and 315 TCF respectively. Its results are also

shown in table 38.

The NPC estimates of economically recoverable gas range from 192 TCF at $2.50/MCF (1979$)

with base case technology to 575 TCF at $9/MCF

with advanced technology, as shown in table 39.

The base case is represented as “current fracturing technology and well spacing regulations, ” but

apparently allows for some evolution and improvement of the technologies over time as operators gain experience. The advanced case incorporates new technologies developed by a

concerted R&D program. The methodology used

by the NPC to determine the economically recoverable gas is similar to the Lewin methodology. Cumulative production per well was determined from type curves41 for base and advanced

technologies. This gives the number of wells per

section required to produce all of the recoverable

gas in a given permeability level in a formation.

The base and advanced technology criteria are

shown in table 41. In the economic model, costs

of drilling and fracturing and operating costs are

subtracted from income from production at various prices, and a marginal rate of return is calculated. All formations with a rate of return less

than a prescribed value (10, 15, or 20 percent)

are considered unprofitable.

It has been suggested that the NPC method of

using type curves designed for 640-acre (one well

per section) spacing to determine cumulative production levels from blanket formations at 160-

acre (four wells per section) and smaller spacings

could result in a substantial overestimate of the

recoverable resource. The expected cause of this

overestimate is the inability of the (640-acre) type

curve to account for the greater interference between wells that would occur at 160-acre spacing (interference reduces the production per

—-. . . . .

4’Type curves are normalized representations of cumulative production over time generated from reservoir simulation models. Because the data are generated in terms of dimensionless values, they

are applicable over a wide range in the reservoir parameters

(permeabilities, poroslties, net pay, pressure, temperature, gas composition, and fracture conductivity). Different type curves, however, are required for different well spacing rules. They are an efficient technique for obtaining estimates of cumulative recovery and

producing rates for a large number of reservoirs.
160 U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Table 41 .-NPC Base v. Advanced Technology

Blanket formations Lenticular formations

1. Fracture height . . . . . . . . . . . 4 times net pay 3 times net pay 6 times net pay 4 times net pay

Range (ft) . . . . . . . . . . . . . . . . 200-600 150-400 300-1,000 200-600

2. Fracture conductivity

(md-ft) . . . . . . . . . . . . . . . . . . . 500 1,000 500 1,000

3. Fracture length, wellbore to

tip (ft), permeability

>=0.1 md

Effectively achieved . . . . . . . 1 ,000‘ 2,000 ‘ 1 ,000‘ 4,000 ‘

Hydraulic design required . . 1 ,700‘ 2,500 ‘ 1 ,700‘ 5,000 ‘

4. Field development,

wells per section

(maximum) . . . . . . . . . . . . . . . 4 12 4 12

Acres per well (minimum) . . 160 53 160 53

5. Lenses remote from the

wellbore may be contacted

by fractures? . . . . . . . . . . . . . NA NA Yes Yes

aProduct of fracture permeability and fracture width.

SOURCE: National Petroleum Council, Unconventional Gas Sources, vol. V, part 1, December 1980.

well).42 The overestimate of production per well

would be greatest at the higher permeability

levels where more of the economically producible gas is found. This problem is not as serious

as it might appear, however, because of the way

the type curve data were used in the NPC report.

If the NPC had computed total production from

wells drilled to determine gas recovery, assuming a standard “four wells per productive section, ” then they would have overestimated the

maximum recoverable resource. Instead, as noted

previously, NPC determined the maximum recoverable gas independently of the type curves, applying recovery factors to the gas-in-place. The

cumulative 30-year production of a well, derived

from the type curves, was used only to determine

the number of wells per section required to produce the maximum recoverable gas.

At the higher permeability levels, all of the

recoverable gas can be produced by less than the

four wells per section base case constraint. Thus,

although the NPC may have urderestimated the

number of wells required to produce these

permeability levels, unless the actual number of

wells required exceeds the four wells per section

constraint, it has not overestimated the amount

of gas that can be produced.

qlGruy petroleum Technology Inc. report to EIA, “Correlations

for Projecting Production From Tight Gas Reservoirs. ”

At lower permeabilities (0.3 md and lower),

where more than four wells per section are required to produce all the gas in the formation,

the NPC technique may overestimate the economically recoverable gas for the base case.

Nevertheless, the amount of gas involved is not

large. For example, a sensitivity analysis of the

NPC estimates shows that a shift to 160-acre type

curves would not have changed the estimate of

recoverable reserves for the blanket formations

by more than 10 percent.43 A similar problem

does not exist for the advanced case because all

of the gas at all permeability levels can be produced from less than the allowed 12 wells per

section.

Gas Research Institute

The most recent estimate of the gas recoverable

at different price and technology levels has been

made by the Gas Research Institute and is also

shown in table 39. These estimates are considerably lower than both the Lewin and the NPC estimates, ranging from 30 TCF at $3/MCF (1 979$)

and base technology, to 150 TCF at $6/MCF and

advanced technology. GRI derived its estimate

by making judgmental adjustments to existing

estimates. It concentrated on those basins where

43J P. Bra;ear, et al., “Tight Gas Resource and Technology Appraisal: Sensitivity Analysis of the National Petroleum Council Estimates , 1984 SPE/DOE/GRl Unconventional Gas Recovery Symposium, SPE/DOE/GRl 12862, Pittsburgh, PA, May 13-15, 1984.
Ch. 8—Tight Gas . 161

the tight sands resource was best understood and,

in addition, attempted to eliminate tight gas that

might conceivably be considered conventional.

Its conservative approach was specifically designed to provide an estimate of that portion of

the tight gas resource which had a high probability of occurrence.

Comparison of Estimates and

Discussion of Uncertainties

One of the major differences between the

recoverable resource estimates is the difference

in the total areas assessed, since the amount of

gas estimated to be recoverable is intimately tied

to the proportion of the gas-in-place actually included in the study and evaluated for recoverability. The NPC, Lewin, and GRI recoverable resource estimates each are based, implicitly or

explicitly, on a different gas-in-place resource

base. The NPC, by including both the appraised

and extrapolated basins, begins with the largest

gas-in-place resource base. Lewin restricts its estimate to those basins for which considerable information is available. GRI also restricts its estimate on this basis, but apparently further limits

the resource base it evaluates by excluding all potential areas of overlap with conventional resource estimates. Where the areas assessed by

NPC, Lewin, and GRI overlap, however, there

are still substantial differences in the estimates of

recoverable gas. These differences result from the

underlying assumptions used in the estimating

process.

In the sections that follow, we first compare

recovery estimates for a comparable area—the

appraised resource—to show how different assumptions affect the estimates of technical y and

economically recoverable gas. Next, we briefly

discuss a portion of the resource base evaluated

by broad geologic analogy rather than direct

appraisal—the extrapolated resource. Finally, we

discuss briefly the geological/geographical boundaries used in the resource estimates. Included in

each section is a discussion of the major uncertainties underlying the estimates and how these

uncertainties affect the amount of gas recoverable. it is important to remember that many of

the uncertainties in calculating the gas-in-place

are propagated through to the calculations of the

technically and economically recoverable resource.

The Appraised Basins

The appraised basins of the Lewin and NPC

studies have comparable total volumes of gas-inplace, as discussed in the previous chapter. Despite this agreement, their estimates for potential recovery of tight gas are significantly different

(the technically recoverable gas is two-thirds of

the gas-in-place in the NPC study compared to

half of the gas-in-place in the Lewin study). Differences in percent of gas-in-place recoverable

are particularly apparent on an individual basin

level, as seen in table 38, and can be attributed

to the different assumptions used by the estimators to calculate both technically and economically recoverable gas.

The NPC approach to estimating maximum recoverable gas is independent of any technology

assumptions and effectively assumes that virtually

all gas in a formation will ultimately be in contact with a well bore. In contrast, the Lewin estimate is constrained by a set of advanced technology criteria that do not allow the entire

gas-bearing portion of a formation to be contacted, even under the most favorable conditions.

The Lewin estimate is more conservative than the

NPC estimate in its assumed fracture lengths and,

for Ienticular resources, in its assumptions about

the probability of producing from lenses not in

direct contact with the wellbore.

Differences between the Lewin and NPC estimates of economically recoverable gas in the appraised basins are caused primarily by differences

in their assumptions about base and advanced

case technology conditions (tables 40 and 41).

For the base technology case, the Lewin estimates

of economically recoverable gas are only twothirds of the NPC estimates (see fig. 31). The effects of shorter assumed fracture lengths in some

areas, especially the Northern Great Plains, a constraint of two wells per section in Ienticular formations, and the constraint that only lenses in

direct contact with the wellbore could be produced probably account for the lower estimates

of recoverable gas in the Lewin estimate.
162 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

100

0

Figure 31.— Comparison of Recoverable Estimates (for gas price in 1983$)

Comparison: Lewin Assoc.

NPC

GRI

NPC (total) advanced technology

NPC (total) base technology

r

NPC (12 basins) advanced technology .

~-- -

-- ------- -

- -

/4Lewin Advanced Technology

F

NPC (12 basins) base

—* techn~y+ — . _ — “

“ -*~ “ — “ — 

- “

- GRI advance d

--”” ‘-

-~”=” — — Lewin base technology

I

. _GRI bas e

.— . — “ —“—

I I I 1 I I

0 1.00

Under advanced

2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00 11.00 12.(

Wellhead price, $/MCF

technology criteria, there is

little difference between the NPC and Lewin estimates at the lower prices despite the NPC technical potential for much higher levels of production using 2,000- to 4,000-ft fractures and up to

12 wells per section. The increased “per section”

production potential in the NPC analysis is probably offset by increased costs of longer fractures,

which would make many of the lower permeability prospects unprofitable at lower prices. The

lower marginal rate of return in the Lewin advanced case allows it to bring a number of its previously unprofitable wells on line, increasing the

percent of the technically recoverable gas that

can be economically produced. In this case,

tradeoffs between costs, rates of return, and

recovery per well allow two entirely different sets

of assumptions to result in approximately the

same amount of gas produced. At higher prices,

however, the higher fracturing costs of the NPC

estimate become less of a factor in determining

profitability of a well and the NPC estimate of

recoverable gas is again higher than the Lewin

estimate.

The above comparison of the Lewin and NPC

appraised basin estimates points out how different

assumptions of price, rate of return, and state of

tech no logic development affect the estimates of

technically and economically recoverable gas.

The inherent uncertainty in some of these assumptions is the major factor in whether the estimates can be considered an accurate representation of the recoverable resource.

The primary uncertainty lies in the technology

assumptions for the different tight gas formations.

The NPC assumptions are considerably more optimistic than those used by Lewin. Assumptions

made by the NPC that are most likely to be

challenged include:

1.

2.

fractures in Ienticular formations will contact

(and allow production from) lenses distant

from the wellbore;

currently available technology will allow

propped 1,000-ft fractures in all producing

situations, advanced technology will allow

4,000-ft fractures with fracture heights less
Ch. 8—Tight Gas 163

3.

than currently achieved with 1,000-ft fractures; and

every stimulation will be successful in

achieving its design criteria (length, orientation, and direction).

OTA considers these assumptions to be optimistic, especially for the base case, but also for the

advanced case as well. As noted in the technology discussion, not all of the base case conditions

have been met at the present time. Although

evolution and improvement of existing technology during normal operations44 will occur, the

base case criteria still appear optimistic. Some of

the base case and advanced case criteria do appear likely to be met over the long term under

a strong R&D program; others may deserve to be

substantially modified.

1. Contacting Remote Lenses. A major assumption of the NPC study is that massive hydraulic

fractures in Ienticular formations can contact

lenses distant from the wellbore, in both the base

and advanced technology cases. This assumption

underlies the inclusion of vast areas of Ienticular

formations into the tight gas recoverable resource

base. The NPC estimates that 126 TCF is recoverable from Ienticular formations in 4 of the 12 appraised basins—43 percent of the total recoverable resource in all appraised basins. To date, no

evidence exists that remote lenses can be contacted, despite a number of fractures completed

in Ienticular formations. In recent analyses of tight

gas resources, GRI has assumed zero contact of

remote lenses for its “present technology” case.45

The DOE Multiwell Experiment is designed to

answer this remote lens question; if the results

of this experiment prove disappointing, estimates

of the amount of gas that can be recovered from

tight Ienticular formations may need to be substantially reduced.

A recent sensitivity analysis of the ability to contact remote lenses has been performed using a

computer simulation of the NPC study.46 This

analysis determined that the technically recovdqAs noted previously, such evolution and improvement is considered to be included in the base case technology conditions.

45Briefingdocumentfor the Tight Gas Analysis System, Lewin &

Associates, Inc., 1984.

qbThe Slmu[ation is called the TGAS Simulator, described in

Brashear, et al., op. cit.

erable gas from appraised Ienticular formations

would be reduced by about half if remote lenses

could not be contacted. For example, for an

allowable 12 wells per section, recovery per well

would drop from 100 to 48 BCF. This effect is

magnified for the economically recoverable gas,

especially at moderate prices, because some lenticular formations cannot be developed at all

unless remote lenses can be produced. For example, at gas prices of $2.50/MCF in 1979$ ($3.35

in 1983$) and a rate of return of 15 percent,

assuming advanced case technology, the NPCestimated economically recoverable gas from the

appraised Ienticular basins is 37 TCF if remote

lenses can be produced and only 10 TCF if they

cannot be. Without production from remote

lenses, the Ienticular tight formations may not

play a significant role in future U.S. gas production.

2. Achievable fracture characteristics. As noted

earlier, there is considerable disagreement about

the extent to which the NPC-defined fracture

characteristics realistically reflect both current

technology and achievable future technology.

For the NPC “base” or current technology,

OTA is particularly skeptical of the assumption

of 1,000-ft achievable fractures for the Ienticular

resource (see the Technology section). Recent

Gas Research Institute analyses have used propped

fracture lengths of 600 ft and fracture conductivities47 of 400 md-ft (v. NPC’s 500 md-ft) to represent “present” technology.48 49 As with changes

in assumptions about contacting remote lenses,

the effect of these changes in fracture characteristics is to substantially reduce the recoverable

gas at all price levels. Figure 32 shows the combined effect on recoverable resources of the “no

contact of remote lenses” assumption and the

changes in fracture characteristics. For example,

recoverable gas at $9/MCF (1982$) is reduced by

about 25 percent, from roughly 400 to 300 TCF.

qTFracture conduc tivity: the product of fracture permeability and

width, a measure of how well gas can flow along the fracture.

q86riefing document for the Tight Gas Analysis System, oP. cit.

49 GR115 “present tectlno[ogy” and NPC’S base case may not describe precisely the same technology level, however, because NPC’S

base case includes the evolutionary effects of future operations.

On the other hand, the GRI criteria were defined several years after

the NPC’S were.
164 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Figure 32.–Comparison of NPC Study Results With

GRI Present Case—Tight Gas Sands Recoverable Gas

10.00 r . . . ,

8.00

6.00

5.00

4.00

3.00

. . . .

1.00

0 ‘

\ 1 I +

o 100 200 300 400

Economically recoverable gas (TCF)

GRI has also chosen to use more modest fracture characteristics than NPC for its “R&D Success” case, which includes improved geological

and geophysical techniques, improved fracture

design and diagnostics, and real-time fracture

diagnosis and control:50 fracture length and conductivity are assumed to be 2,000 ft and 800 mdft, respectively, v. NPC’s 4,000 ft and 1,000 mdft. Although OTA agrees that these NPC “advanced case” fracture characteristics appear to

be quite optimistic, our major concern lies with

the NPC assumptions for fracture height. GRI has

accepted the NPC’s fracture height criteria for

both the current and advanced cases.51 According to these criteria, the 4,000-ft fractures will

have shorter fracture heights than the 1,000-ft

fractures (e.g., for blanket sands, fracture height

is six times net pay for the 1,000-ft fracture and

four times net pay for the 4,000-ft fracture).

Because of the shorter fracture height, the

longer fractures will be cheaper per unit length

than the base case fractures, which in turn adds

substantially to the estimated recoverable resource in the “advanced technology” case. The

fracture height assumption reflects NPC’s belief

that careful control of fracture placement and

—.—50Th~ latter improvement allows problems encountered in fracturing to be diagnosed and fixed in “real time, ” i.e., as the fracture is being made.

51 Briefing document, Op. cit.

fracturing fluid pressure will serve to maintain

small fracture heights. This is the opposite of current experience, where longer fractures generally are associated with increased fracture height

and higher (per unit length) costs. On the other

hand, current fracturing technology does not include reservoir and fracture-propagation modeling capabilities that provide “real time” (during

the actual fracturing process) control of well treatmerits.52 GRI is sponsoring research to develop

this capability and clearly hopes that successful

development will allow longer fractures to be produced without increasing fracture height. Future

improvement in fracture control clearly is a certainty. Nevertheless, assuming a reduction in fracture height in conjunction with a fourfold increase in fracture length appears to be optimistic.

In addition, the NPC’s specification of fracture

height as a constant multiple of net pay thickness

serves to automatically favor thin, higher permeability intervals over thicker, low-permeability intervals, This is because fracturing costs area function of the volume of fracture fluid required,

which in turn is a function of fracture height. Consequently, using NPC’s assumptions, thin, rich,

high-permeability pay intervals will tend to appear very attractive to develop even though in

actual experience it may be difficult to achieve

very long fractures in such intervals without exceeding the “four or six times net pay” fracture

height constraint. As a result, the NPC’s fracture

height assumptions may yield estimates of more

gas at lower prices than maybe realistically producible. However, this effect may be counter balanced somewhat by the empirical relationship

between net pay thickness and permeability assumed by NPC. Because the NPC believed that

most of the tight gas resource lies in the lower

permeability rocks, they assumed that the higher

permeability gas-bearing zones would be thin and

the lower permeability zones would be thick. Because the initial productivity, and thus the economic viability, of a well depends on the product of thickness and permeability, the assumption

that higher permeability zones would essentially

always be thin is pessimistic. An alternative

sZGas Research Institute, Status Report: GRI’s (Jnconventiona/

Natural Gas Subprogram, December 1983,
Ch. 8—Tight Gas ● 165

assumption, albeit an optimistic one, that all pay

zones are the same thickness would yield a 46-

percent increase in the recoverable resource at

$2.50 gas in 1979$ ($3.35 in 1983$) with the base

technology. The relative effect decreases at higher

gas prices and improved recovery technology.53

Finally, whether or not the NPC’s fracturing criteria are generally realistic, OTA is concerned that

they were universally applied to all formations

regardless of geologic character, except for the

separation of blanket and Ienticular formations.

For example, using these fracturing criteria, the

Northern Great Plains becomes one of the dominant sources of recoverable gas from blanket formations. Apart from the question of how much

gas exists in the Northern Great Plains, geologic

characteristics of these shallow, low-pressure

reservoirs can also restrict the amount of recoverable gas. For example, the presence of watersensitive clays makes these reservoirs sensitive to

formation damage.54 Also, experience has shown

that fractures in shallow formations may propagate horizontally rather than vertically, reducing

the net pay drained by each well, and significantly

reducing the recovery efficiency, Thus, the appropriateness of assuming 4,000- or even 1,000-ft

fractures in assessing recovery from these reservoirs, and thus counting on up to 70 to 90 percent recovery of the gas-in-place, is questionable.

The Lewin study assumed that short fractures (200

to 500 ft) would be used in these reservoirs, and

assumed that fractures in the shallower formations would propagate horizontally.55 Its ultimate

recovery efficiency in the Northern Great Plains

is only 47 percent of the gas-in-place (table 38).

More accurate assessment of the recoverability

of gas from these formations, using more sitespecific technologies, is needed. For example, the

use of air-drilled open hole wells at close spacings may be a preferred method of production

considering the low drilling and completion costs

for these depths and the avoidance of formation

damage. 56 Ultimate recovery from this region appears more likely to be on the order of so per-

‘~J. P. Brashear, et al., op. cit.

54R. L. Gautier and D. D. Rice, “Conventional and Low

Permeability Reservoirs of Shallow Gas in the Northern Great

Plains, ” journal of Petroleum Technology, july 1982.

ssLewin, vol. 11, pp. 3-57.

sGGaut;er and Rice, Op. cit.

cent (or less) of the gas-in-place rather than the

NPC’s estimated 70 to 90 percent.57

3. Success Rate of Fracture Treatments. Further,

the NPC study assumes that each fracture treatment is successful in achieving design criteria.

Fractures are assumed to never grow vertically

out of the pay zone at the expense of fracture

length. They are never offset against existing natural fractures or intersect one another at close

well spacings. Formation damage is minimal. The

NPC approach assumes that technologic development will be able to overcome all of these

problems. In fact, however, some of these problems appear to be inherent to the formations.

With better reservoir characterization, producers

may be able to better predict where fractures will

grow out of the pay zone or what the probability is that they may intersect, but they may never

be able to control many of these occurrences;

other occurrences may be controllable but only

at added cost. OTA feels that 100 percent fracture success is an overly optimistic assumption.

[n addition to uncertainties associated with the

fracturing technology criteria, an important uncertainty in the appraised recoverable resource

is associated with the geology of the Northern

Great Plains:

The Northern ‘Great Plains

If gas does not exist in large quantities in the

Northern Great Plains, the estimated recoverable

resource will have to be substantially reduced

regardless of the success of advanced technologies. The NPC estimates that 100 TCF, one-third

of the technically recoverable gas in the appraised

basin estimate, can be produced from this region.

According to the NPC criteria, much of this gas

ought to be relatively inexpensive to produce.

Approximately 54 TCF is estimated to be recoverable at $2.50/MCF (1 979$) using base technologies. Even the more conservative Lewin estimates predict that 21 TCF will be recoverable at

$1.75 (1977$) under base case conditions. Despite this apparent incentive, however, there appears to be little current interest in developing

SzDudley Rice, U.S. Geological Survey, Denver, CO, personal

communication.
166 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

tight gas in the Northern Great Plains. No FERC

filings for tight gas designations in the Northern

Great Plains have been made to date. Reasons

for the lack of interest may include external constraints, such as an absence of pipelines and market problems due to the existing surplus. However, there are other tight gas basins with similar

transportation/market problems—e.g., the Uinta

and Piceance basins—that have sustained at least

moderate development efforts, so these problems

do not fully explain the lack of activity in the

Northern Great Plains.

On the other hand, a recent GRI analysis58

claims that the current lack of activity and high

estimated recoverable resource can be reconciled

by comparing the profitability of individual prospects in the Northern Great Plains with prospects

in other tight gas basins. The Northern Great

Plains is described as “having a very geologically

diffuse resource, which would require large numbers of shallow, low-pressure wells spread over

great distances.”59 While the Northern Great

Plains contains more total economically recoverable gas than competing basins at any price

level, several basins in the Rockies and Southwest

were found to contain a number of individual formations offering greater profitability per thousand

cubic feet of gas extracted. These prospects are

characterized as offering larger field sizes and

greater well productivity and recoverable gas per

section than prospects in the Northern Great

Plains. Because developers make investment

decisions on the basis of individual prospects and

not entire basins, development of the Northern

Great Plains might not be expected to occur until the more attractive prospects elsewhere were

exploited. GRI also speculated that the intermingling of tight formations with established gasfields in the Rockies and Texas would also provide an important incentive for developing these

basins first, because developers tend to want to

drill in areas where they have had previous successful experience.

The questions concerning gas-in-place, producibility, and current activity levels call for an in58J. 1. Rosenberg, “The Economics of Tight Sands Gas Extraction

as Affected by R& D,” Gas Research Insights series, Gas Research

Institute, August 1983.

Jglbid.

dependent assessment of the Northern Great

Plains production potential. Such an assessment

should include a reevaluation of the gas-in-place,

the engineering characteristics of the reservoirs,

and the costs and technologic requirements of

producing from these reservoirs. An analysis of

the external constraints and their temporal significance is also needed.

The Extrapolated Resource

The NPC approximately doubles the volume

of its gas-in-place estimate by including 101 additional basins in the resource base. Because it

assumes that the formations in the extrapolated

basins have similar producing characteristics to

analog formations in the appraised basins, it also

approximately doubles the estimated technically

recoverable resource as well as the economically

recoverable resource.

It is generally agreed that the extrapolated

basins represent the most speculative part of the

NPC resource estimate. In addition to the uncertainty as to the quantity of gas existing in these

basins, there are further uncertainties in the extrapolation of engineering characteristics for gasproducing formations and the consequent estimates of production. There is sufficient information in these areas to say that some gas is there,

and that some of it may be economically produceable, so the extrapolated resource certainly

cannot be entirely disregarded. If FERC filings can

be considered indicative of productive areas (if

not of actual volumes of gas), then the large number of filings for the Eastern and Southwestern

United States may bean encouraging sign for the

production potential from extrapolated basins.

Recent studies have been undertaken to better characterize the extrapolated basins,60 but

data sufficient to revise the NPC estimates are not

yet available. Because the potential contribution

of the extrapolated basins to the recoverable resource has been estimated to be so large, more

detailed assessments remain a high-priority area

for future research.

mR. j. Finley and P.A. O’Shea, “Geologic and Engineering Analysis of Blanket-Geometry Tight Gas Sandstones, ” 198.3S/?E/DOE

joint Symposium on Low Permeability Gas Reservoirs, SPEIDOE

11607.
Ch. 8—Tight Gas . 167

Many who use the NPC figures in their analysis of gas supply consider only the recoverable

gas in the appraised basins because of the

speculative nature of the extrapolated resource.

OTA suggests that it is overly conservative to

disregard the extrapolated resource altogether,

especially since FERC filings indicate that development is going forward in some of the extrapolated basins; however, until better estimates are

available, it may be more useful to consider the

extrapolated recoverable resource estimates in

a category separate from the more precise estimates of the appraised basins.

Effect of Boundary Conditions

Double Counting. –The separate estimation of

the conventional and unconventional natural gas

resource base by different groups, coupled with

poorly stated “boundary conditions” for each

estimate, can lead to some resources being

counted in both conventional and unconventional estimates (e.g., “double counting”). This

would lead to an overestimate of the total natural gas resource.

Tight gas has the highest level of current production of all the unconventional resources. Because of the existing production, there is some

controversy over how much of the tight gas resource has already been included in conventional

resource estimates, and thus in estimates of future

conventional gas production. To the extent that

it is so included, it cannot be considered as a potential supplemental source of supply.

Most conventional resource assessments are

not well documented; and comparison of conventional with unconventional estimates is not

straightforward. Recently, the Potential Gas Committee (PGC) has attempted to determine what

percent of its total conventional undiscovered

recoverable resource61 occurs in tight formations.

It concludes that 172 TCF, or 20 percent of its

total potential recoverable resource, is tight gas.62

61 I ncludi ng re50urCes made avai [able by the growth of alreadydiscovered fields because of enhanced recovery, discovery of new

reservoirs, etc.

GZThe pGC tight gas estimate included both tight sands and DevOnian shales. However, conversations with the people responsible

for determining tight gas in the eastern region have indicated that

the Devonian shale contribution to the tight gas estimate is very

sma[l.

A considerable portion of this gas does not overlap with the NPC tight gas resource, however,

because it is below 15,000 ft (the NPC depth

limit), in areas already undergoing development

(and thus not unconventional according to the

NPC definition), or simply in locations not considered by the NPC study to be prospective.

There is no unequivocal data set that will allow

an accurate estimate of the overlap between conventional and unconventional natural gas resources. Estimates range up to 100 TCF,63 and the

PGC has recently suggested that as much as half

of the tight gas in its estimate may represent an

overlap with the NPC resource64 An OTA analysis of the overlap, presented in appendix C, indicates that the total overlap between the PGCestimated 172 TCF of tight gas and the N PC-estimated 606 TCF of recoverable tight gas may be

as low as 30 TCF. Even the low side of the overlap, however, though relatively small compared

to the total size and large uncertainties in the tight

gas resource estimates, is still important in assessing the unconventional tight gas contribution to

near- and mid-term production because the 30

TCF are in the most accessible, least expensive

portion of the tight gas resource. The main areas

of overlap occur in the blanket formations of the

Rocky Mountain Basins and the Cotton Valley

Trend in Texas and Louisiana. These areas currently are the major producers of gas from tight

formations, and the NPC report has predicted

these areas to be the main contributors to “unconventional” supply in the next 20 years.

Deep Tight Gas.–Another problem arising from

inadequately defined boundary conditions is that

certain potential resources may be overlooked

entirely, resulting in an underestimate of the total

resource base. For example, the PGC estimated

that its conventional gas resource base includes

some 89 TCF of gas in tight formations at depths

greater than 15,000 ft. The NPC report acknowledges that large volumes of gas probably occur

at depths greater than 15,000 ft, but they assumed

this gas to be too speculative a resource to in63vel10 KUUSkraa, Lewlrl & Associates, Inc., personal communication, 1984.

MH. C. Kent, Director, Potential Gas Agency, testimony before

the Subcommittee on Energy Regulation, Senate Committee on

Energy and Natural Resources, Apr. 26, 1984.
168 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

elude in its tight gas assessment.65 Other experts

have concurred that large volumes of gas exist

in deep tight formations, in the Rocky Mountain

Basins as well as the Anadarko and Arkoma

Basins in Oklahoma and Arkansas. Many of the

deeper Rocky Mountain formations are Ienticular.

Apart from the PGC estimate, which is widely

viewed as an estimate of the conventional resource, there are no quantitative estimates of

recoverable resources in deep tight formations.

Deep tight formations, other than those already

included in the PGC estimates, probably should

be included in future estimates of the unconventional tight sands resource at least for the estimates of gas-in-place. They represent no more

speculative a source of gas supply than the unfractured portions of the Devonian shales or the

deep coal seams, both of which generally are included in gas-in-place estimates of unconventional resources.

Conclusions About Recoverable Gas

To summarize, OTA considers the NPC estimates of recoverable tight gas resources to be optimistic. The major reasons for this appraisal are:

1.

2.

3.

The Northern Great Plains. OTA considers

it quite plausible that the recoverable resources in the Northern Great Plains are considerably lower than the 100 TCF maximum

recoverable gas projected by the NPC.

Gas-in-Place. Aside from the Northern Great

Plains, OTA believes the NPC’s gas-in-place

estimates to be reasonable, in the context

of “most likely” values. The margin for error is large, however, especially for the extrapolated resource; the estimate for the extrapolated resource should be considered as

speculative.

Technology. OTA considers some important

aspects of NPC’s appraisal of current technology and projection of advanced technology to be over-optimistic. Of particular concern is the assumption that fractures will be

able to penetrate and drain lenses remote

.—

bSAccording to Ovid Baker, Chairman of the NPC Tight Gas Task

Group, deep tight gas below 15,000 ft would cost more than

$12/MCF to produce, and the NPC upper limit on price was $9/MCF

(Ovid Baker, personal communication, 1984).

from the wellbore. Another important concern is that very long fractures (up to 4,000

ft) can be achieved with a net decrease in

fracture height.

OTA also believes that all available estimates

of recoverable tight gas are highly uncertain because of poorly defined reservoir characteristics

and technologic uncertainties. However, there

seems little doubt that large quantities—at least

a few hundred TCF—of tight gas will be recoverable even under relatively pessimistic technologic

circumstances, provided gas prices reach moderately high levels in the future (e.g., $5 to $7/

MCF in 1984$).

Annual Production Estimates

Any forecasting of actual production from the

tight gas resource requires making a number of

assumptions over and above those made to estimate the recoverable resource, and similarly

uncertain. Projections must be made of the price

of gas and the state of technology development

over the time interval of the forecast. These are

the critical uncertainties. The amount of “high

potential” land immediately available for drilling

must be estimated. Finally, an estimate must be

made of the number of wells that can be drilled

within a single year and the rate of increase in

following years. The comparison of different forecasts requires an understanding of these underlying assumptions.

The Lewin study used two different development schedules, described in table 42, to determine potential production under base and advanced technology conditions. The schedules

represent a rapid early development of the resource. For the base case, tight sands production

is 3 TCF in 1990 and rises to nearly 4 TCF in 2000,

at $3/MCF (1 977$). The advanced case contributes 4 TCF by 1985 and nearly 8 TCF in 1990 but

declines to less than 7 TCF by the year 2000. In

contrast, the NPC standard scenario at $5/MCF

(1979$) will contribute only 2 TCF by 1990 but

up to 9 TCF in the year 2000.

The NPC approach was to assume that there

are few external constraints on most of the factors affecting production. Rather than a forecast

of the “most probable” production, its supply
Ch. 8—Tight Gas ● 169

Table 42.-Projections of Annual Tight Gas Production, TCF

Assumptions 1990 2000

Lewin:

All drilling begins in 1978 and IS completed by

2003

Base case: drill probable acreage immediately, lag

drilling of possible acreage 9 years; 20 percent

DCF ROR

Advanced case.’ lag drilling of probable acreage 3

years, lag drilling of possible acreage 9 years

but complete in 15 years; 10 percent DCF ROR

NPC:

Standard scenario, phase in advanced technology,

5 percent by 1983, 100 percent by 1989 in

blanket sands; 2 years lag in Ienticular sands;

40 percent of most profitable prospects ( > 50%

DCF ROR) drilled in first 20 years; 4 years from

first drilling to initial production.

2 times standard: faster technology development

and drilling schedule,

1/2 standard.’ slower technology development and

drilling schedule

GRI:

Assume average production decline curves,

increase in numbers of wells drilled by 200 per

year.

Base case.’ begin with 100 wells in 1984 to 800 in

1988 and 10 percent to 15 percent growth

beyond 1988

Advanced case. begin with 200 wells in 1984;

increase to 800 in 1987 with 10 percent to 15

percent growth beyond 1987.

AGA:

Price and rate of return not defined; average

production decline curve similar to GRI; lower

drilling rates than NPC; slower implementation of

advanced technology

Conservative case: lower initial average production

rates to account for areas where massive

hydraulic fracturing cannot be used

Consensus case.’ modified to account for slow

technologic development and overlapping

conventional and tight definitions.

Pricea

($/MCF) Base Advanced Base Advanced

3.00 (4.70) 3.2 7,7 4.0 6.8

Price

($/MCF)

15% ROR 1/2 std Standard 2 x s t d 1/2 std Standard 2 X std

2,50 (3.35) 1.1 5.8

3.50 (4.65) 1.3 7.0

5,00 (6.70) 0.9 1.8 2,2 4.1 8,3 15.5

9.00 (12.00) 2.5 10,5

Pricea

($/MCF) Base Advanced Base Advanced

3.12 (4.20) 0.48 0.93 1.99 3.44

4.50 (6,00) 0.53 1.02 2.51 5,21

6.00 (8.00) 0.57 1,12 3.31 6.04

Conservative High Conservative High

Calculated 1.1 1.2 4.3 6.2

Consensu s — 1.2-3b

aPrice in dollars at the time of the study(1983$)

bRange includes Devonian shale

scenarios are quite deliberately structured to represent a maximum—the amount of gas that could

be produced given a concerted effort to develop

the required technology and no market restrictions 66 on field development.

The NPC study combines the resource base

and economic model to develop several scenarios for production of the tight gas resource. The

66Tha( is, producers can sell all the gas they can produce and

transport to potential markets, at the assumed wellhead price plus

transportation costs.

scenarios incorporate a development schedule

in which a certain percentage of the more profitable prospects in all basins are drilled first. Certain constraints were incorporated in the development schedule to reflect the fact that not all

the leases on the most profitable prospects will

be immediately available for drilling. Development in some areas, such as the Northern Great

Plains, is delayed due to lack of pipelines. Advanced technology is phased in according to specific schedules. Annual production rates and cumuIative additions to reserves for each scenario

38-742 0 -85 - 1 2
170 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

were calculated for various prices and rates of

return. Results of the different scenarios are

shown in table 42.

Figure 33 compares several of the NPC scenarios with the Lewin base and advanced case. The

primary difference between the two sets of estimates is the rapidity with which profitable prospects are developed in the Lewin study, and also

in the period of time between discovery and actual production from a prospect. In the NPC

study, it takes 4 years to place a well under production after drilling; in the Lewin study, production begins the year after discovery.

GRI took a slightly different approach to forecasting annual production from tight sands in the

earlier (1980) of its two analyses.67 It determined

a production decline curve representative of an

“average” well with a production life of 30 years

and specified a rate of increase in the number

of wells drilled per year. Initial production rates

and rate of drilling varied for the base and advanced case scenarios. Details are given in table

42, Its production estimates for base and advanced technology cases range from 0.48 to 1.12

TCF in 1990 and 1.99 to 6 TCF in the year 2000.

A more recent GRI production analysis68 is

based on the TGAS model of the NPC study

67. C. Sharer and j. j. Rasmussen, “Position Paper: Unconventional Natural Gas,” Gas Research Institute, Mav 1981.

‘Sj. 1. Rosenberg, F. Morra, Jr., and M. M’archl’ik, “Future Gas

Contributions From Tight Sand Reservoirs, ” 7984 Irrterrratiomi Cm

Research Conference, Sept. 10-13, 1984, Washington, DC.

Figure 33.-Annual Tight Gas Production Estimates

(wellhead gas price = $4.70/MCF, 1983$)

1980 1985 1990 1995 2000

Year

“No gas price specified.
ChI. 8—Tight Gas 1 7 1

methodology, but adopts a series of advanced

technology assumptions that are more modest

than the NPC’s. The production projections are

based on a price path rather than a constant real

price, with gas prices assumed to reach $6.20/MCF

in 2000 and $7.80/MCF in 2010 (all prices in

1982$), and assuming a 15 percent discount rate.

The model is deliberately calibrated to produce

a year 2000 base production level at around the

average of current projections by AGA and DOE,

so the value of the analysis lies in the sensitivity

analyses around the base production level (described later), and not the level itself.

The production estimates for the base and advanced technology cases range from 1,9 to 2.7

TCF in 2000 and 2.9 to 5.6 TCF in 2010. An additional set of estimates was made for a case

where no limits were set on gas demand, capital

and drill rig availability, or level of investment.

As might be expected, the production estimates

for this case are very high, 8 to 11 TCF in 2000

and 8 to 14 TCF in 2010. The investment and

drilling implications of this latter case appear

unrealistic, but the estimates give some idea

about what might be possible with an emergency

development program.

An additional estimate of future production

rates is given by the American Gas Association

(AGA),69 AGA used the NPC’s analysis as a starting point and superimposed its own assumptions.

Its initial estimate projected annual production

of 1.2 TCF in 1990 and 6.2 TCF in the year 2000.

AGA attributes these lower estimates (relative to

the NPC forecasts) to lower drilling rates and a

slower implementation of advanced technology.

A more conservative estimate, based on lower

initial production rates per well, projects 1.1 TCF

in 1990 and 4.3 TCF in 2000. No price levels are

indicated. AGA suggests that even lower annual

production (from 1.2 to 3 TCF from both tight

sands and Devonian shales) is likely due to definitional overlap between conventional and tight

reservoirs (i. e., some of the production formerly

considered to be unconventional more properly

belongs in the conventional category) and a less

optimistic outlook for the potential of advanced

————

bgArrlerlCan GaS Association, Tbe ~as ~r)f?rgy ~U~/J/Y @~~oo~:

1983-2000, October 1983.

technologies. This lower production range probably is not directly comparable to the NPC’s,

however, because the AGA definition of unconventional gas appears to exclude gas resources

not yet under development that are economically

recoverable at today’s price and technology—

resources that are included in the NPC’s tight gas

resource base. Such resources, which are in a

“grey area” between clearly conventional and

unconventional resources, probably make up at

least 100 TCF of the NPC’s recoverable resource

and play a major role in NPC’s projected production during the first few decades of tight gas development.

The time frame and extent of technological development is a major factor contributing to the

uncertainty of actual production from the tight

gas reservoirs. The production of most of the resource contained in the lower permeability formations and the Ienticular formations is strongly

dependent on advanced technology development. A slower rate of technology development

may severely limit the potential contribution of

the tight sands resource to U.S. supply in the next

20 years. For example, NPC made its scenario

projections based on immediate utilization of

base technology, and implementation of advanced technology in all blanket formations by

the year 1989 and in all Ienticular formations by

1991. Events of the last few years have indicated

that this rate of development is too optimistic.

As discussed previously, the base case technology criteria have not yet been met, especially not

in Ienticular reservoirs.

Aside from the rate at which new technology

will be developed, the advanced technology

characteristics assumed by the NPC appear to be

quite optimistic, and GRI has used more modest

assumptions. However, in reality the specification of future technologies has always been a risky

undertaking, and past efforts in other technological areas have not tended to be wildly successful.

As shown by figure 34 and by an examination

of the “base” and “advanced technology” production projections in each of the studies, the

adequacy of exploration and production technology is critical to the economics of tight gas development, and errors in projecting the future

state of technology may be translated into sub-
172 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Figure 34.—incremental Tight Gas Sands Production

Rates As a Function of R&D Advances

8

6

4

2

0

1985 1990 1995 2000 2005 2010

Years

SOURCE: Lewin & Associates, Gas Research Institute.

stantial errors in projecting future production

levels at a particular gas price.

Figure 34 shows GRI’s projected production

levels at current technology, advanced technology, and a modified advanced technology case

where the ability to produce Ienticular reservoirs

not in direct contact with the well bore has never

been achieved. Because of the time delay involved in developing and implementing new

technologies, the three cases do not diverge until the mid-1990s, but by 2000 the advanced technology case produces about 50 percent more

than the current technology case. By 2010, the

advanced case produces 100 percent more—5.6

TCF/yr v. 2.9 TCF/yr About half of the additional

production would be lost, however, if remote

lenses cannot be produced.

Another important area of uncertainty is the potential for errors in resource assessment. A number of the resource estimates for individual basins

have been questioned. Figure 35 breaks out the

NPC standard development scenario into the

contributions by each basin. In this way, the effect of delaying or otherwise constraining development of certain basins can be more easily

visualized. Significant errors in the resource

assessments for these basins might be reflected

in errors in the production estimates. However,

because operators will shift from one target to

another if the first does not meet their expectations, the effect on national production of an

overestimate of resources in a single basin may

include both an overestimate of production from

that area and a partially offsetting underestimate

of production from adjoining areas.

A significant contributor to annual production

is the group of Eastern basins. These fall in the

extrapolated portion of the resource assessment;

recoverable resource estimates for these basins

are subject to considerably greater uncertainties

than those for the appraised basins.

Another area that deserves particular attention

is the Northern Great Plains, which has been the

subject of considerable argument concerning the

magnitude of its recoverable resource. As illustrated by figure 35, the Northern Great Plains

(NGP) plays only a moderate supply role in the

NPC standard scenario. One cause of this moderate role may be that the NPC assumed that lack

of pipeline availability would significantly delay

development in this region. However, the relative development costs of the NGP’s shallow gas

resource are projected to be quite low, and a

supply analysis that assumed fewer supply restrictions would project a more extensive role for

NGP gas. Figure 36 illustrates GRI’s TGAS projection of tight gas production with and without

the NGP, with current and advanced technology.

The projection assumes a gradually rising gas

price rather than the NPC’s constant real price.

For both the present and advanced technology

cases, removal of the NGP drastically curtails total

tight gas production, especially in the short term.

For the present technology case, production only

“recovers” to about half the reference case by

the year 2010. The effect of “losing” the NGP

in the advanced technology case is less severe,

with production in 2010 about two-thirds of the

reference production.

Another potential supply constraint, the total

size of the resource, probably will not significantly

affect production rates over the next 20 years.

in fact, if development of the tight gas resource

continues to be as slow as in the last few years,

this boundary constraint is not likely to be felt

until well into the next century. it may, however,

have an impact on the long-term contribution to

supply. Comparison of the NPC and Lewin scenarios demonstrates the effect of a smaller total

resource on production. Supply from the Lewin

appraised resource will begin to decline near the
Ch. 8—Tight Gas ● 173

Figure 35.—Annual Production by Basin— NPC, $5.00/MCF (1979$), 15°/0 DCF ROR, Standard Scenario

.

D

I

Midcontinent

Rocky Mountains I

Northern Great Plains

1985 1990 1995

SOURCE National Petroleum Council.

Figure 36.— Incremental Tight Sands Gas Production

Rates With and Without the Northern Great Plains

Resource

8

6

4

2

0

1985 1990 1995 2000 2005 2010

Year

SOURCE Lewln & Associates, Gas Research Institute.

2000 2005 2010 2015

Year

year 2000, apparently due to the boundary constraints imposed by the size of the resource. In

contrast, production from the total U.S. resource

appraised by the NPC continues to increase well

into the next century and remains as a significant

source of supply until at least 2040 (NPC report,

fig. 27).

The absence of pipelines in many potential tight

sands production regions further constrains nearand mid-term development of the tight sands resource. Development of new regions has always

been something of a problem for gas development: pipeline companies cannot get approval

to build new lines without evidence of proved

reserves, whereas producers are reluctant to drill

.
174 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

and prove reserves without the presence of a

nearby line. For tight gas fields, pipelines may require evidence of larger reserves than are presently required for conventional fields, because

the tighter reservoirs produce more slowly.

In the short term, pipeline constraints will affect the pattern of development. Fields near existing pipelines will be developed first. Already

much of the new production from tight sands

fields is coming from the Southwest, which has

excess pipeline capacity. In other areas without

pipelines, despite potentially large volumes of gas

and low estimated costs of extraction, development is likely to be delayed for several years due

to lack of pipeline capacity.

Aside from technical considerations, future

tight gas production will be dependent on future

gas prices and investment discount rates. For example, figure 37 illustrates how production will

change if prices are 20 percent higher or lower

than the projected values in GRI’s analysis. The

price variation produces a production variation

in the present technology case of about 1 to 3

TCF in the year 2000, a major difference in production for a relatively modest range of gas prices.

Similarly, the range of year 2000 production projections for the advanced case will be about 2

to 4 TCF. Because future gas prices are likely to

be closely tied to unpredictable oil prices, the

chance of estimating year 2000 gas prices to within better than +/- 20 percent—and thus, estimating production to better than about +/- 1 TCF—

seems remote.

Figure 38 shows the effect of changes in discount rate on production. Discount rate is essentially a proxy for the perceived risk associated

with an investment. The range of discount rates—

10 to 20 percent–displayed in the figure seems

a reasonable measure of uncertainty for the present technology case because the profile of the

potential developers, the development climate,

and the physical uncertainty associated with development expenditures are not well understood

at this time.

As illustrated by the figure, discount rate is a

crucial variable over the entire course of development and for both base and advanced technology. For example, in the year 2000, the 10

Figure 37.—incremental Tight Sands Gas Production

Rates as a Function of Gas Price

8

0

1985 1990 1995 2000 2005 2010

Year

SOURCE: Lewin & Associates, Gas Research Institute.

Figure 38.—incremental Tight Sands Gas Production

Rates As a Function of Discount Rate

I

Present I

1985 1990 1995 2000 2005 2010

Year

SOURCE: Lewin & Associates, Gas Research Institute.

point spread in discount rate introduces an uncertainty of about +/- 50 percent in the expected production for the present technology case and

+ 100 percent, –5o percent for the advanced

technology case.

In the NPC and Lewin reports, and possibly in

the GRI and AGA reports as well, little or no consideration was given to the possibility that market problems might constrain the future production of tight gas. in the past few years, however,

declines in gas usage and the widely perceived

optimistic prospects for conventional gas supply

and price stability have altered even the enthusiasts’ perception of the near-term future of tight

gas and other forms of unconventional gas, It is

generally considered improbable that massive financial resources will be channeled into development of very low permeability formations if

ample prospects of conventional gas are avail-
.

Ch. 8—Tight Gas ● 175

able. Consequently, many supporters of the NPC

study, while remaining convinced of the accuracy

of the gas-in-place and recoverable resource estimates, no longer consider the high production

projections to be very likely. To a certain extent,

more pessimistic projections of future tight gas

production can be self-fulfilling because their

acceptance is likely to discourage the research

necessary for a major expansion of tight gas production. on the other hand, at least a moderate

rate of improvement in tight gas exploration and

production expertise and technology will continue regardless of markets, because of continued

research on oil production from tight formations

and the momentum of existing research programs

and tight gas development.

OTA believes that future tight gas development

will be closely linked to the availability of conventional gas resources. As discussed in Part I of

this report, we do not believe that the year 2000

supply of conventional gas can be projected without a large error band. Consequently, we are

skeptical of our ability to reliably project tight gas

production to the year 2000 except on a “what

if . . .“ basis.

On an optimistic basis, we do believe that the

year 2000 incremental production of tight gas70

zOThat is, over and above the 1 TCF/yr or so of tight gas produced

today that is generally included in “conventional” production

figures.

can reach 3 or 4 TCF/yr, or perhaps even somewhat higher, if the present gas bubble ends within

a year or two, markets for gas remain firm and

real prices increase steadily for the remainder of

the century, and the industry is confident of the

long-term marketability of tight gas and thus is

willing to make the necessary investments in

R&D. Such a future is consistent with the pessimistic end of OTA’s projected range of 9 to 19

TCF/yr for year 2000 production of conventional

gas.

On the other hand, there are plausible circumstances that could stifle future tight gas production, including high conventional gas production

and stable or declining real prices, low future demand for gas, or the loss of industry confidence

in future gas marketability. A pessimistic scenario

might involve year 2000 incremental production

of 1 to 2 TCF/yr. Beyond 2000, the size of the

recoverable resource, as affected particularly by

production technology and the availability of gas

in the Ienticular basins and the Northern Great

Plains, will play a critical role in determining the

magnitude of production. In addition, the production rate will always be extremely sensitive

to the introduction of any new technological advances affecting production costs and recovery

efficiency.
Chapter 9

Gas From Devonian Shales
Contents

Page

introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... ... ... ..179

Characteristics of the Devonian Shale Resource . . . . . . . . . . . . . . . .. ... ... ...179

Gas-In-Place Resource Base . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..182

Methodologies and Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...182

Estimate Comparison and Uncertainties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .186

Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .........................187

Fracturing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...........................187

Deviated and Directional Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. ....189

Exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........................189

Recoverable Resources and Production Potential . ........................190

Methodologies and Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .191

Estimates Comparison and Uncertainties. ,.. . ..........................199

Annual Production Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ... ... ....201

TABLES

Table No. Page

43.

44.

45.

46.

47.

48

49.

50.

51.

52.

53.

54.

55.

Devonian Shale Resource Base Estimates (TCF) . .......................182

Equation Parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........184

Estimates of ln-Place Natural Gas Resources in the Devonian

Shale of the Appalachian Basin . . . . . . . . . . . . . . .......................184

Devonian Shale Recoverable Resource Estimates (TCF) Appalachian Basin .191

Summary of Major Differences Between Lewin Base and Advanced

Cases in Devonian Shale Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 193

Lewin &Associates: Results of Economic Analysis, Summary Table . ......194

Summary of Producible Gas Estimates, Appalachian Basin . . . . . . . . . . .. ...195

Effect of Spacing on the Devonian Shale Recoverable Resource . . . . . . . ...196

Results of Lewin Assessment of Technically Recoverable Gas in Ohio,

By Stimulation Method After 40 Years . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .198

Results of Lewin Assessment of Technically Recoverable Gas in

West Virginia, by Stimulation Method After 40 Years... . ...............198

Comparison of Estimated Appalachian Devonian Shale Resources

Recoverable With Borehole Shooting, Well Spacing of 150 to 160 Acres ..200

Lewin &Associates Results for Annual production Estimates . ............202

Potential Incremental Supply of Devonian Shale Gas in the

Appalachian Basin: NPC-High Growth Drilling Schedule. . ..............200

FIGURES

Figure No. Page

39. Primary Area of Devonian Shale Gas Potential . .......................180

40. Averaged Production Decline Curves for 50 Devonian Shale Gas Wells ...181

41. Shale Gas Potential in the Appalachian Basin . ........................185

42. Distribution of Devonian Shale Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...187
Chapter 9

Gas From Devonian Shales

INTRODUCTION

Although it is often presented as a gas source

of the future, Devonian shale gas actually has a

long production history: the first Devonian shale

gas well was drilled in 1821, near Fredonia, NY,

and “modest” production from Devonian shale

wells began around the 1920s and has continued

to the present.1 Cumulative production from the

shales during all the years of production has been

less than 3 trillion cubic feet (TCF), most from the

‘Potential Gas Agency, “Potential Gas Resources From Nonconventional Sources, ” Potential Supply of Natural Gas in the

United States, May 1981.

Big Sandy Field in Kentucky and adjacent West

Virginia, and current production is only about 0.1

TCF/yr.

Because of its history, Devonian shale gas may

be thought of as a “conventional” gas resource.

It is also an unconventional gas resource, however, because of its complex geology and because

advanced exploration and extraction technologies and higher prices may be able to transform

it into an important component of U.S. gas supply

from its current status as a very limited, if still

locally important, gas source.

CHARACTERISTICS OF THE DEVONIAN SHALE RESOURCE

Devonian shale gas is defined as natural gas

produced from the fractures, pore spaces, and

physical matrix2 of shales deposited during the

Devonian period of geologic time. As illustrated

in figure 39, Devonian shales occur predominantly in the Appalachian, Illinois, and Michigan

basins. The shales formed approximately 350 million years ago in a shallow sea that covered the

eastern half of what now constitutes the continental United States. organic-rich muds and silts

were deposited in the sea and subsequently

buried by younger sediments. The high pressures

and temperatures that accompanied burial of the

sediments resulted in the formation of natural gas

from the organic material.

The gas content of the shales is proportional

to the amount of organic material, and more precisely the organic carbon, present in the rock.

The organic material occurs as microscopically

thin layers, alternating with mineral layers. The

actual physical color of the shales is indicative

of their organic content: black and brown shales

generally have higher organic contents and therefore more gas than gray shales.

‘That is, a portion of the gas is adsorbed, or bound, to the actual

physical structure of the shale.

Other determinants of the gas content are the

origin of the organic material, that is, the type of

organisms (algae, pollen, woody plants, etc.) that

formed the sedimentary layers which became the

shale, and the physical conditions, especially the

temperature, to which the organic material was

exposed. For example, blooms of algae appear

to be the major source of Devonion shale gas,

whereas terrestrial organisms are less promising

sources of gas.3 And temperature conditions between 60° C (140° F) and 150° C (3020 F) are

optimal for the formation of petroleum (oil and

gas).4

Unlike accumulations of natural gas that are

considered conventional, and unlike tight sands

gas, Devonian shale gas did not migrate from

source rocks to reservoir rocks and accumulate

in a trap. Instead, the low permeability of the

Devonian shale prohibited most of the gas from

escaping. As such, the shale is effectively the

source, reservoir rock and trap for the gas. However, some gas originally present in the shale may

3

R. A. Struble, Evaluation ot’ the Devonian Shale Prospects in the

Eastern United States, U.S. Department of Energy Report

DOE/MC/19143-1305, undated.

4j. M. Hunt, Petroleum Geochemistry and Geology (New York:

Freeman, 1979), p. 617. Cited in R. A. Struble, op. cit.

179
180 U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Figure 39.— Primary Area of Devonian Shale Gas Potential

SOURCE: Johnston & Associates, OTA Contractor,

have migrated out of the formation, escaping to

the atmosphere or forming conventional gas accumulations in nearby sandstones.

The reservoir characteristics of Devonian shale

differ substantially from those of conventional

reservoirs. Porosities range from 8 to 30 percent

in conventional reservoirs; Devonian shale matrix porosities are generally 1 to 2 percent. The

permeability of the shales is also significantly

lower. Conventional reservoirs have permeabilities in the range of 1 to 2,000 millidarcies (red),

whereas Devonian shale matrix permeabilities

generally range from 10-5 to 10-6 md. Even

though portions of the shale contain natural fractures, fracture permeabilities tend to be low, rang-
Ch. 9—Gas From Devonian Shale . 181

ing from about 0.001 to 1 md; in most cases, permeabilities are less than about 0.1 md. s As

suggested by these statistics, gas flows much less

readily from most Devonian shale reservoirs than

from conventional sandstone reservoirs.

The natural fractures in the shale, which most

often occur in a vertical pattern, are critical to

successful production. Such production generally requires intersecting these fractures to utilize

the increase in overall permeability that they promote. Because the shale fracture systems in the

great bulk of the Appalachian Basin are still quite

tight, however, achieving high recovery efficiencies generally also requires inducing new, propped

fractures in addition to connecting with the natural system. Also, aside from their “tightness,”

the shale fracture systems tend to be somewhat

lined up rather than being random in direction–a

property called “anisotropy.” Optimum fracture

design and well spacing are affected by this property, e.g., a rectangular well spacing pattern

aligned with the direction of anisotropy will increase gas recovery over the usual square

pattern. 6

Typically, production from Devonian shale

wells is at first relatively high, followed by a steady

decline to a base level which can remain constant for over 50 years. Four production curves

representing the averaged production of multiple wells are included in figure 40. The shape of

the production curves probably is a result of the

multiple ways in which the gas occurs in the rock:

in pore spaces, in the fracture system and adsorbed to the shale matrix. The initial production

is composed primarily of the free gas contained

in the fracture network immediately connected

to the wellbore and that pore gas which readily

migrates to the well bore. The base level then represents the rate at which the gas diffuses through

and desorbs from the shale matrix. However, the

relative contribution of each of the three distinct

“sources” of gas in the shale is not completely

‘V. A. Kuuskraa and D. E. Wicks, “Devonian Shale Gas Production Mechanisms, ” 1984 International Gas Research Conference;

V. A. Kuuskraa, et al., Technically Recoverable Devonian Shale Gas

in Ohio, Lewin & Associates Report for Morgantown Energy Technology Center, July 1982.

6V. A. Kuuskraa and D, E. Wicks, “Devonian Shale Gas Production Mechanisms,” 1984 International Gas Research Conference.

Figure 40.—Averaged Production Decline Curves for

understood, and there are alternative interpretations of the precise composition of the base production level. One interpretation is that the base

level is primarily adsorbed gas that is being released by the shale matrix as the pressure drops.

An alternative explanation is that the base level

gas is primarily gas from other gas-bearing intervals that are connected to the primary (stimulated) interval by the vertical fracture network in

the shale.

Deciphering the relative roles of these two

mechanisms is critical to estimating the recoverable resource. At one extreme, if the base level

of production is mostly adsorbed gas and there

is little communication between gas-bearing intervals, then the intervals that are not currently

being stimulated may be available for production

in the future. At the other extreme, if there is little resorption of gas and the base level is due

to vertical communication between intervals,

then the number of targets for economic production is drastically reduced and the recoverable

resource will be far less. In the latter case, the
182 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

major part of the gas-in-place (Kuuskraa and The current available data appear to support the

Wicks estimate that adsorbed gas represents over “resorption, little vertical communication” inter80 percent of the total7

) will not be available for pretation, but these data are limited to a very

production with currently foreseen technology. small geographical area.8

BCharles Komar, Morgantown Energy Technology Center, per7Kuuskraa and Wicks, op. cit. sonal communication, 1984.

GAS= IN-PLACE RESOURCE BASE

The Devonian shale resource is becoming increasingly well characterized as a result of recent

efforts to better understand the geological characteristics of the resource and its size. Work performed as part of the Department of Energy’s

(DOE) Eastern Gas Shales Project (EGSP) has provided substantive geological and geochemical

data. 9

Methodologies and Results

As illustrated in table 43, several organizations

have estimated the size of the Devonian shale resource base. The three most recent estimates of

the in-place resource were made by the National

gThe results of the project are summarized in a report by R. A.

Struble, Evaluation of the Devonian Shale Prospects in the Eastern

United States, U.S. Department of Energy Report DOE/MC/19143-

1305, undated. This report provides a comprehensive review of

the “state-of-the-art” of Devonian shale resource analysis up to

about 1982.

petroleum Council (NPC) in June 1980 and the

U.S. Geological Survey (USGS) and the Mound

Facility (operated by Monsanto Research Corp.)

in 1982. The NPC study evaluated the Devonian

shale resource in the three shale basins, whereas

the other two restricted their estimates to the Appalachian Basin.

National Petroleum Council10

The NPC estimated the gas-in-place resource

for each of the three major basins. The primary

variables in the in-place resource calculation

were shale thickness, areal extent and gas content, with gas content assumed to be uniform

throughout each basin. These parameters were

established differently for each basin, depending

on the type and quantity of information available.

locational Petroleum council, “Unconventional Ndtural GasDevonian Shales,” June 1980.

Table 43.-Devonian Shale Resource Base Estimates (TCF)

Organization Year Basin evaluated Estimate

National Petroleum Councila 

. . . . . . . . . . . . . . . 1980 Appalachian . . . . . . . . . . . . . . . . 225 to 1,861 (125 to 1040b

)

Michigan . . . . . . . . . . . . . . . . . . 76

Illinois. . . . . . . . . . . . . . . . . . . . . 86

U.S. Geological Surveyc . . . . . . . . . . . . . . . . . . . 1982 Appalachian . . . . . . . . . . . . . . . . 577 to 1,131

Mound Facilityd 

. . . . . . . . . . . . . . . . . . . . . . . . . . 1982 Appalachian . . . . . . . . . . . . . . . . 2,579 (l,440b

)

Lewin & Associatese

. . . . . . . . . . . . . . . . . . . . . . 1980 Appalachian . . . . . . . . . . . . . . . . 400 to 2,000

Federal Energy Regulatory Commissionf 

. . . . 1978 Appalachian . . . . . . . . . . . . . . . . 285

Smithg . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1978 Appalachian 206 to 903

aNational Petroleum Council, Unconvenyional Gas Sources, Tight Gas Reservoirs Part 1, December 1980.

bConsidering “drillable” area only.

CR.R. Charpentier et al., Estimates of Unconventional Natural Gas Resources of the Devonian Shale Of the Appalachian Basin, USGS Open-File Report 82-474, 1982.

dR, E, Zielinski and R D, Mclver, Resource and Exploration Assessment of the oiI and Gas Potential in the Devonian shales of the Appalachian Basin, DOE/DP/0053-1 125,

undated.

eV. A. Kuuskraa and R. F. Meyer, “Review of World Resources of Unconventional Gas,” in IIASA Conference on Conventional and Unconventional World Natural Gas

Resources, Laxenburg, Austria, June 30-July 4, 1980.

fU.S., Department of Energy, Nonconventional Natural Gas Resources, Report DOE/FERC-0010, 1978.

gE. C. Smith, “A Practical Approach to Evaluating Shale Hydrocarbon Potential,” in Second Eastern Shales Symposium, Vol. II, U.S. Department of Energy, Report

METC/SP-7816, 1978, pp. 73-87.

SOURCE: Office of Technology Assessment.
Ch. 9—Gas From Devonian Shale ● 183

In each basin, the black and gray shale thicknesses were multiplied by their respective gas

contents and their areal extents to arrive at the

gas-in-place estimate for the basin.

In the Appalachian Basin, the gas-bearing zone

includes the gray and black shale units that

overlie the Onandaga limestone and underlie the

Berea sandstone. The thickness of the black

shales was determined in two ways: first, by

gamma-ray well log data which detects the high

radioactivity content characteristic of organic-rich

shales; second, by thicknesses determined visually from core sample color. The two black shale

thickness calculations yield substantially different

results, which in turn yield very different gas-inplace estimates. The gas content of the shales was

determined through off-gassing data from rock

core samples.11 Values of 0.6 and 0.1 cubic feet

of gas per cubic feet of Appalachian shale were

obtained for black and gray shales, respectively.

The areal extent of the Appalachian shale was

determined to be 111,100 square miles.

The gas-bearing unit in the Michigan Basin is

the Antrim shale, which extends over 35,400

square miles and contains both black and grey

shales. The thickness of the Antrim was determined strictly by well logs and is poorly defined

where the Antrim grades into the barren Ellsworth

shale in the western portion of the basin. Also,

there were no core samples available for offgassing experiments to determine the quantity of

gas present in the unit. In the absence of these

data, the gas content of the Michigan Basin shales

were assumed to be the same as those of the Appalachian Basin on the basis of similarities in the

well production data for the two basins.

The New Albany shale group, covering 28,150

square miles, is the gas-bearing unit in the Illinois

Basin. Neither gamma-ray well log data nor core

sample data were available to determine the

thickness of the units, and therefore the black and

gray shale thicknesses could not be differentiated.

The thickness of the entire sequence was determined from USGS maps and used in a simple

volumetric resource calculation. off-gassing data

from cores were available to determine the gas

.-.——

1 Ioff.gassing measures the amount of gas that desorbs from a

known volume of core over a specific period of time.

content. The thickness of the sampled units in

proportion to the total group thickness was used

to establish a weighted average of 0.62 cubic feet

of gas per cubic foot of shale for the entire New

Albany group.

The results of the NPC study suggest that estimates of the quantity of gas present in the Appalachian Basin are sensitive to the assumed

thickness of the black shale and to the inclusion

or exclusion of the lower quality gray shales.

Based on thicknesses determined by gamma-ray

logs, and including only the black shales, the gasin-place is estimated to be 225 TCF. Based on

black shale thickness determined visually from

USGS samples and including the gray shales,

1,861 TCF is estimated to be present. (The range

for the black shales only is 225 to 1,102 TCF.) If

areas that are not drillable12 are excluded, the gasin-place estimate is reduced to 125 and 1,040 TCF

for the log and sample thicknesses, respectively,

The gas-in-place estimates for the Michigan and

Illinois basins are 76 and 86 TCF, respectively,

but are more uncertain because of the lack of

data.

U.S. Geological Survey13

The USGS estimate of Devonian shale gas in

the Appalachian Basin recognizes three categories of shale gas: macrofracture gas, micropore

gas, and that gas which is adsorbed, or attached,

to the clay matrix. Unlike the early Lewin & Associates study (1 978-79), the USGS attributes only

a small amount of the total volume of gas-in-place

to macrofractures; it assumes that most of the gas

is in micropores or bound to the organic matter

in the shale matrix.

The Appalachian Plateau province and a small

segment of the Valley and Ridge province were

divided into 19 areas, termed plays. The characteristics of each play were described in terms of

physical location, unit names, thickness, organic

content, maturation level and type of hydrocarbon present, tectonic or structural attributes, and,

subsequently, a brief description of the producI zBeCaUSe of difficult terrain, presence of buildings and other development, designation of the land as protected parkland, etc.

1 JR. R. Charpentier, et al,, Estimates of Unconventional Natural

Gas Resources of the Devonian Shale of the Appalachian Basin, ”

U.S. Geological Survey Open-File Report 82-474 (preliminary), 1982,
184 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

tion potential of the play. The volume of gas for

each of the 19 different areas was calculated using

Equation 1, below:

The parameters used in the equation are explained in table 44. The volume of gas for each

area was summed to obtain a total basin estimate.

The analysis explicitly recognizes two severe

data problems:

● limited quantity of data for most of the

assessed area, and

● large sampling errors and differences in interpretation.

Because of the limited quantity and quality of

data, a range rather than a point estimate of the

gas present was developed. The Monte Carlo

method of estimation was employed to acquire

the range.14

——— lqln using a Monte Carlo method, appropriate variables in the

equation are specified by a probability distribution rather than by

a point estimate. Then, the equation is “solved” for the dependent variable–in this case, gas-in-place–a large number of times

by randomly sampling the probability distributions. In this way, a

probability distribution is obtained for the dependent variable (gasin-place). The “solution” to the equation can either be expressed

by the probability distribution itself, by its mean or median, or perhaps by a range defined by some probability that the actual value

is within its borders (e. g., “there is an 80 percent probability that

the correct value is in the range X to Y“).

Table 44.—Equation Parameters

Symbol Meaning

G . gas-in-place

0 rnacro “ : : . average macrofracture porosity as a fraction

of total volume

TH s . . . . . . . average thickness of organic-rich shales

Pr . . . . . . . . . average reservoir pressure (psi)

Ps . . . . . . . . standard pressure (14.73 psi)

Tr . . . . . . . . . average reservoir temperature (oR)

Ts . . . . . . . . standard temperature (5200R)

z . gas deviation factor (0.9)

Area” ; ; ; ; . area (square miles)

0 micro . . . . average content of microporosity gas at

standard temperature and pressure as a

fraction of rock volume

SOR . . . . . . average volume ratio of adsorbed gas to

inorganic content

ORG . . . . . . average organic content as fraction of rock

volume

SOURCE U S. Geological Survey, “Estimates of the Unconventional Natural Gas

Resources of the Devon Ian Shale of the Appalachian Basin, ” 1982

The data used were acquired from a variety of

sources. The configuration of the gas shales was

taken from geologic cross sections, isopachs

(thickness maps), and other geological maps compiled by the USGS. Maps were also used to estimate thickness, organic content and average

depths, which when combined with temperature

and pressure gradients yielded average reservoir

pressures and temperatures. Micropore gas estimates were achieved by plotting gas content—

acquired from off-gassing data from canned core

samples—against the amount of organic matter

in the sample. The slope of the resultant curve

represents the ratio of adsorbed gas to organic

matter. The intercept (gas content at the point

where organic matter is zero) represents the

micropore gas content.

The results of the USGS study are compiled in

table 45. The 95th fractile (F95is a low estimate

and signifies that there is a 95 percent chance that

there is more than 577.1 TCF present. The 5th

Table 45.—Estimates of In-Place Natural Gas

Resources in the Devonial Shale of

the Appalachian Basin

Natural gas resources

(trillions of cubic feet)

Low High

Play F9 5

a

F5

a Mean

1. North-Central Ohio . . . . . . . 17.9 34.2

2. Western Lake Erie . . . . . . . 21.7 31.3

3. Eastern Lake Erie . . . . . . . . 2.1 3.3

4. Plateau Ohio , . . . . . . . . . . . 44.4 76.2

5. Eastern Ohio . . . . . . . . . . . . 35.2 55.1

6. Western Penn-York. . . . . . . 20.4 28.2

7. Southern Ohio Valley. . . . . 19.7 36.2

8. Western Rome Trough. . . . 38.0 74.0

9. Tug Fork . . . . . . . . . . . . . . . 13.7 25.9

10, Pine Mountain . . . . . . . . . . . 10.7 18.7

11. Plateau Virginia . . . . . . . . . 3.9 10.2

12, Pittsburgh Basin . . . . . . . . . 76.8 129.9

13. Eastern Rome Trough . . . . 70.7 132.5

14. New River . . . . . . . . . . . . . . 38.5 91.7

15. Portage Escarpment . . . . . 8.5 21.3

16. Cattaraugus Valley . . . . . . . 10.4 23.2

17. Penn-York Plateau . . . . . . . 98.1 195.2

18. Western Susquehanna. . . . 24.1 67.7

19. Catskill . . . . . . . . . . . . . . . . . 22.1 75.8

25,9

26.5

2.7

59.9

44.7

24.3

27.7

56.0

19.7

14.6

7.1

102.1

100.3

63.1

14.6

16.6

146.0

44.9

47.6

Entire basin . . . . . . . . . . . 577.1 1,130.9 844.2

NOTE: All tabulated values were rounded from original numbers. Therefore, totals

may not be precisely additive.

aF95 denotes the 95th fractile; the probability of more than the amount F95 is 95

percent. F5 is defined similarly. Because of dependency between plays, these

fractiles (unlike those in many other studies) are additive.

SOURCE U.S. Geological Survey, “Estimates of the Unconventional Natural Gas

Resources of the Devonian Shale of the Appalachian Basin, ” 1982
Ch. 9—Gas From Devonian Shale ● 185

fractile (F5 is a high estimate and indicates that

there is only a 5 percent chance of there being

more than 1,130.8 TCF present.15 The mean estimate is 844.2 TCF. Although the USGS did not

estimate recoverability, it compiled a map illustrating shale gas potential (fig. 41) which qualitatively indicates the potential for recovery in each

area based on gas-in-place and the presence of

natural fracture systems.

The Mound Facility16

The Mound study incorporates extensive geochemical data into its volumetric analysis of the

1 Sconseq Uently, there is a 90 percent probabi Iity that the gas-inplace is within the range 577.1 to 1,130.8 TCF.

IfJR, E. Zielinski and R. D. Mclver, “Resource and Exploration

Assessment of Oil and Gas Potential in the Devonian Gas Shales

of the Appalachian Basin, ” 1982.

gas-in-place in the Appalachian Basin. Organic

geochemical analyses were performed on over

2,000 individual core samples and on an additional several hundred well cuttings to evaluate

the quality of the shale units as sources of natural gas and other hydrocarbons. In particular, the

analyses focused on three primary determinants

of gas content: the quantity of organic carbon

present, its origin (i.e., the nature of the organic

material that provided the carbon, e.g., spores,

pollen, herbaceous plants, algae, etc.), and its

thermal maturity .17

1 Thermal maturity is the extent to which the organic matter In

the rocks has been “cracked” by heat. Cracking is the process by

which long hydrocarbon chains are broken to form simpler

molecules such as those comprising methane gas.

Figure 41 .—Shale Gas Potential in the Appalachian Basin

SOURCE USGS, “Estimates of Unconventional Natural Gas Resources of the Devonian Shale of the Appalachian Basin, ” 1982

38-742 0 -85 - 1 3
186 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Several general conclusions were formulated

about the resource potential of the Appalachian

Basin. The most important conclusion is that the

Devonian shales are exceptionally rich source

rocks; were it not for their low porosity and

permeability, the shales would represent “one

of the greatest oil- and gas-producing provinces

of the world.”18B Other conclusions point to the

nonuniformity of the resource and establish

where the generally rich nature of the source

rocks may not apply. For example, the quantity

of organic material in the basin decreased to the

east. The organic-rich rocks in the extreme northwestern and western portion of the basin had

high potential for hydrocarbon development, but

they were only slightly thermally altered and

never reached their full gas-bearing potential. In

the deeper portions of the basin, too much heat

was generated, thereby lessening the potential

for finding hydrocarbons.

The gas-in-place analysis differed from the other

estimates in the way in which the gas content was

determined. Mound felt that a large portion of

the gas escaped during the process of obtaining

the core and before the core could be sealed in

the gas-tight canister, To improve the accuracy

of the measurement, Mound developed a controlled off-gassing experiment where the rate of

gas release from the core is measured. Data from

these experiments were used in combination with

other geologic and geochemical characteristics

of the formations to develop equations which

determined the “indigenous,” or original, gas

contents of the rock. The methodology was

verified by the use of a pressurized core barrel,

which extracts the core under in-situ pressure,

thereby limiting premature gas release. Mound

thus concluded that the revised values more accurately reflected the quantity of gas originally

present in the rock.

The gas-in-place estimates were determined for

each of 17 separate stratigraphic intervals, or

lall. E. i!ielirlski and R. D. Mclver, ‘‘Synthesis of organic

Geochemical Data From the Eastern Gas Shales,” SPE/DOE 10793,

in Proceedings of the Unconventional Gas Recovery Symposium,

May 1618, 1982, Pittsburgh, PA.

units, in the Appalachian Basin by first combining the indigenous gas contents (MCF/acre-foot)

with the thicknesses of the gas-bearing shale to

provide the areal distribution of the total gas in

each unit. The data were contoured, as illustrated

in figure 42. Next, the acreage contained within

each contour area was integrated, multiplied by

the appropriate gas areal density (MCF/acre), and

summed to yield the total gas-in-place for the

unit. This methodology resulted in a gas-in-place

estimate for the 17 units composing the Appalachian Basin of 2,579 TCF.

Estimate Comparison and Uncertainties

The methodologies used by NPC, USGS, and

Mound to determine the gas-in-place are all

volumetric estimates based on multiplying gas

content, shale thickness, and areal extent, but

they differ substantially in their computation

methods and input data. The major difference appears to be in the computation of gas content.

NPC used a basin-wide average based on offgassing data available at the time. Both the

Mound and USGS analyses use a more sophisticated, disaggregate approach, with USGS calculating separately the macrofracture, microporosity, and adsorbed (bound) gas for 19 areas

in the Appalachian Basin, and Mound determining gas contents for 17 stratigraphic units in the

basin using equations based on geochemical

analysis, and contouring and integrating the

results across the basin. Both the USGS and

Mound estimates had access to new off-gassing

data developed by the Eastern Gas Shales Project. The Mound approach is the most optimistic

of the three because it incorporates a calculation

of gas lost in obtaining and measuring the core

samples, a factor not considered by the NPC and

apparently not considered significant by the

USGS.

In OTA’s judgment, the physical evidence cited

and calculations made in the Mound report appear plausible; the Mound estimate of 2,579 TCF

gas-in-place (1,440 TCF in “drillable” areas)

seems a reasonable estimate given the available

data.
Ch. 9—Gas From Devonian Shale ● 187

Figure 42.— Distribution of Devonian Shale Gas

[

MCF Gas/Acre

100 )

I

.“

● TENN-9

o

-

0

Stratigraphic interval: early marcellus time

SOURCE: Zielinskl and Mclver, 1982,

TECHNOLOGY

Fracturing

Because of the extremely low permeability of

the shales, production of Devonian shale gas

depends on exploiting the natural fracture network in the rock and on enhancing gas flow by

artificially stimulating the well. Over 90 percent

of all Devonian wells require stimulation in order to yield gas in commercial quantities, and

even stimulated wells will not be successful unless

there is already a well-developed natural fracture

network.

For most of the Devonian shale’s production

history, wells were stimulated by filling large portions of the wellbore with explosives and allowing the detonation to shatter the rock surrounding the well. This basic method was first used in

1865 and is still in use. It generally is considered

less of a “fracturing” method than simply as a
— ——

188 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

means to overcome the formation damage caused

by drilling in the shales. (Its primary structural effect is to fragment the rock immediately surrounding the well bore.)

As in the tight sands, hydraulic fracturing is becoming increasingly used today in the shales. The

fractures being created in the shale formations

are small, however, not the massive 1,000-ft fractures becoming more popular in the Western

tight sands. They also generally carry less proppant than in the sands. The shales are extremely

sensitive to formation damage during fracturing,

especially because of the presence of water-sensitive clays in the shale that can be dislodged by

the fracturing fluids and plug pores and fractures.

Although formation damage is a problem with

tight sands and coal seams also, Devonian shales

may be the most sensitive. Devonian shales have,

as a consequence, served as a testing ground for

a number of new fracturing fluids.

Many of the fluids developed to minimize formation damage are foamed, using a gas phase

to reduce the amount of water required. Foamed

fluids are gas-in-water emulsions, where the surface tension of the bubbles holds the proppant–

particles that become wedged in the fractures and

hold them open–in suspension. Nitrogen (N2

is the most common gas used. Properties that

make foam suitable for the Devonian shale include low volumes of water, high efficiency in

creating fractures, high proppant-carrying capacity, low friction during pumping, and sufficient

energy within the gas phase to allow recovery of

most of the fluid without pumping. By 1980-81,

foam technology had advanced so rapidly that

it dominated fracturing in the Devonian shales.

Pure nitrogen has also been used as a fracturing fluid. It is not an efficient fracture fluid and

can only be used to fracture small depth intervals of 10 ft or s0.

19 In addition, it is not an effective carrier of proppants, and consequently is effective only at shallow depths where the fractures

are less likely to close. However, nitrogen does

not adversely affect the formation and it has proven very effective in increasing gas flow. As a result, nitrogen fracturing quickly became the preferred method for many production situations.

Because of the newness of this type of treatment

and its relative lack of propping effectiveness, the

ability of nitrogen fracturing to maintain production levels over the long-term is uncertain.

Current trends in fracturing technology are centered on the developing of fluids that are both

nondamaging, like nitrogen, and can carry proppants more effectively. possibilities include:

●

●

●

●

Stabilized foam.–Although similar to the

original foams, water has been reduced from

25 to 10 percent, and proppant-carrying capability is enhanced by a gelling agent that

stiffens the foam. This is a high cost method

that has been used only sparingly.

Liquid carbon dioxide.–This method has the

ability to transport proppants. As the liquid

C02 warms, it reverts to the gas phase and

easily flows back out of the hole with minimal damage to the formation. Liquid CO2

fracturing is a relatively expensive process

and somewhat more dangerous to use than

foamed fluids. In addition, the casing and

pumping materials must be capable of

withstanding very low temperatures.

Shale oil.—This method combines a nitrogen-driven fracture with the subsequent injection of shale oil—obtained from previous

drilling–as a proppant-carrying agent to prevent fracture closure.

Water-based nonreactive solvents.–These

solvents can be used either after a fracture

to clean the formation or as the fluid base

of a stabilized foam fracturing treatment. This

system is still experimental.

Finally, producers have attempted the use of

radically improved versions of the original explosive fracturing used since the 1800s. In tailored

pulse loading, a propellant charge is ignited to

pressurize the wellbore at a much slower rate

than is achieved with conventional explosives.20

The loading rate, or rate at which the energy

stored in the propellant is released, can be controlled to create different types of fractures. For

lqFor example, a nitrogen fracture might affect only the reservoir rock between 900 and 910 ft in depth.

20J. W. Crafton, “Fracturing Technologies for Gas Recovery From

Tight Sands, ” OTA contractor report, September 1983.
Ch. 9—Gas From Devonian Shale ● 189

example, at intermediate loading rates, multiple

fractures form radially around the well bore.21 At

slow rates, fractures form in an analogous manner to hydraulic fractures, directionally controlled

by the regional stress field.

This technique has only been used on a small

scale for prefracturing tests.22 However, it is

thought to have significant potential for use on

a larger scale, especially because it causes little

formation damage. Commercial application in the

Devonian shales may occur in the near future.

The record of success of well stimulations in

Devonian shales is mixed. Although new stimulation technologies have increased gas production

from a number of wells, many have not benefited from stimulation and the specific reasons for

their lack of success are not well understood.

One problem is the local variability and unpredictability of fractured zones. Wells offset short

distances from producing wells may not intersect

a productive fracture system.23 Improved technologies or exploration strategies to locate and

characterize fracture systems are critical to economic development of Devonian shales.

Another problem is the difficulty in extrapolating successful stimulation techniques from one

site to another. Although some producers have

been quick to try the newest in technologies, no

one has yet established criteria for choosing tailored pulse loading over nitrogen or perhaps liquid C02 injection. Most stimulations appear to

be conducted on a trial-and-error basis and inadequate records are kept to determine the reasons for success or failure of a particular

technique.

A third problem in successful Devonian shale

gas production is accurately determining the pay

interval. Because many wells do not have significant gas shows prior to stimulation, it is difficult

.———

zlThe radial fractures possible with tailored pulse loading may

have special potential in areas where the natural fracture systems

in the shale display strong directional tendencies. Radial fractures

may outperform long hydraulic fractures when these tendencies

(permeability anlsotropies) are substantial (Kuuskraa and Wicks,

1984, op. cit.).

Zzjohnston & Associates, inc., “The Status and Future of Production Technologies for Gas Recovery From Devonian Shales, ” OTA

contractor report, 1983.

231 bid,

to determine the interval within the shale sequence which is most likely to contain recoverable gas. Consequently, fractures may not be

properly located to optimize production.

Finally, no technology now exists or is being

considered to produce gas from those portions

of the Devonian shales where the natural fracture system is not well developed. This severely

limits the overall production potential of the resource.

Deviated and Directional Drilling

The only other technology that currently has

any potential for increasing production in unconventional reservoirs is one that allows drilling

wells that either intersect more of the reservoir

rock or intersect more of the natural fracture system. Thus, if reservoirs lie in an essentially

horizontal plane and natural fracture systems in

a more or less vertical plane, a well drilled at

some angle from the vertical would intersect

more gas-productive natural fractures.

Directional drilling has frequently been suggested as a technology applicable to Devonian

shale gas production .24 Production requires intersection of natural fractures and most of these

fracture systems are vertical. The major drawback

is the problem of formation damage. A drill bit

drilling at an angle from the vertical encounters

increased frictional resistance and, if drilling in

a fractured formation, runs a greater risk of having the wellbore collapse. Drilling muds are

needed to reduce friction and hold the hole

open; however, drilling muds may cause considerable formation damage. One experimental deviated well has been drilled in the Devonian

shale, in Meigs County, Ohio, but its intent was

more to determine the natural fracture spacing

than to test a new production technique.25

Exploration

Unlike the sophisticated exploration techniques

used in frontier areas such as the Western Over-

.2qOffice of Tech rlology Assessment, ‘‘Status Report of the Gas

Potential From Devonian Shales of the Appalachian Basin, ” 1977.

Z> Charles Komar, Morgantown Energy Technology center, personal communlcatlon, 1984.
190. U.S. Natural Gas Availability: Gas Supply Through the Year 2000

thrust Belt and offshore, the “exploration techniques” used for locating Devonian shale wells

are often little more than near-random selection

based on the availability of land. The failure to

use sophisticated exploration technology reflects

a number of factors. First, it is difficult to build

an exploration block of any size in the Appalachian shale basin because of the diversity of land

ownership. Second, leasing problems—e.g., the

lack of well spacing requirements in some States

in the shale area—aggravate the problem because

wells on adjacent properties can get as close to

a successful well as the property line allows.

There is little incentive to invest in expensive

seismic surveys if the costs cannot be recaptured

by exclusive development of the surveyed area.

Third, existing technology is not fully effective in

locating the subsurface features whose understanding is critical to drilling success, and the

steep terrain drives up the cost of techniques such

as reflection seismology.

Aerial and satellite imagery may prove useful

in Devonian shale exploration because they can

identify Iineaments—characteristic topographic

features–which may be related to fault and fracture zones and may contain information on regional stress patterns. Concentrations of surface

fractures may indicate the presence of subsurface

fracture networks that could serve as potential

reservoirs. 26 Skeptics feel that surface expression

————

Z6R. D. MCIVer, j. R. Kyle, and R. E. Zielinski, “Location Of Drilling

Sites in the Devonian Shales by Aerial Photography, ” SPE/DOE

10794, SPE/DOE Unconventional Gas Recovery Symposium, pp.

51-53.

of fractures does not accurately reflect subsurface conditions (i.e., fractures may curve at depth

or may not extend to the gas-bearing rocks). To

support their position, they cite failures of wells

offset from producing wells along a surface lineament.

27

Subsurface mapping of variations in the rock

formations is also important in the shale region.

A key mapping tool for the shales is well logging

using a combination of gamma-ray and neutrondensity logs. Induction logs, spectral logs, thermal decay logs, noise logs, and temperature logs

are often run in combination with the gammaray and neutron-density logs. Some operators also

rely on a combination of gamma-ray, bulk-density, and resistivity logs. (For a brief description

of the various types of well logs, see box B-1 in

app. B.) Unfortunately, current well logging techniques are not adequate to detect open fractures

that do not actually intersect the boreholes, so

they are only of limited use in mapping fracture

patterns. Also, some States in the shale basins do

not require full disclosure of well log data, and

this further limits the ability to construct useful

subsurface maps from the existing data.

~johnston & Associates, inc., oP. cit.

RECOVERABLE RESOURCES AND PRODUCTION POTENTIAL

The Devonian shale gas-in-place resource in

the Appalachian Basin has been estimated at between 225 TCF (the NPC low estimate) and 2,579

TCF (the Mound estimate). As discussed above,

the higher end of the range appears most credible on the basis of existing data. However, much

of the gas-in-place is unlikely to contribute to

future gas supply, for the most part because geological conditions make the gas extremely difficult to produce. The quantity of gas likely to be

produced is a function of the price of the gas,

the available technology, the associated costs of

production, and a variety of other factors, such

as institutional barriers, that will influence decisionmaking on production. Several organizations

have attempted to estimate the size of the recoverable resource. Reports have been issued which

describe the resource and designate the most
Ch. 9—Gas From Devonian Shale ● 191

favorable areas for production.28 Production scenarios have also been established by further

assuming drilling and development schedules. In

general, the estimates of recoverable resources

and future production are based on extrapolation of past production, for which there is a sizable amount of data due to the long production

history of the shales. However, the production

data are limited in important ways. Available production histories are for the most part limited to

wells using traditional production technology,

that is, “shooting” with explosives at wide well

spacing. Also, these histories are affected by a variety of factors aside from the nature of the gas

resource. These factors include differences in

market conditions, well operating practices, production techniques, the use of workover treatments, and pipeline pressures.29 Extrapolation of

production data therefore should account for

these variables, yet the lack of data and the complexity of the necessary analysis makes such an

accounting quite difficult. None of the existing

ZBFavorable areas are designated by State in DOE/METC reports

118-124 and on a play basis in the USGS report entitled, “Estimates

of Unconventional Natural Gas Resources of Devonian Shale of

the Appalachian Basin, ” 1982.

Z9R. E. Ziellnski and R. D. Mclver, Resource and hph?tion

Assessment of the Oil and Gas Potential in the Devonian Gas Shales

of the Appalachian Basin, U.S. Department of Energy, Morgantown

Energy Technology Center Report DOE/DP/0053-l 125.

studies of recoverable resources have attempted

such an accounting. Also, it is not clear to what

extent the drilling represents a true unbiased sample of what might occur on undrilled acreage if

the same production techniques were used. These

problems with the available data are discussed

later.

Methodologies and Results

As illustrated in table 46, several estimates of

recoverable resources have been made. These

include early estimates by the Office of Technology Assessment (OTA), Lewin & Associates, and

the National Petroleum Council (NPC). Each estimator assumed economic and technologic parameters to establish estimates of recoverable resources in the Appalachian Basin. Both Lewin &

Associates and the NPC extended their analysis

to include annual production estimates or

scenarios.

More recently, Pulle and Seskus of Science Applications, Inc. (SAI), Zielinski and Mclver of

Mound, and Lewin & Associates also estimated

the recoverable resource in the Appalachian

Basin. Pulle and Seskus30 used past production

30C$ v. Pul[e and A. P. Sesktjs, “Quantitative Analysis of the Economically Recoverable Resource, ” U.S. DOE-METC, 1981.

Table 46.—Devonian Shale Recoverable Resource Estimates (TCF): Appalachian Basin

Organization Year Estimate Conditions

Office of Technology Assessment. . . . . 1977 15-25

23-38

Lewin & Associates . . . . . . . . . . . . . . . . . 1978-79 2-1o

4-25

After 15 to 20 years

After 30 to 50 years

At $2 to $3/MCF (1976), current technology

(borehole shooting or hydrofracturing),

150-acre spacing

Base case

Advanced case for prices between $1.75 to

$4.50

traditional advanced

National Petroleum Council . . . . . . . . . . 1980 3.3 - 38.9

15.3 - 49.9

Pulle and Seskus (SAI). . . . . . . . . . . . . . . 1981 17-23

Zielinski and Mclver (Mound) . . . . . . . . . 1982 30-50

Lewin & Associates . . . . . . . . . . . . . . . . . 1983 6.2-22.5

Lewin & Associates . . . . . . . . . . . . . . . . . 1984 19-44

For price levels between $2.50 to $9, 160-acre

spacing

Technically producible

“Shot” wells, 160-acre spacing

For States of West Virginia, Ohio, and Kentucky

only, “shot” wells, 160-acre spacing

Technically recoverable, for most promising

formations in Ohio. Maximum represents

80-acre spacing, advanced technology

Technically recoverable, for most promising

formations in West Virginia. Preliminary

values

SOURCE: ???
792 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

data and Delphi estimation to compute a mean

value of 20.2 TCF for the recoverable Appalachian resource using explosive fracturing at

160-acre spacing. Zielinski and Mclver31 utilized

SAI data to estimate the recoverable resource,

also based on explosive fracturing. They felt that

sufficient data were not available to make a

reliable estimate, but produced a preliminary estimate of 30 to 50 TCF for the minimum recoverable gas in West Virginia, Ohio, and Kentucky.

The most recent estimation effort was performed

by Lewin & Associates under contract to DOE’s

Morgantown Energy Technology Center (METC)

and was an estimate of the technically recoverable reserves in the most favorable Devonian formations in Ohio and West Virginia (the estimates

for West Virginia were published only in draft

form at the time of this report).32 To OTA’s knowledge, this estimate is the only one currently

available to use reservoir simulation. Using this

simulation capability, the analysis explores the

ramifications of alternative fracture technologies,

well spacing, and well patterns on the size of the

recoverable resource.

Office of Technology Assessment33

The OTA report was published in 1977 and was

the first study that attempted to evaluate the

recoverable Devonian shale gas resource in the

Appalachian Basin.

OTA established production estimates based

on 15 to 20 years of production data from 490

wells in three productive areas of the Appalachian

Basin. Wells from Cottageville and Clendenin,

WV, and Perry County, KY, were grouped according to the quantity (high, medium, or low)

of gas produced. Average production rates were

calculated for both shot and fractured wells in

each group and used to calculate the recoverable

resource assuming a productive area of 16,300

..—

3’R. E. Zielinski and R. D. Mclver, “Resource and Exploration

Assessment of the Oil and Gas Potential in the Devonian Gas Shales

of the Appalachian Basin, ” 1982.

32v. A. l(uuskraa, et al., Technically Recoverable Devonian shale

Gas in Ohio, Lewin & Associates Report for Morgantown Energy

Technology Center, July 1983; and V, A. Kuuskraa, et al., Technica//y Recoverable Devonian Shale Gas in West Virginia, Summary,

1984 (draft).

‘~office of Technology Assessment, “Status Report of the Gas

Potential From Devonian Shales of the Appalachian Basin, ” 1977.

square miles— 10 percent of the entire basin area

of 163,000 square miles. A well spacing of 150

acres was assumed, yielding approximately

69,000 wells. The economics were determined

using an after tax net present value (ATNPV)

model, a discount rate of 10 percent, and a wellhead price for gas in the $2 to $3/MCF range

(1976$).

The findings as reported by OTA are summarized below:

●

●

●

The Devonian shale resource could be produced without developing new production

equipment and techniques.

The Brown shaless34 (as they were called by

OTA) could yield between 15 and 20 TCF

during the first Is to 20 years of production.

After 30 to 50 years, cumulative production

could reach 23 to 38 TCF.

Because of the tremendous drilling effort and

the time required to develop the-necessary

pipeline infrastructure, as many as 20 years

may be required before annual production

reached 1 TCF.

A critical factor in OTA’s analysis is the assumption that only 10 percent of the Appalachian Basin

will prove to contain gas recoverable at the assumed price using conventional technology. This

assumption is based on the general argument that

past drilling has not been random, but instead

has been skewed to the high-quality areas–a universal tendency in resource development—and

also upon observations of the clustered nature

of existing development, the considerable depths

and/or thinness of the shales in some undeveloped portions of the basin, the poorly developed

fracture systems in other undeveloped areas, and

the lack of success of drilling in some of these

areas. This assumption that much of the undeveloped acreage in the basin will not prove to

be productive is undoubtedly correct qualitatively, but there appears little quantitative basis for

the choice of 10 percent as the productive fraction; it is essentially an educated guess.

‘QBrOWn Shales are generally younger than black shales and have

more hydrocarbons in the organic material. The organics in the

black shales are closer to elemental carbon. (V. Kuuskraa, 1982,

“Unconventional Natural Gas,” in Advances in Energy Systems and

Technology, vol. 3.) Brown and black shales are commonly referred

to jointly as black shales.
Ch. 9—Gas From Devonian Shale ● 193

Lewin & Associates I35

Lewin & Associates addressed the gas potential of Devonian shales in a series of 1978-79

reports entitled “Enhanced Recovery of Unconventional Gas. ” The purpose of the Devonian

shale portion of the study was to estimate the economic potential of the resource, based on empirical data such as geology, reservoir performance, and costs.

The Lewin & Associates study evaluated gas recovery potential with respect to price for base

and advanced cases. The parameters assumed for

each case are listed in table 47. Economic analyses were performed to determine the economically recoverable resource at $1.75, $3.00, and

$4.50/MCF (1977$) for both the base and advanced cases. The base case represents the development of areas with producing characteristics similar to areas under production today, using

available small-scale hydraulic fracturing techniques with design fracture lengths of 100 to 200

ft. The advanced case added a mix of strategies

to the base case to increase production and

enlarge the size of the recoverable resource, including:

jJLeWin & Associates, Inc., Enhanced Recovery of UnCOn VentiOna\

Gas, U.S. Department of Energy reports HCP/T 2705-01, 02, and

03, 1978-79.

●

●

●

extension drilling into deep shales, with improved stimulation (in eastern West Virginia

and Pennsylvania);

dual completion, i.e., stimulating two separate gas-bearing intervals from one well, with

improved stimulation (in Ohio), to allow economical production of marginal prospects;

and

improved recovery through advanced stimulation technologies and closer well spacing

(in eastern Kentucky and western West Virginia, the center of current production).

The evaluation was confined to the Appalachian Basin. Of the entire basin area of 210,000

square miles, only 62,000 square miles were considered as potential shale gas-bearing areas. The

62,000 square mile area was divided into 12 analytical areas based on similar geologic characteristics, drilling or production histories. Approximately 5,000 square miles of that area included

already proven areas or sites of previous production, leaving 57,000 square miles as probable and

possible gas-bearing areas.

Actual production data from several gas companies and 250 individual wells were collected

and cumulative production decline curves established for each area. The production curves were

adjusted for “play out, ” to compensate for the

fact that fields tend to produce less as drilling

Table 47.—Summary of Major Differences Between Lewin Base and Advanced Cases in Devonian Shale Analysis

Strategy item Base case Advanced case

Source characterization:

Eligible areas . . . . . . . . . . . . . . . . . . . . . . . Probable areas Probable and possible areas

Dry hole rates . . . . . . , . . . . . . . . . . . . . . . . 20% 10%

Technology:

Completions . . . . . . . . . . . . . . . . . . . . . . . . Single Dual where a low producer is underlain by

other productive pay

Recovery efficiency per unit area . . . . . . Current levels Improved by 20 percent in higher

producing areas

Economics:

Risk—reflected in discount rates a of . . . 21 ‘/0 160/0

Development:

Start year for drilling

Probable area . . . . . . . . . . . . . . . . . . . . . 1978 1981 (R&D effect begins)

Possible area . . . . . . . . . . . . . . . . . . . . . 1987 1987

Development pace

Probable area . . . . . . . . . . . . . . . . . . . . . 17 years to completion 13 years to completion

Possible area . . . . . . . . . . . . . . . . . . . . . 17 years to completion 15 years to completion

aDiscount rates include a constant ROR based on 10 to 150/0 and an inflation adjustment of 6°/0

SOURCE: Lewin & Associates.
194 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

moves into extension areas, and for stimulation

technology improvement, to compensate for the

differences between the old explosive fracturing

and hydraulic fracturing. The adjusted curves

were then used to estimate 30-year cumulative

recovery per well for each area. These estimates

were then used in the analysis of the economic

potential.

The economic analysis used a discounted cash

flow model. Net cash flow was calculated by subtracting investment costs, operating costs, and all

other allocated costs from the cash flow acquired

from production revenues. The net cash flow for

the 30 years of production for each well considered in the study was discounted to arrive at the

net present value. The areas with a positive net

present value were assumed to be developed in

accordance with the timing schedule designated

for each case.

The results of the economic evaluation are

summarized in table 48. The base case estimates

are quite pessimistic—at $4.50/MCF (1 977$), or

$7/MCF (1 983$), a very high price in today’s market, total recoverable resources are only 10.5

TCF. The somewhat more optimistic advanced

case, which reaches 18 to 25 TCF at the same

price, obtains most of its added recovery from

the deep drilling and dual completions, with improved recovery in existing producing areas

yielding only 2.1 TCF at this price.

An important consideration in this analysis is

that Lewin considered there to be little difference

in per well recovery efficiency between the base

and advanced case, despite the more effective

fracturing attainable in the advanced case. The

major difference between the two cases is the

Table 48.- Lewin & Associates: Results of Economic

Analysis, Summary Table

Economically recoverable

Price, 1977$ (1983$) Base case Advanced case

$1.75/MCF ($2.75/MCF) . . . . 2 TCF 5 TCF

$3.00/McF ($4.70/MCF) . . . . 8 TCF 16 TCF

$4.50/MCF ($7.00/MCF) . . . . 10.5 TCF 18 to 25 TCFb

aCurrent proved reserves are 1 TCF and the following estimates represent additions to reserves.

bThe range reflects the geologic uncertainty with regard to natural fracture intensity.

SOURCE: Lewin & Associates.

more rapid drainage attainable with the improved

stimulation technology, which greatly improves

the economics of recovery and moves marginal

areas into the “economically recoverable” range.

The source of this interpretation is the belief at

the time that the primary source of producible

gas is the fracture porosity.36 This was thought

to imply that the recovery efficiency of even borehole shooting would be quite high, in the neighborhood of so percent, with little improvement

obtainable from more effective fractures. It currently is believed, however, that much of the

long-term well production is from the resorption

of gas bound to the shale matrix, and that the

actual recovery efficiency of borehole shooting

is only a few percent. Lewin’s new work, described later in this section, folds this new understanding of the source of recoverable Devonian

shale gas into its analysis (see the discussion of

“Lewin & Associates 11”). An important implication of this understanding is that improved fracturing should increase ultimate recovery, not just

accelerate production.

National Petroleum Counci137

The NPC also estimated the quantity of producible gas in the Appalachian Basin for different

levels of technology and price. Three levels of

technology were considered in the analysis: traditional (borehole shooting), conventional (conventional hydraulic fracturing), and advanced (unique

fracturing techniques and deviated drilling). Advanced technology was assumed to double the

production increase achievable from the use of

conventional technology.38 Conventional technology was assumed to increase production over

traditional borehole shooting by O to 57 percent

depending on the open flow rates of the wells.39

MI n other words, it was thought that most of the recoverable gas

was free gas stored in the natural fracture systems.

jzNational petroleum COU nci 1, Unconventional Gas SOUrCt?S—

Devonian Shales, 1980.

JaThis assumption was based on experiments performed i n

Kanawha County, WV. Three advanced technology wells had production increases of 230 percent over wells stimulated by traditional shooting. Conventionally fractured wells showed 80 percent

increases in production over traditionally shot wells.

39 The advantages d fracturing over borehole shooting decline

as the unstimulated flow rate increases; with flow rates above 300

MCF/D, fracturing was assumed to be no better than shooting.
Ch. 9—Gas From Devonian Shale . 195

The quantities of potential reserves for price levels

between $2.50 and $9.00 (1979$) were estimated

by performing discounted cash flow analysis for

10, 15, and 20 percent after tax rates of return.

NPC’s initial objective was to utilize existing

production data to predictor extrapolate production in undeveloped areas. They intended to

model the average well production decline of

each county to the hyperbolic equation below:

where Cl, C2, and C3, were empirically derived

constants for that county. When the existing production data were fit to the equation, they discovered that all the decline curves, regardless of

county, could be represented adequately with the

use of 3 and 2.5 for C2 and C3

, respectively.

Therefore, apparently Cl can serve as an index

to characterize average production decline for

each county. The relation of Cl to cumulative

production can be determined by integrating the

hyperbolic equation over the appropriate time

period. For example, 30-year cumulative production is equal to 4.43 Cl.

Several parameters, such as the various thickness estimates and depth, were evaluated for correlation with the Cl values. The thickness of the

black shale as determined by gamma-ray logs was

the only parameter that correlated to Cl

; it did

so with a linear coefficient of 0.213, that is, the

average county black shale thickness as determined by logging can be multiplied by 0.213 to

obtain the Cl value for each county. This value

was used as the basis for the “traditional technology” case.

The results of the economic analysis are tabulated in table 49. The potential reserve is that portion of recoverable gas that is economically producible at a given price. The total producible gas

is the total cumulative amount of in-place gas that

Table 49.—Summary of Producible Gas Estimates

can be produced over the wells’ 30-year lifetimes,

under the specified technological conditions, irrespective of price.

The major findings presented in the NPC report are listed below:

●

●

●

Average well production can be modelled

to a hyperbolic decline curve as represented

by the equation below:

Cl is an index to characterize average production decline and is linearly related (linear coefficient of 0,213) to black shale thickness as determined by log data.

The total producible gas using conventional

technology is 37.4 TCF, which is approximately 30 percent of the 125 TCF estimated

gas-in-place in drillable formations assuming

the lower value of shale thickness based on

gamma-ray well log data (see the discussion

of the NPC estimates of gas-in-place earlier

in this chapter), and about 4 percent of the

1,040 TCF gas-in-place using the visually

determined thickness.

The average price requirement for production of 37.4 TCF is $6.75/MMBtu (1979$)at

10 percent rate of return. Approximately 15

TCF can be produced at prices up to $3.50/

MMBtu.

Pulle and Seskus (SAl)40

This analysis essentially extrapolates production

data from 1,534 Devonian shale wells (with 10

years or more of production history) to full development of the Appalachian Basin’s shales. The

basin is divided into 10 subregions based on the

thickness of the radioactive (black and brown)

‘C. V. Pu Ile and A. P. Seskus, Science Applications, Inc., Quantitative Analysis of the Economically Recoverable Resource,

DOE/MC/08216-l 57, May 1981.

Appalachian Basin (constant 1979 dollars and 10°/0 ROR)

Cumulative potential reserves (TCF) v. price ($/MMBtu) Total producible

2.50 3.50 5.00 7.00 9.00 gas (TCF)

Traditional technology . . . . . . . . . . . . 3.3 8.5 11.4 14.9 16.6 25.3

Conventional technology . . . . . . . . . . 7.3 14.5 19.5 23.5 27.0 37.4

Advanced technology . . . . . . . . . . . . . 11.8 20.1 27.2 32.9 38.9 49.9

SOURCE: National Petroleum Council.
196 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

shales, the drilling depth of past production, and

a measure of the thermal maturity of the shale

cores that have been obtained. To obtain an estimate of the recoverable resource, wells are assumed to be drilled on 160-acre spacing, using

explosive shooting for stimulation. Past production histories are used to estimate 30-year cumulative production for wells in half of the subregions; for the other subregions, production is

estimated by combining the opinions of four experts in a Delphi procedure. The percentages of

dry holes are estimated using the same Delphi

procedure.

The estimated mean recoverable gas under the

160-acre spacing is 20.2 TCF, with an estimated

95 percent probability that the total lies between

17.06 and 23.34 TCF. However, the “95 percent

probability” is a statistical value based on the

assumption that the distribution implied by the

historical data is a perfect reflection of future production from new wells. This seemingly high level

of probability should not be treated too seriously.

It does not account for errors introduced by the

Delphi procedure, by changes over time in well

“shooting” techniques, or by the possibility that

past well locations were not random but instead

represent some selection on the basis of relative

prospects for success.

The analysis does not include an evaluation of

the effect of price on well spacing, so it is not clear

what gas price corresponds to the estimated 20,2

TCF of recoverable resources. On the other hand,

the authors show how total recovery is likely to

vary with well spacing; table 50 shows the variation of recoverable resources with assumed well

spacing. This estimate is based on a theoretical

model applied to only four wells, so the results

should be treated as very tentative. Also, the estimated recovery—and revenue—per well for 10-

acre spacing is only one-fifth of the per well

recovery and revenue for 160-acre spacing. This

implies that the gas price needed for economic

recovery of the 67,9 TCF resource for 10-acre

spacing will be five times the price needed for

recovery at 160-acre spacing, all other things being equal. A countervailing factor, however, is

that gathering costs are quite high in the Appalachian region, and closer well spacing and the

Table 50.—Effect of Spacing on the

Devonian Shale Recoverable Resource

—

Relative Ratio of Total

Spacing number increase in recoverable

(acres) of wells resource resource (TCF)

160 . . . . . . . 1 1.00 20.2

80 . . . . . . . 2 1.68 34.0

40 . . . . . . . 4 2.44 49.3

20 . . . . . . . 8 3.10 63.0

10 . . . . . . . 16 3.36 67.9

SOURCE: C. V. Pulle and A. P. Seskus, Quantitative Analysis of the Economical.

ly Recoverable Resource, US. Department of Energy Report DOE/MC/

08216-157, May 1981.

resulting higher production levels per unit area

would lower these costs.

Mound Facility (Zielinski and Mclver)41

Zielinski and Mclver of the Monsanto Corp.’s

Mound Facility have reviewed the NPC and SAI

estimates of recoverable resources in the Appalachian Basin and, using the SAI data, derived an

alternative, admittedly preliminary estimate of the

recoverable resource in West Virginia, Ohio, and

Kentucky.

Zielinski and Mclver’s review of the NPC estimates noted the following:

1.

2.

3.

——

There are important numerical discrepancies

between well production values reported by

NPC as derived from their equations, and

values actually calculated using these

equations.

The NPC analysis derived a relationship for

the initial production rate of a well by searching for correlations only with variables which

have little to do with production, and picked

a variable (gamma-ray log response) for the

relationship only by default. Neither gammaray log response nor any of the other variables examined bear any relationship to the

organic matter type or thermal maturation,

both critical factors in determining gas potential.

The NPC found that a single equation could

represent well production for the entire Ap41 R. E. Zielinski and R. J. Mclver, Resource and Exploration Assessment of the Oi/ and Gas Potential in the Devonian Gas Shales of

the Appalachian Basin, Mound Facility Report to U.S. Department

of Energy, DOE/DP/0053-l 125, undated.
—

Ch. 9—Gas From Devonian Shale . 197

palachian Basin. This may imply that, for the

shot well technology used in most of the

wells in the production histories, the fairly

uniform porosity and permeability values of

the shale dominate average gas production.

This, in turn, implies to the reviewers that

closer well spacing should significantly improve recovery if shooting is the method of

stimuIation.

The review of the SAI estimate noted the following:

1. SAI divided the basin into 10 subregions by

evaluating four variables—radioactive shale

thickness, drilling depth, stress ratio, and a

measure of thermal alteration. Only the latter variable has any documented relationship to gas production, and this relationship

is a limited one. Consequently, the extrapolation of production data in a subregion to

undeveloped portions of that region may not

be valid.

2. SAI assumed that well production in each

subregion would be distributed Iognormally,

but the actual production data in the five

subregions where production data was available did not tend to indicate a Iognormal distribution.

Zielinski and Mclver also were concerned that

neither the NPC nor the SAI estimates accounted

for the effects of external influences–market

forces, operating policy, production practices–

on production, but instead implicitly assumed

that past production was dependent only on the

physical nature of the resource.

Based on the above concerns, Zielinski and

Mclver’s conclusion was that “the two . . . studies

. . . do not form a sound foundation for the estimation of recoverable resource. ”

Zielinski and Mclver have developed a preliminary estimate of recoverable resources in Ohio,

Kentucky, and West Virginia based on the observation, from SAI production data, that the production per unit area of the developed portions

of these States follow a clear pattern, i.e., Kentucky’s production tends towards 2.3 X 10-3

TCF/mi

2

, Ohio’s towards 0.7 X 1 0

-3 TCF/mi2

,

and West Virginia’s towards 1.5 X 10-3 TCF/mi 2

.

Extrapolating these values to prospective but

undeveloped acreage yields a total recoverable

resource of 30 to 50 TCF for the three States, for

the same technology (“shooting”) and well spacing (160 acres). This estimate is based on the

assumption that different market conditions, production practices, etc., did not affect the State

production averages, and also that past well siting

was random. The authors consider the 30 to 50

TCF value to be a minimum for recoverable

resources because improved stimulation technology, closer well spacing, or use of remote sensing techniques to improve well siting can individually or in combination increase total recovery

as well as production rates. For example, Zielinski

and Mclver predict that halving well spacing to

80 acres will essentially double the recoverable

resource.

Lewin & Associates II42

A recent estimate by Lewin & Associates makes

use of the extensive data collection and analysis

effort of DOE’s Eastern Gas Shales Project, e.g.,

the geochemical analyses of Mound, and combines this with reservoir simulation to estimate

the technically recoverable gas resource of the

Lower and Middle Huron Intervals of the Ohio

Devonian shale.

The Lower and Middle Huron Intervals represent only a portion of the resource base that potentially can be exploited; they contain about 50

TCF of gas-in-place, compared to an estimated

gas-in-place of 390 TCF for Ohio and 2,579 TCF

for the Appalachian Basin .43 The Huron Intervals

have been the traditional targets for past drilling

in Ohio, and the great majority of available drilling data applies only to these intervals. The recovery potential of the remaining 340 TCF in

Ohio is unknown. However, nearly half of the

gas-in-place in the entire basin is considered by

Mound to be undrillable because of surface constraints such as roads and towns, and thus the

recoverable resource for the remainder of Ohio

42V E Kuu5kraa, et al,, I-ew; rl & Associates, Inc., Technicall y

,.

Recoverable Devonian Shale Gas in Ohio, prepared for the Morgantown Energy Technology Center, U.S. Department of Energy, July

1983.

4JFrom the Mound Study.
✑✙✘● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

is unlikely to be as large, in relationship to its gasin-place, as in the Huron Interval. Nevertheless,

the Lewin estimates should be recognized as representing only a limited portion of Ohio’s Devonian shale gas potential, although the most prospective portion.

Selected results of the Lewin analysis are shown

in table 51. The results should be interpreted

carefully because they refer to the expected physical results of a specified quantity of drilling and

stimulation without regard to economic feasibility. In other words, they are comparable to the

“technically recoverable” or “maximum producible” resources of other estimates. The results are

particularly interesting, however, because Lewin’s

use of reservoir simulation provides for a more

credible estimate of the effects of improved stimulation technologies and smaller well spacing. As

shown in the table, both methods of improving

gas recovery could be extremely successful in the

Appalachian Basin. According to the report, 80-

acre spacing has already started to supplant the

more traditional 160-acre spacing in new drilling

in the basin, Accordingly, the 8.7 to 10.5 TCF projected as the result of improved but relatively conventional technology at 160-acre spacing probably represents a pessimistic estimate of actual

recoverable resources assuming high gas prices.

This result has interesting implications for the

future potential of Devonian shale gas in view of

the limited portion of the total Appalachian resource represented by this analysis.

A more recent Lewin study, available in draft

at the publication close of this report, estimates

the technically recoverable Devonian shale resources in West Virginia. Table 52 summarizes

the results, which apply to the Huron, Rhinestreet, and Marcellus shale intervals. These intervals represent the most promising shale prospects

in the State, although only 70 TCF out of a total

of 125 TCF of gas-in-place for the intervals was

actually appraised. Insufficient reservoir data

were available for the nonappraised portions of

these intervals. In addition, hundreds of TCF exist in lower quality shale formations that may be

developable at some point, but not with simple

extensions of today’s technology.

The results of the West Virginia assessment are

even more optimistic than the Ohio results, given

the estimated 25.4 to 32.7 TCF technically recoverable resource based on improved but readily

attainable technology and 160-acre spacing.

Coupled with the probability that Kentucky will

prove to have recoverable resources somewhere

in-between those of Ohio and West Virginia,44

the Lewin results imply that the Devonian shale

recoverable resource is considerably greater than

imagined by all of the previous estimates reviewed herein.

Table 51 .—Results of Lewin Assessment of

Technically Recoverable Gas in Ohio, by

Stimulation Method After 40 Years

dqvel 10 I(u u5kraa, Lewin & Associates, Inc., personal Comm u n ication, 1984.

1. Present technology, 160-acre spacing

● Borehole shooting . . . . . . . . . . . . . . . . . . . . . . .6.2 TCF

Il. Improved but readily attainable technology,

160-acre spacing:

● Small radial stimulation (30 ft radius). .. ....8.7 TCF

● Small vertical fracture (150 ft wings) . .....10.5 TCF

Ill. Advanced technology, speculative,

160-acre spacing:

● Large radial stimulation (60 ft radius). .. ...10.2 TCF

. Large vertical fracture (600 ft wings) . .....15.2 TCF

. Large vertical fracture, 80-acre spacing

(600 ft wings) . . . . . . . . . . . . . . . . . . . . . .....21.0 TCF

IV. Changed well patterns (3 to 1 rectangle,

taking account of permeability anisotropy)

with improved or advanced technology:

yields added recovery of 5 to 10 percent/well.

SOURCE: V. A. Kuuskraa, et al., Technically Recoverable Devonian Shale Gas in

Ohio, Lewin & Associates Report for Morgantown Energy Technology

Center, July 1983.

Table 52.-Results of Lewin Assessment of

Technically Recoverable Gas in West Virginia, by

Stimulation Method After 40 Years

1. Present technology, 160-acre spacing:

● Borehole shooting . . . . . . . . . . . . . . . . . . . . . .19.1 TCF

Il. Improved but readily attainable technology,

160-acre spacing:

● Small radial stimulation (30 ft radius). .. ...25.4 TCF

● Small vertical fracture (150 ft wings) . .....32.7 TCF

Ill. Advanced technology, speculative:

● Large vertical fracture (600 ft wings) . .....88.4 TCF

SOURCE: V. A. Kuuskraa, et al., Technically Recoverable Devonian Shale Gas in

West Virginia, Summary, 1984 (draft).
Ch. 9—Gas From Devonian Shale ● 199

Estimates Comparison and Uncertainties

OTA’s examination of the several estimates of

Devonian shale recoverable resources established some important concerns:

First, with the exception of the latest Lewin &

Associates reports on Ohio and West Virginia, the

attributes of advanced recovery technologies

were described vaguely, and a reservoir simulation model that could predict the effect of longer

fractures or other attributes of advanced technologies was not available. Consequently, estimates

of the effects of advanced recovery technologies

on recoverable resources should be considered

at best either “educated guesses” or extrapolations based on quite limited evidence.

Second, several of the estimates extrapolate

available data on existing production to the entire Appalachian Basin by using methods that rely

on guesswork, on arguable assumptions, or on

apparent relationships with variables that do not

seem likely to be strongly related to resource

recovery potential. For example, the early OTA

study did not formally relate well production to

measurable physical attributes of the areas under

development, presumably because there were inadequate data. Instead, the study assumed that

10 percent of the basin will be productive in the

same manner as the area now under production,

and that the remainder of the basin will be unproductive; the choice of 10 percent was not explained, but is essentially an “educated guess.”

Both the Pulle and Seskus and the NPC estimates

relied on predictive variables—in NPC’s case,

shale thickness as measured by gamma-ray logs—

which seem likely to be only limited predictors

of gas recovery. The Zielinski and Mclver estimate

for West Virginia, Ohio, and Kentucky, admittedly a preliminary, crude attempt, is based on

the assumption that the existing wells, used for

extrapolation, were randomly sited, so that their

production would be representative of what

would occur in the untested portions of the shale

area. This type of assumption is more tenable in

the Appalachian Basin than it would be elsewhere because sophisticated exploration techniques were not used to site the existing wells,

the haphazard availability of land for drilling may

have interfered with pattern drilling, and other

factors. In our view, however, the information

gained by earlier drilling is certain to have directed subsequent drilling to better-than-average

prospects, and the direct extrapolation used in

this study will tend to lead to an overestimate of

the resource recoverable by borehole shooting.

Third, only a very small part of the Devonian

shale has been tested by drilling, and consequently the available studies focus on the resources recoverable from the producing shale intervals, or those closely resembling them, i.e.,

those with well-developed natural fracture systems. Much of the gas-in-place exists in intervals

which are not currently productive. For the most

part, the large portion of this gas probably could

not be produced with current technologies and

prices. However, it may be possible to economically recover much of this gas with new technology, especially at higher prices. The existing

studies cannot account for this possibility, and

probably there is no credible way at present to

determine the true potential of these intervals.

Nevertheless, it must be made clear that the existing estimates of the Devonian shale resource

potential do not include this speculative portion

of the resource, and that there is at least the possibility that, with further technology development, the gas ultimately recoverable from the

Devonian shales may be considerably larger than

currently estimated.

Fourth, all of the estimates may suffer from the

problem that past production has been influenced by the market and by other external influences on production. The studies all implicitly

assume either that the resource characteristics are

dominant in determining production characteristics, or else that any external influences on production will remain essentially unchanged during the period of development of the resource.

Zielinski and Mclver have noted that these production influences might have affected the ultimate recovery of past wells, and should be taken

account of when extrapolating to future production.

Comparison of the resource estimates of the

various studies is made difficult by the first problem, the lack of clearly defined criteria for “advanced technologies, ” and also by differences in
—

200 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

assumed gas prices and study areas. However,

relatively clear comparisons can be made of the

resources recoverable by traditional borehole

shooting. Table 53 compares the resource estimates of six studies for borehole shooting at 150-

to 160-acre spacing and, for three of the studies,

at prices moderately higher than current market

prices for new gas. The estimates of Pulle and

Seskus, Zielinski and Mclver, and the recent

Lewin study do not specify prices and are more

in the nature of “technically recoverable gas. ”

They are best compared to the NPC “total producible” resource of 25.3 TCF and the 1977

Lewin estimate of 10.5 TCF for gas prices of

$4.50/MCF ($7.00/MCF [1983$]); the latter should

be close to a “technically recoverable” limit because of the rapidly diminishing returns for further price increases apparent in the Lewin analysis.

Because there has been extensive experience

with borehole shooting, the estimates for recoverable resources using this technology should be

the most reliable. There are serious differences

among the estimates in table 53, however, and

we believe these differences reflect some of our

concerns with the individual studies. The Zielinski and Mclver estimate, which should be considered optimistic because it assumed that siting

of past wells was random and therefore that their

production experience would be representative

of undrilled acreage, is in fact the highest of the

estimates of technically recoverable gas. The 1977

OTA estimate is not based on a geological evaluation of the prospects of the undeveloped portion

of the basin, and probably should be downplayed; it is, in fact, at considerable variance with

the NPC and early Lewin estimates, which are

more pessimistic. On the other hand, the early

Lewin estimates also appear to be considerably

more pessimistic than the recent Lewin estimates

for Ohio and West Virginia; it seems likely that

a new Lewin estimate of the Appalachian gas

recoverable at about $4.70/MCF (1983$) would

be considerably higher than the 8 TCF predicted

by the early study. The difference between the

early and more recent Lewin studies is emphasized by the recognition that the early study includes some hydraulic fracturing in its recoverable resource estimate; presumably, its estimate

for the resource recoverable with borehole shooting only would have been even lower than 8 TCF.

In conclusion, OTA’s best resolution of existing

resource studies is that the Devonian resource

ultimately recoverable with borehole shooting at

160-acre spacing and gas priced at $4 to $5/MCF

(1983$) is at least 10 TCF and, based on the implications of the recent Lewin work, most probably is somewhat higher. Ultimately, if the Lewin

analyses prove to be substantially correct, about

30 to 50 TCF may be recovered with this technology and spacing at very high prices. These are

extremely conservative estimates of the actual gas

potential of the Appalachian Basin, however, because neither the technology assumption nor the

spacing assumption are realistic. Many producers

in the basin have begun to use hydraulic fracturing, which increases ultimate recovery per well,

and well spacing in the less permeable areas has

begun to be decreased to 80 acres, which improves recovery per section. With borehole

shooting as the “baseline” technology, halving

Table 53.—Comparison of Estimated Appalachian Devonian Shale Resources Recoverable With Borehole Shooting,

Well Spacing of 150 to 160 Acres

Gas price ($/MCF) Recoverable resource Total producible

Study (data) study date (1983)a

(TCF) (TCF)

OTA (1976) . . . . . . . . . . . . . . . . . . . . .... ... ... .. .$2 to $3 ($3.03 to $4.95) 23 NA

NPC (1979) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3.50 ($4.70) 8.5 25.3

Lewin I (1977). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3000 ($4.68) 8

b

10.5+

Pulle and Seskus (1981) . . . . . . . . . . . . . . . . . . . . . . None 17-23

Zielinski and Mclver (1982)

(West Virginia, Ohio, Kentucky) . . . . . . . . . . . . . None 30-50

Lewin II (1983) (portions of

Ohio and West Virginia only) . . . . . . . . . . . . . . . None 25.3

aThe 1983 gas price is obtained by applying the GNP Price Deflators published by the Bureau of Economic Analysis, Department of Commerce.

blncludes hydraulic fracturing as well as borehole shooting.

SOURCE: Office of Technology Assessment.
Ch. 9—Gas From Devonian Shale ● 201

the spacing seems likely to yield at least a 70-

percent increase in recoverable resources, primarily because the area of influence of each well

is smallest with this technology and thus the additional wells will interfere least with the adjacent

wells. The incremental benefit of reduced spacing will decrease for recovery technologies that

contact more of the formation because of interference between adjoining wells; however, Lewin

estimated that halving the spacing will still add

40 percent to the recoverable resource in Ohio

even when the baseline technology achieves 600-

ft fractures, which should maximize interference

between wells.

The use of conventional hydraulic fracturing

and more advanced stimulation also can greatly

increase the recoverable resource. The N PC estimates that conventional fracturing will yield a 50-

to 70-percent increase in recovery over borehole

shooting. They project an additional 40-percent

increase over the conventional fracturing with the

more advanced stimulation techniques, but this

estimate is based on very limited experience. The

recent Lewin study estimates that a stimulation

achieving 600-ft fractures can more than double

the recoverable resource over that obtainable

with borehole shooting, and that a combination

of this technology with 80-acre spacing can more

than triple the resource.

These estimates imply that the recoverable resource in the Appalachian Devonian shales may

prove to be quite large, perhaps 80 or 100 TCF

or even higher with high gas prices and substantial improvements in recovery technology. However, the current limited capability in reservoir

simulation and our limited geologic understanding imply that estimates of recoverable resources

using advanced technology should be viewed as

having quite high uncertainty.

Finally, as noted previously, none of the estimates consider the possibiIity of producing from

shale intervals that do not contain well-developed

natural fracture networks. This portion of the

shale is a highly speculative resource, and its gasin-place may never become recoverable. Nevertheless, it does present some potential for future

recovery.

Annual Production Estimates

Annual production estimates may be calculated

by estimating the number of wells to be drilled

and postulating a drilling schedule. The number

of wells drilled is determined by the area considered to be drillable and the well spacing

assumed. The larger the well spacing, the fewer

the number of wells that may be drilled in a given

area. The USGS argues that drainage patterns of

Devonian shale wells are too variable to assume

a constant spacing.

Lewin & Associates determined 1990 production estimates based on an available acreage of

57,000 square miles, a well spacing of 150 acres

per well and the drilling and development schedules outlined for the base and advanced technology cases. The resulting estimates are shown in

table 54.

Annual production and additions to reserves

were also calcuIated in the NPC study. The number of wells drilled were constrained by an available acreage of 62,000 square miles, a well spacing of 160 acres per well and “low” and “high”

drilling schedules. The low scenario assumed

there would be initially 12 rigs drilling in Devonian shale in 1980, and a 12-percent increase

each year thereafter. The high scenario assumed

15 rigs were active in 1980, with 15 rigs added

each year through 2000. All rigs were assumed

to drill 35 productive wells per year. The results

of this analysis are included in table 55. As shown

in the table, the high scenario depends on extremely high gas prices into the 1990s. Even with

advanced technology, the year 2000 production

rate of 1.35 TCF/yr requires gas prices above

$10.00/MCF (1983$).

It is not clear whether or not the annual production estimates projected by the NPC and

Lewin accounted for some important factors that

can influence the rate at which the resource is

developed. The effects of these factors are not

readily quantifiable, but they can be used to qualify the production potential estimates.

One factor that definitely will affect the production rate is the availability of adequate leases

for exploration and drilling. In fact, in most ac38-74~ O -85 - 1 4
202 U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Table 54.—Lewin & Associates Results for Annual Production Estimates

Price, 1977$ (1983$) Production rates (TCF/yr)

($/MCF) Base case Advanced case

1.75 (2.75) . . . . . . . . . . . . . . . Peak 0.1 in 1990 Peak 0.3 in 1990

declines thereafter declines thereafter

3.00 (4.70) . . . . . . . . . . . . . . . Peak 0.3 in 1990 0.6 in 1990, hold to 1995

gradual decline thereafter declines thereafter

4.50 (7.00) . . . . . . . . . . . . . . . Remains constant at 0.3 Increases to 0.7 to 0.9 in 1990

through 2000

SOURCE: Lewin &Associates, Inc., Enhanced Recovery of Unconventional Gas, U.S. Department of Energy Report HCP/T2705-01,

02, and 03, 1978-79.

Table 55.—Potential Incremental Supply of Devonian Shale Gas In the Appalachian Basin:

NPC High Growth Drilling Schedule (production and reserve volumes [BCF] and price [$/MMBtu]) (constant 1979 dollars)

1980 1985 1990 1995 2000

Annual productive wells drilled. . . . . . . . . . . . .

Cumulative wells . . . . . . . . . . . . . . . . . . . . . . . . .

Traditional technology:

Annual production rate . . . . . . . . . . . . . . . . . .

Annual reserve additions . . . . . . . . . . . . . . . .

Cumulative additions . . . . . . . . . . . . . . . . . . .

Incremental price at 10°/0 ROR . . . . . . . . . . .

Conventional technology:

Annual production rate . . . . . . . . . . . . . . . . . .

Annual reserve additions . . . . . . . . . . . . . . . .

Cumulative additions . . . . . . . . . . . . . . . . . . .

Incremental price at 10°/0 ROR . . . . . . . . . . .

Advanced technology:

Annual production rate. . . . . . . . . . . . . . . . . .

Annual reserve additions . . . . . . . . . . . . . . . .

Cumulative additions . . . . . . . . . . . . . . . . . . .

Incremental price at 10°/0 ROR . . . . . . . . . . .

770

770

15

200

200

<2.50

17

240

240

<2.50

21

290

290

<2.50

3,400

12,500

190

890

3,300

<2.50

220

1,040

3,800

<2.50

270

1,290

4,800

<2.5 0

6,000

37,300

430

1,250

8,800

<5.00

550

1,660

11,000

<3.50

700

2,030

14,000

<3.50

8,650

75,300

620

1,110

14,300

<7.00

865

1,690

19,600

<7.00

1,110

2,170

25,100

<5.00

11,300

126,400

690

720

18,400

<12.00

1,005

1,140

26,100

<9.00

1,355

1,600

34,500

<9.00

SOURCE: National Petroleum Council.

tive areas of Devonian shale drilling, perhaps 95

percent of all wells drilled are located on the basis

of the availability of Iand. Most of the Devonian

shale in the Appalachian Basin occurs in the

older, more populated areas, which over the

years have been divided into small tracts (by oil

industry standards). Building an exploration block

of any size is difficult and expensive with many

title problems. Also, a trend towards short-term

leases of 1 year or less has made establishing an

orderly exploration program difficult. Some States

also have no well spacing requirements, making

any tract capable of holding a potential drilling

rig a drill site. As a result, a good well may be

jeopardized by other wells that are placed too

close to it.

The type of operators in the Devonian shale

will also influence the development of the resource. The major oil companies have not invested in Devonian shale wells, due principally

to land problems and poor well performance.

The majority of operators are small companies

financed by drilling funds or direct investment

groups. Although these small operators can move

swiftly into “hot” acreage, their cash flows are

generally not sufficient to allow much exploration. As a result, many wells are drilled with little regard to geological conditions. A lack of funds

could also inhibit the use of costly yet more effective evaluation and stimulation techniques,

thereby reducing the quantity of gas ultimately

recovered,

Aside from these uncertainties, and the obvious

uncertainty introduced by our inability to project

future economic and market conditions such as

gas prices, demand, and availability of capital,

production projections share most of the uncertainties associated with the estimates of recoverable resources discussed previously in this

chapter. Of particular interest are uncertainties
Ch. 9—Gas From Devonian Shale ● 203

in the effects of improved stimulation technologies, since increases in fracture areas will affect

production rates as well as total cumulative production. Consequently, production projections

assuming the use of advanced technologies

should be considered substantially more uncertain than projections assuming explosive fracturing. In the latter case, extrapolating from historic

production data should be an acceptable procedure for projecting future production, although

our lack of data on production practices and

other factors that might have influenced past production rates requires that a substantial error

band be placed around the results.

Production levels of about 1.0 TCF by the year

2000 would seem to be readily supported by the

available studies: the 1977 OTA study concluded

that 1.0 TCF/yr could be achieved 20 years after

commencing an intensive drilling program, assuming relatively moderate prices; the first Lewin

study projected a maximum production rate of

0,9 TCF/yr in 1990, with advanced technology

and $4.50/MCF gas (1 977$) ($7.00/MCF [1983$]);

and the NPC study projected a 1.0 TCF/yr production rate in 2000 using available technology,

although admittedly at a very high price ($9.00/

MCF [1979$]). However, high production levels

of Devonian shale gas in the Appalachian Basin

using currently available or moderately improved

technology implies a massive expansion of drilling

in an area where such an expansion is institutionally and physically difficult. Also, the production levels in the various studies were derived by

assuming arbitrary drilling levels and extrapolating production data from quite limited areas to

the basin as a whole. On the other hand, the recent Lewin work in Ohio and West Virginia implies that gas recovery (and production rates) per

section can be increased substantially with reduced spacing, tailoring of drilling patterns to

permeability anisotropy, and improved fracturing. Increased recovery per section could allow

a more rapid expansion of production by easing

problems of pipeline construction and land assemblage. Consequently, if gas market conditions

in the Northeast improve very soon, institutional

barriers to production are reduced or overcome,

and exploration and production technology advances are achieved, OTA considers a production rate of 1.0 to 1.5 TCF/yr from the Appalachian Devonian shales by the year 2000 to be

quite plausible. Achievement of the prerequisite

conditions in the short time span involved is,

however, still somewhat optimistic.
Chapter 10

Coalbed Methane
Contents

Page

Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........................207

Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................207

Gas-in-Place . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...............209

Methodologies and Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...209

Uncertainties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...................211

Production Methods and Technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ....212

Production Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..............212

Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......................215

Recoverable Resources and production Potential . ........................217

Methodologies and Results . . . . . . . . . . . . . . ............................217

Estimate Comparison and Uncertainties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..219

Annual Production Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..........221

TABLES

Table No. Page

56. Coalbed Methane Resource Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .210

57. Coal Resource and Gas Content Assumptions . .................,......210

58. DOEGas-in-Place Estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..211

59. Comparison of Recoverable Resource Estimates . ......................217

60. GRl Coalbed Methane Annual Production Estimates (TCF). . . . . . . . . . . ....223

FIGURES

Figure No. Page

43. U.S. Coal Regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .........208

44. Variation of Gas Content by Rank, Temperature. . . . . ..................208

45. Variation of Adsorbed Gas by Rank . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..209

46. Methane Gas Adsorbed on Coal as a Function of Pressure . .............213

47. Pressure Drawdown Curves for Three Wells in a Line . .................214

48. 20-Year Production Prediction for Gas and Water Production From a Well

Pattern Designed to Allow Rapid Water Removal . .....................214

49. Deviated Drilling into a Coal Seam . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...216

50. Estimated Distribution of Bituminous Coal by Seam Thickness . ..........218

51. Well Production Histories in San Juan and Other Basins . ...............220

52. Annual U.S. Production Rates of Coalbed Methane as a Function of

Time–Vertical Wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ........222

53. Annual U.S. Production Rates of Coalbed Methane as a Function of

Time–Horizontal Wells . . . . . . . . . . . . . ..............................222
Chapter 10

Coalbed Methane

INTRODUCTION

Methane in coal seams traditionally has been

viewed as a hazardous waste product of the mining operation, rather than an energy resource in

its own right. In fact, gas in a coal seam only contains 1 to 2 percent of the energy capacity of the

coal itself. As a consequence, an estimated 217

thousand cubic feet per day (MCF/D) or 80 billion cubic feet per year (BCF/yr) of methane is

vented to the atmosphere from U.S. mines, ’ without thought of recovery, to increase mine safety.

The search for additional natural gas resources

in the 1970s fostered an interest in economically

recovering this “wasted” gas. By removing this

gas before mining begins and either using it on

site or selling it to the natural gas market, energy

conservation could be combined with increased

mine safety. In addition, it was realized that a potentially large gas resource lies trapped in seams

of coal that will likely never be mined because

of their depth or physical characteristics.

Although it is widely acknowledged that the

coal bed methane resource is large, early economic assessments suggested that it had little potential for economic recovery barring very high

gas prices. More recent evidence from wells pro- .

ducing gas from coal seams at current prices suggests a more optimistic outlook is justified. It appears that in some areas with highly favorable

geology, commercial volumes of gas are recoverable at current prices using existing technologies.

Current production efforts include nearly 100

producing wells drilled by various operators in

Alabama’s Black Warrior Basin, early efforts by

Carnegie Natural Gas Co. and Equitable Gas Co.

in Pennsylvania and West Virginia, a variety of

wells in the San Juan Basin of New Mexico, and

others. z

IV. A. Kuuskraa and R. F. Meyer “Review of World Resources

of Unconventional Gas, ” IIASA Conference on Conventional and

Unconventional World Natural Gas Resources, Luxenburg, Austria,

]une 30-july 4, 1980.

2). L. Wingenroth, “Recent Developments in the Recovery of

Methane From Coal Seams, ” Gas Energy Review, vol. 10, No. 9,

September 1982, American Gas Association.

CHARACTERISTICS OF THE COALBED METHANE RESOURCE BASE

Coalbed methane is defined as natural gas

trapped in coal seams. The location of the Nation’s coal resources and associated methane accumulations are depicted in figure 43. Approximately two-thirds of the resource is located in

the West and Midwest and the remainder is located in the Appalachian Basin.

Methane forms as a byproduct of the coalification process. s With increasing temperatures, the

rank (carbon content) of the coal increases, and

larger volumes of methane and other volatile constituents are produced (fig. 44). As volatiles are

~Coalification: the formation of coal from organic-rich sediments,

under intense heat and pressure.

driven off by the increasing temperatures, the

coal shrinks, giving rise to a pervasive natural fracture system called the “cleat.” Although much

of the generated gas migrates out of the formation, some remains in the coal seam adsorbed

to the coal pore surfaces, and some is trapped

in the pore spaces and fracture system by the

reservoir pressure. In sharp contrast to conventional gas reservoirs, where essentially all of the

gas is trapped in the pores and fractures, the adsorbed gas is the dominant source of coal bed

methane and plays the major role in production.

The volume of adsorbed gas appears to be a function of depth (pressure) and coal rank, as shown

in figure 45. Nevertheless, given the vagaries of

207
208 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Figure 43.—U.S. Coal Regions

SOURCE: Department of Energy.

Figure 44.-Variation of Gas Content by Rank, Temperature

20 Coal rank

170

(338)

220

(428)

270

50 100 150

Yield, liter/kg

200

SOURCE: J. M. Hunt, Petroleum Geochemistry and Geology (San Francisco: W. H. Freeman & Co., 1978) (fig.

5-7, p. 165).
I

Ch. 10—Coalbed Methane ● 209

I 4700

600

200

100

Depth, meters

SOURCES: A G Kim, “Estimating Methane Content of Bituminous Coalbeds

From Adsorption Data,” BuMines RI 8245, 1977 c.f ; G. E. Eddy, C. T.

Rightmure, and C. W. Bryer, “Relationship of Methane Content of Coal

Rank and Depth, Theoretical vs Observed,” SPE/DOE Unconventional

Gas Recovery Symposium, 10800, 1982

the geologic process, methane content in coal

is highly variable from seam to seam and even

within the same seam.

The quality of the gas present in coal seams is

also somewhat variable, but generally is quite

good. The heat of combustion ranges from 950

to 1,050 Btu per cubic foot. The gas has few impurities; carbon dioxide and water vapor are the

primary undesirable components. Sulfur dioxide

and hydrogen sulfide gases are absent even in

the more sulfur rich coals.

Coal in itself is essentially impermeable. Bulk

permeability of a coal seam depends on how

well-developed the cleat is. Generally, there is

a dominant system of vertical fractures, the socalled “face cleat, ” and a less developed system

of vertical fractures perpendicular to the face

cleat, the “butt cleat, ” the nature of the face cleat

is critical to the coal’s production characteristics.

The importance of the natural fracture system,

together with the critical production role played

by adsorbed gas, establishes a close parallel between coal seam methane and the Devonian

shale gas resource.

Many coal seams contain water and thus the

reservoir pressure is partialIy a hydrostatic pressure caused by groundwater. Although in some

cases the water is the original product of the coal

formation process, often the water infiltrates the

coal from the surface or from overlying aquifers.

The presence of this water has profound effects

on gas production from the coal seams.

GAS-IN-PLACE

Existing gas-in-place estimates are summarized Methodologies

in table 56. These range from a low of 68 TCF

to a high of about 850 TCF. Most estimates are

based on the U.S. coal resource; differences arise

from varying assumptions of gas content (volume

of gas per cubic foot or ton) of the coal and criteria for defining coal seams as good targets for

recoverable gas.4 Several of the most recent estimates are discussed in more detail below.

4

These criteria are important because gas-in-place estimates generally consider only gas found in formations that contain potentially recoverable gas.

and Results

National Petroleum Council, Gas Research

Institute, and Kuuskraa and Meyer

Among the more recent studies, the estimates

by the National Petroleum Council (NPC), the

Gas Research Institute (GRI), and Kuuskraa and

Meyer (KM) are very similar in methodology and

in results. The estimated resource in place ranges

from 398 TCF (NPC) to 550 TCF (KM).

All of these studies use the 1974 U.S. Geologic

Survey’s (USGS) coal resource data—an estimate
210 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Table 56.—Coalbed Methane Resource Estimates

Resource in place

Study (TCF)

Department of Energy (1984) . . . . . . . 68-395

Kuuskraa and Meyer (1980) . . . . . . . . 550

National Petroleum Council (1980) . . 398

Gas Research Institute (1980) . . . . . . 500

Federal Energy Regulatory

Commission (1978) . . . . . . . . . . . . . 300-850

Deul and Kim (1978) . . . . . . . . . . . . . . 318-766

Wise and Skillern (1978) ., . . . . . . . . . 300-800

TRW . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72-860

National Academy of Sciences

(1976) . . . . . . . . . . . . . . . . . . . . . . . . . 300

SOURCE: Adapted from AGA Gas Energy Review, September 1982; and C. W.

Byrer, T. H. Mroz, and G, L. Covatch, “Production Potential for Coalbed Methane in U.S. Basins,” SPE/DOE/GRl Unconventional Gas

Recovery Symposium, 12832, 1984.

of “minable” coal resources—as the basis for

their estimates. The USGS assessment is broken

down into identified and hypothetical resources

at depths less than 3,000 ft and hypothetical resources at depths greater than 3,000 ft. The identified resources are further broken down by coal

rank—anthracite, bituminous, subbituminous,

and lignite. For the methane estimates, Kuuskraa

and Meyer have subdivided the hypothetical resources by rank in approximately the same proportion as they occur in the identified resources.

The NPC, GRI, and KM analyses then multiply

the coal resource by an assumed gas content to

determine the gas resource in place. All assume

that gas content varies with rank and depth.

Assumptions are compared in table 57. Although

the KM estimates disaggregate the gas content of

coal to a greater extent than the GRI or NPC estimates, their assumed gas contents, averaged, are

essentially the same as the GRI and NPC values.

Consequently, the increased detail in their estimate does not contribute to a substantial difference in the calculated gas-in-place.

The NPC estimate excludes all coal resources

at depths less than 300 ft, assuming these coal

seams contain essentially no recoverable gas. The

exclusion of shallow coals appears reasonable because the lower pressures may have allowed any

gas originally contained in shallow seams to have

escaped to the surface. However, the NPC also

assumed that a full third of the identified and

hypothetical coal resource between O and 3,000

ft occurs above 300 ft; also, the NPC apparently

assumed that the bulk of this shallow coal is bituminous, with high gas content. Thus, the NPC

analysis excludes from consideration a large percentage of the higher-gas-content coal. This conclusion appears to be the primary reason that the

NPC estimates are 100 to 150 TCF lower than the

GRI and KM estimates.5 The exclusion appears

overly pessimistic because it is the lower rank

5,41though G RI also appears to exclude the coal resource at less

than 300 ft from their gas-in-place calculations, in fact their total

coal resource base is equal to the USGS coal resource base (3,968

X 109 tons) from O to 6,000 ft.

Table 57.-Coal Resource and Gas Content Assumptions

Coal rank

Zero to 3,000 ft Greater than 3,000 ft

Kuuskraa & Meyer Kuuskraa &

<1,000 1,000-3,000 >3,000 NPC GRI Meyer NPC GRI

A) Coal resource assumptions (billion short tons):

Anthracite (A) . . . . . . . . . 845 739 1,584 46 60

Bituminous (B) . . . . . . . . 1,001 1,300

A + B . . . . . . . . . . . . . 845 739 1,584 1,047 1,360

Subbituminous . . . . . . . . 538 470 1,008 1,137 1,520

Lignite . . . . . . . . . . . . . . . 538 470 1,008 504 700

Total . . . . . . . . . . . . . . . 3,600 2,688 3,580

Total (all depths) . . . . 4,000 3,076 3,968

B) Gas content assumptions-cubic ft/ton:

Anthracite and

bituminous . . . . . . . . . 150 250 197a

200 200

Subbituminous . . . . . . . . 60 100 79a

80 80

Lignite . . . . . . . . . . . . . . . 30 50 39a40 40

176

112

112

400 388 388

500 200 200

200 200 200

100 200 200

aWeighted average.

SOURCE: Office of Technology Assessment.
Ch. 10—Coalbed Methane . 211

(thus lower gas content) coals that tend to occur

at shallower depths.

Department of Energy (DOE) —Methane

Recovery From Coalbeds Project

The DOE Coalbed Methane Basin analysis is

the first attempt to estimate the gas-in-place on

a basin-by-basin level. The DOE approach targets

the most likely gas-producing coal seams in each

coal-bearing basin. Wherever possible, they have

established a range of gas contents for the targeted coals in each basin and calculated a gasin-place. Data were obtained from a variety of

producing wells and test wells. They have completed studies of 14 basins with an estimated total

gas-in-place of 68 to 396 TCF. Results for the 14

basin analyses are summarized in table 58. The

high end of this range is essentially compatible

with earlier estimates; the low end is very conservative, being the product of lower estimates

of both target area and gas content.

DOE appears to have made a number of subjective judgments in delimiting its target areas.

For example, DOE selected for inclusion in the

resource base only those coal seams with high

reported gas contents, high rank, and thick cumulative sections, without setting any quantitative

criteria for the selection. In addition, assessments

of several basins have not been completed. Thus,

its estimate is conservative in terms of total gasin-place. Because it focused on formations that

are the most likely to contain recoverable gas,

however, the gas-in-place estimates may represent a valid basis for an estimate of the technically

recoverable resource.

Uncertainties

The wide range of gas content in coal seams,

seen clearly in table 58, is the primary factor contributing to uncertainty in gas-in-place estimates.

The range in the DOE gas-in-place estimates—

over a factor of 5—may not be an unreasonable

reflection of the true uncertainty at this time. The

level of uncertainty will only be reduced as more

data are obtained on gas content of specific coal

seams. However, the impetus to obtain more

data may only come as producers move to develop these resources.

The other major factor contributing to uncertainty is the lack of data on coal resources at

depths greater than 3,000 ft. The USGS coal resource estimate is limited to potentially minable

seams, and may substantially underestimate the

gas-bearing resource. Very little information is

available on the rank, reservoir characteristics,

Table 58.— DOE Gas-In-Place Estimates

Gas contents Estimated total gas-in-place (TCF)

Basin (CF/ton) Minimum Maximum

Eastern:

Northern Appalachian , . . . . . . . . . . . . . . . . . . . . . . 30-420 61.0

Central Appalachian . . . . . . . . . . . . . . . . . . . . ... , . 125-400 10.0 48.0

Illinois , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30-150 5.2 21.1

Warrior . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-600 11.0

Arkoma . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70-700 1.6 3.6

Richmond . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ND 0.7 1.4

Western:

Piceance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 -410+ 30.0 110.0

Powder River 1.45 5.9 39.4

Greater Green River . . . . . . . . . . . . . . . . . . . . . . . . . 13-539 0.2 30.9

San Juan. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20-135 + 1.8 25.0

Western Washington . . . . . . . . . . . . . . . . . . . . . . . . 32-86 3.6 24.0

Raton Mesa . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-492 8.0 18.4

Wind River . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . a

0.5 2.2

Uinta , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-443 0.2 0.8

Total . . . . . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . . .

.—

67.7 395.8

ND—no data

aAssumes deep coals will contain some gas

SOURCE. C. W Byrer, T H. Mroz, and G L Covatch, “ProductIon Potential for Coal bed Methane in U.S Basin s,” SPE/DOE/GRI Unconventional Gas Recovery Symposium, 12832, 1984
212 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

and gas content of the deep and unminable coals.

Because deep coals are likely to be of higher rank

and have higher gas content than shallower coals, b

gas-in-place estimates that assign to the deep

coals the same coal rank distribution found in the

shallow coals may be too conservative. However,

very low permeabilities, particularly in anthracites, may exclude some of these coals as

sources of economically recoverable gas resources, absent significant advances in well

stimulation technology.

‘Deeper coals are more likely to have been exposed to high

temperatures, which in turn influence rank and gas content. See

fig. 44.

To the extent that the deep coal seams are not

considered to be viable targets for mining, many

of the legal and institutional constraints to producing methane from minable coal seams will not

be applicable to these deep seams. This may increase their attractiveness to gas producers. Refining the estimates of the deep gas resource, along

with incorporating improved gas content data

from the newly drilled basins, are the most important tasks remaining in establishing a more

credible estimate of the coal bed methane gasin-place.

PRODUCTION METHODS AND TECHNOLOGY

Production Methods

Producing coal seam methane is considerably

different from producing natural gas in conventional reservoirs. Production rates in conventional

reservoirs are primarily a function of permeability,

whereas in coal seams, methane production is

also dependent on the rate at which the adsorbed

methane diffuses into the fracture network, or

“cleat.” If the permeability of the coal’s fracture

network is very low, then permeability will be the

factor controlling production rates. However,

when the fracture network is relatively permeable

and is connected to the well bore, or when the

fracture network is not well-developed (and thus

the surface area for diffusion to take place is

limited) production is more likely to be limited

by the rate of diffusion of the adsorbed methane

into the fracture network.

These different limiting factors have important

implications for the probable effects of fracturing. If permeability is controlling, fracturing should

increase production by enhancing the flow path

from the fracture network to the wellbore. If diffusion is controlling, however, fracturing is unlikely to greatly affect production because it cannot add greatly to the surface area available for

resorption, and any increased permeability it creates will not add to production.7

7

Lewin & Associates, Inc., Enhanced Recovery of Unconventional

Gas, Vo/urne ///: The Methodology, U.S. Department of Energy report HCP/T2705-03, February 1979.

It is necessary to reduce the pressure in the fracture systems in order for gas to desorb from the

coal and be available for production. Figure 46

shows how reducing the pressure will reduce the

volume of gas adsorbed. The pressure/gas volume curve, which is typical of coal seams, is

strongly nonlinear: a unit pressure drop has far

less effect on resorption at high pressures than

it does at low pressures. As a result of this nonlinearity, there may be little or no gas production until the pressure in the formation is reduced

to the level where the rate of resorption per unit

pressure drop begins to accelerate.

Because the reservoir pressure generally is a

hydrostatic head associated with the groundwater

in the coal seam, reducing the reservoir pressure

means dewatering, i.e., pumping the water out

of the seam. Water removal also increases the

relative permeability of gas in the fracture network, allowing more gas to flow to the well bore.

This also tends to reduce the pressure in the formation, further increasing the ability of gas to

desorb from the coal,

As pumping the water from a well commences,

the reservoir pressure is first reduced in the immediate vicinity of the wellbore, with the area

of the pressure drop spreading overtime. The rate

of gas production generally will increase with

time as more and more area achieves the large

pressure drop necessary to cause rapid resorption. This production increase with time is in
Ch. 10—Coalbed Methane ● 213

Figure 46.— Methane Gas Adsorbed on Coal as a

Function of Pressure

22

Maw Lee Coal

18

t A

16 L

B

14 -

12 -

c

10 -

8 -

6 -

4

SOURCE: S. C Way, et al , “Role of Hydrology in the Production of Methane From

Coal Seams,” Quarterly Review of Methane From Coal Seams Tech.

nology, vol 1, No. 2, August 1983, Gas Research Institute,

sharp contrast to the more normal production decline experienced in conventional gas wells. s

This model of gas production from coal seams

may not apply to single, isolated wells. In coals

with highly permeable, interconnected fracture

systems, the effect of pumping over time will

draw the pressure down in small increments over

a wide and expanding area with little change in

the pressure distribution near the wells.9 Because —————

as. C. Way, et al,, “Role of Hydrology in the Production of Methane From coal Seams,” Quarter/y Review of Methane From Coa/

Seams Techfto/ogy, vol. 1, No, 2, August 1983, Gas Research institute.

9“New Advances in Coalbed Methane, ” Intercomp Resource Development & Engineering, Inc. (appears as app. C in K, L, Ancell,

Coa/ Degasification, An Unconventional Resource, Dowdle Fairchild & Co., Inc., Houston, TX).

resorption is strongly nonlinear, favoring a large

pressure drop, the areal extension of a moderate

pressure drawdown is likely to yield little additional gas. The solution to this problem is to

somehow bound the drainage area of the wells

so that larger pressure drops occur over time.

One method is to drill a closely spaced pattern

of wells and pump them simultaneously, deliberately creating interference between adjacent

wells. Such interference will effectively halt or

bound the areal spread of pressure drop from a

single well. This practice is in sharp contrast to

normal practice in conventional gas fields, where

close spacing and well interference are avoided

because they reduce average recovery per well.

Figure 47 shows pressure drawdown curves for

a group of three wells. The broken lines represent the pressure curves associated with each well

in isolation; the solid lines are the actual pressure

curves that result from the three well system, reflecting the interference effects of the wells on

each other. Close spacing of wells allows more

of the formation to achieve the sharply reduced

pressures necessary for maximum resorption and

production of gas. The advantage of closer spacing is particularly apparent when water can infiltrate the formation. Pumping from isolated wells

may simply be unable to remove the water faster

than it can infiltrate, and thus such pumping will

not successfully dewater the formation and produce the gas; simultaneous pumping from a

group of wells generally can “outrun” the infiltration. In a formation where water infiltration is a

problem, the rate of pumping also becomes critically important, since a higher pumping rate may

be necessary to outrun the infiltration and successfully draw down the pressure.

One well spacing pattern uses exterior wells to

produce water and provide interference, while

interior wells produce most of the gas.10 Simulated production from this configuration predicts

consistent high flow rates over a 20-year term,

as shown in figure 48.

Iolbld ,
214 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Figure 47.— Pressure Drawdown Curves for Three Wells in a Line

Q, Q2 Q3

Impermeable

SOURCE: S. C, Way, et al., “Role of Hydrology in the Production of Methane From Coal Seams,” Quarter/y Review of Methane

From Coal Seams Technology, vol. 1, No. 2, August 1983, Gas Research Institute.

Figure 48.— 20-Year Production Prediction for Gas and Water Production From a Well Pattern

Designed to Allow Rapid Water Removal

History I 20-year prediction Time, days

SOURCE: INTERCOMP Resource Development and Engineering, Inc.
Ch. 10—Coalbed Methane 215

Technologies

Increasing production, at least from shallow

wells, does not depend primarily on the development of new technologies. The primary target

for improved technologies are the deep coal

seams. There we need better reservoir characterization techniques. New drilling and completion

techniques also are required in deep wells where

drilling fluids or cements used for completions

are likely to cause extensive formation damage.

Stimulation technologies also have not been

highly successful in the lower permeability deep

coal seams.

Drilling

Most current production of methane from both

minable and unminable coalbeds uses vertical

wells drilled through the coal seam. Major problems involve extensive formation damage induced by drilling fluids and by cements used to

complete the holes. In shallower wells, air or

water drilling and open hole completions11 can

counteract these problems. Improved production

from multiple completions12 and from deep coal

seams where open hole completions may not be

practical will require new technology developments. Current research programs sponsored by

the Gas Research Institute are addressing these

problems.

Another problem inherent in vertical drilling

is the difficulty of intersecting the vertical fracture network, or face cleat. Well stimulation may

be required to connect the wellbore with the natural fracture system and thus provide a pathway

for gas to flow to the well. Another remedy is to

slant or deviate the wells from the vertical to intersect the face cleats. Ideally, the well can be

drilled parallel to the seam, as sketched in figure 49. This technology requires considerable improvement and cost reductions to be considered

a realistic option for coal seam methane production. Keeping the wellbore in the coal seam is

quite difficult, and drilling costs are significantly

1‘That is, completing the well by perforating the gas-bearing rock

formation without first casing and cementing the wellbore In the

vicinity of the formation.

1.2That Is, pr~ucing from multiple seams with a single well.

higher than for vertical wells. Dewatering deviated wells may also be a problem.

In minable coal seams, horizontal wells may

be used. These wells usually are drilled from

within the mine workings, perpendicular to the

face cleat, and generally have high rates of gas

drainage. The gas recovered from the boreholes

is pumped through a separation unit to remove

associated water before the gas is piped out of

the mine.13

The main difficulty in drilling horizontal holes

is keeping within the coal seam. Consolidated

Coal Co. (Consol) has developed a mobile horizontal drilling system with special features for

methane production. Three- to four-inch diameter holes may be drilled to lengths greater than

2,000 ft using a guidance system to keep the bit

within the seam and methane is piped out through

closed-loop plastic pipes.

Horizontal wells may partially escape dependence on the mining operation with a system that

uses horizontal holes drilled radially from the bottom of a central vertical shaft. However, the expense of the shafts may dictate that the whole

operation can succeed financially only if the

shafts can be re-used later on for the mining operation; thus, it is not clear that this drilling system

actually will sever the tie between mine and gas

recovery operation. This method has not yet been

tried in the United States.

Stimulation

Where low permeabilities area problem, stimulation is used to increase the flow of gas to the

well by increasing the area of the natural fracture system in contact with the wellbore. Hydraulic fracturing is the most common stimulation

technique used. As with such treatments in the

——-. 13A major (but no nt e ch n i c al ) roadblock tO substantial prod uction of methane from these types of horizontal boreholes is that production may be dependent on the mine operation, If the mine were

to close, the methane recovery operation might also be forced to

cease. For example, at Kerr McGee’s Choctau Mine i n the Arkoma

Basin, the coal seam methane production operation was completely

set up, equipment installed, and approvals acqulreci when the mine

was closed for lack of a coal market, Financing for a methane

recovery project that is dependent on mine operation will tend to

be difficult to obtain.
216 U.S. Natural Gas Availability: Gas Supply Through the Year 2000

SOURCE: Gas Research Institute.

Devonian shales, the most widely used fracturing fluids are nitrogen foam and water-based gel.

A sized proppant may be included to hold open

the newly formed fractures. The amount of each

ingredient used depends on the fracturing fluid

pressure required, the coal seam thickness, the

fracture length desired, and the cost. When the

fluid injection is completed, the induced pressure

is released and the well prepared for production.

The effects of hydraulic fracturing may be entirely different in coals than in sandstone reservoirs. An induced fracture in sandstone will typically extend outward at substantial length from

the well bore. Coal formation fractures are generally shorter and wider than sandstone fractures.

The difference is attributed to the plasticity of the

coal and dissipation of the compressional energy

into the cleat system. ’4

Several problems may be encountered in stimulating coalbed wells. One is the tendency for

proppant material to flow back into the well bore

and create pump malfunctions during dewatering. Another problem is orienting the fracture to

intersect rather than parallel the planes of the vertical fractures, or face cleat, in order to intersect

as many fractures as possible. This may be difficult because the original stress field in the coal

——

14M. G. Doherty, “Methane From Coal Seams, ” International

Conference on Small Energy Sources, Los Angeles, CA, Sept. 9-18,

1981.
Ch. 10—Coalbed Methane ● 217

clearly favored fracture directions parallel to the

face cleat. A third problem, pertaining to minable seams, lies in containing the fracture within

the seam. Some mine operators feel that fracturing can cause structural damage to the roof rock,

increasing the potential for mine collapse. Ongoing work by the U.S. Bureau of Mines is attempting to evaluate the extent to which this concern

is valid. 15

15M A Trevits, M. E. Hanson, and V. L. Ward, ‘‘Methane Drain- . ,

age: Identification and Evaluation of the Parameters Controlling induced Fracture Geometry, ” SPE/DOE Unconventional Gas Recovery Symposium, May 16-18, 1982.

RECOVERABLE RESOURCES

The coalbed methane resource base is large

but, like the other unconventional resources, the

recoverable portion is significantly less than the

gas-in-place. Economic and technological conditions are the primary factors governing the

amount of the resource that will contribute to

future supply. Other factors, such as legal and

environmental issues, also are likely to influence

coal bed methane production, particularly from

minable coal beds. Even without the hard-topredict effects of these other issues, however, the

uncertainty associated strictly with technical

issues is high. The NPC, in describing its estimates

for the recoverable gas resource, calls them “a

qualified and educated guess, ” and “nothing

more than an order-of-magnitude projection based

on current information."16 Although the scientific understanding of coal bed methane produclbNdtiO~dl Petroleu M COU ncil, Unccmventiona/ Gds $XJfCe5: COA/

Seams, June 1980.

Pumps

Water removal can in general be accomplished

with existing pumping technologies, but the large

amount of water that is produced during dewatering is a strain on pumping equipment and frequent maintenance is often required. pumps are

also apt to become clogged with the coal fines

remaining in the well after drilling. Dewatering

deeper wells may require the development of

larger capacity pumps. Nevertheless, solutions to

these problems are more a matter of refinement

of existing technology than radical innovation.

AND PRODUCTION POTENTIAL

tion has improved in the last 4 years, no estimates

of the economically recoverable resource have

been made since the 1981 GRI estimate.

Methodologies and Results

Estimates of the recoverable resource base

have been made by the NPC (1 980), Kuuskraa

and Meyer (1 980), and GRI (1 981). A variety of

different economic and technology assumptions

were used to obtain the estimates shown in table

59.

National Petroleum Council17

[n the NPC study, recoverable resources were

calculated by identifying that portion of the resource that would yield sufficient production per

well to cover the costs of an “average” well (with

—.—.—

171 bid.

Table 59.—Comparison of Recoverable Resource Estimates

Technically or economically

recoverable gas (TCF) Assumptions

KM . . . . . . . . . . . . . 40-60 30-45°/0 recovery of target resource of 135 TCF, no price constraints, but

recoverable resource limited to bituminous seams >3.5 ft thick,

subbituminous seams >10 ft thick

NPC . . . . . . . . . . . . $2.50 $5.00 $9.00 Production costs define minimum production levels,

5.0 25 45 10%\o ROR which in turn define minimum economic thickness at 3

2.5 20 38 150/0 ROR MCFIDlft (bituminous), 1,2 MCF/D/ft and 0.6 MCF/D/ft

2,0 17 33 200/0 ROR (subbituminous and lignite, respectively) Gas is used

onsite,

GRI . . . . . . . . . . . . $3.00 $4.50 $9.00 Expert judgement

10-30 15-40 30-60 Existing-advanced technologies

SOURCE Off Ice of Technology Assessment

38-742 0 -85 - 1 5
218 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

a depth of 3,000 ft, 12-year well life, assumed 10

percent production decline rate, and 90 percent

success rate). This was done by the following

method:

1.

2.

3.

Using county-by-county coal resource estimates, a distribution of the coal-in-place resource according to seam thickness was constructed for each grade of coal. The distribution for bituminous coal is shown in figure

50 as a plot of cumulative coal-in-place v.

minimum total seam thickness.

By examining data on production rates per

foot of seam thickness for existing wells, values of 3 MCF/D/ft (bituminous), 1.2 MCF/D/ft

(subbituminous), and 0.6 MCF/D/ft (lignite)

were estimated for the production rates per

foot from the coal resource in place. Then,

for each grade of coal, minimum total seam

thickness was converted to minimum “per

well’) production rate. This rate can, in turn,

be converted into minimum gas price necessary to pay for the well.

It is assumed that gas recovery will be 50 percent of the total gas-in-place in coal seams

satisfying the minimum thickness criteria,

and that a random 10 percent of the coalin-place will not be available for drilling.18

——.— 16Neither of these values are further substantiated i n the report.

Figure 50.— Estimated Distribution of Bituminous

Coal by Seam Thickness

0 10 20 30 40 50 60

Minimum total seam thickness (feet)

SOURCE: National Petroleum Council.

4.

Using these values and the assigned values

of gas content (200 cubic feet per ton for

bituminous, 80 CF/t for subbituminous, and

40 CF/t for lignite), cumulative coal-in-place

can then be converted to recoverable gas resource.

The final result is a relationship between the

recoverable resource and gas price. The estimated recoverable gas resources for three

gas prices, assuming the gas to be used onsite without compression, are shown in table

59.

The report does not give results for the case

where the gas is scrubbed, compressed, and

gathered for delivery to a pipeline. However,

comparison of plots of gas price v. necessary production rates for onsite use and pipeline sales

(figs. 4 and 5 in the NPC report) imply that pipeline delivery will add approximately $1.00/MCF

to production costs. The actual effect on producer incentives is not clear, however. On the

one hand, it is not uncommon for pipelines to

pay for gathering and compression costs, which

reduces the gas price required by producers to

make a profit. On the other hand, for existing

coal bed methane projects, initial compression

and gathering cost generally have fallen on the

producers. 19

Kuuskraa and Meyer20

A large portion of Kuuskraa and Meyer’s gasin-place estimate of 550 TCF was recognized as

being within coal seams that were too thin or

whose gas content per unit volume was too low

to exploit. Assuming the favorable resource to occur only in bituminous coal seams greater than

3.5 ft thick and sub-bituminous seams greater

than 10 ft thick, Kuuskraa and Meyer estimated

that about 135 TCF of methane is present in the

most favorable coal seams. The technically recoverable resource was determined to be 30 to

45 percent of the favorable resource, or 40 to 60

TCF, based on calculations of the amount of gas

Iqvello KUUSkraa, LeWin & Associates, Inc., persona! cornrnuni -

cation, 1984.

ZOV. A. Kuuskraa and l?. F. Meyer, ‘‘Review of world Resources

of Unconventional Gas, ” IIASA Conference on Conventional and

Unconventional world Natural Gas Resources, Luxenburg, Austria,

June 30-)uly 4, 1980.
Ch. 10—Coalbed Methane 219

that would desorb from the coal.21 The KM estimate does not specify price constraints, but the

thickness limits used to define the favorable resource do appear to imply a price range. Using

basically the same methodology, a predecessor

Lewin & Associates report22 projected that 11 ft

thick subbituminous seams in Colorado could be

economically developed for gas production at

$3.00 to $4.50/MCF in 1977 dollars, or about

$5.00 to $7.00/MCF in 1983 dollars. Consequently, it seems likely that most of the 40 to 60 TCF

of technically recoverable gas could be economically recovered at gas prices of $5.00 to $7.00/

MCF (1983$).23

Gas Research lnstitute24

GRI estimated recoverable gas resources by

polling experts to determine how much gas they

thought was present at various price levels, using

existing or advanced technologies. The results of

this poll are given in table 59.

Estimate Comparison and Uncertainties

In general, the estimates of recoverable resources are quite similar, with the exception of

the pessimistic NPC estimate for moderate priced

gas (2.5 to 5.0 TCF at $2.50/MCF in 1979$ or

$3.35 in 1983$). For high-priced gas, in the range

of $5.00 to $10.00/MCF (1983$), a range of 20

to 60 TCF of recoverable gas would appear to

agree well with all three studies.

In OTA’s opinion, however, this apparent

agreement should be viewed with caution. Of the

three unconventional resources examined in this

report, coal seam methane has the least production experience and the poorest data base to

guide recoverable resource estimates. As a result,

the two studies that used an analytical approach

to estimating the recoverable resources—NPC

and Kuuskraa and Meyer—use very broad assumptions and may be subject to considerable error,

—————

“ lbld.

zzLeWln & Associates, Inc., frrhdr?ced I?ecuvery Of ~nCOflk’enfiOnd/

(23s, op. Cit.

Z]Confl rmed by Vello Ku uskraa, Lewin & Associates, Inc., personal communication, 1984.

z~Gas Research I nstltute, Position Paper; uflconv’ent/ona/~atural Gas, May 1981.

The NPC report has made several assumptions

that appear vulnerable to error. For example, the

assumption of a 50 percent average recovery of

the gas-in-place appears to be unrealistically high.

Seams in the Black Warrior Basin in Alabama currently being developed by U.S. Steel do appear

to have a potential recovery of about 50 percent, 25 but this area is one of the best methane

prospects at present. A second assumption, that

historic values of production rates per foot of

seam thickness can be used to project future production rates, is probably too pessimistic. The

NPC report notes that they had been told that

future close-pattern drilling will be more productive than existing wells, which for the most part

are isolated and do not represent efficient gas

recovery. Recent performance data and research

resuIts appear to verify this production behavior

(see discussion on Production Methods, above).

Another problem with the use of the historic data

is that the values of production per foot of seam

thickness vary widely and randomly both between and within separate coal beds. In the limited sample obtained by the NPC, production varied between O and 12.3 MCF/D/ft.26 This wide

variation implies that the use of an average can

introduce substantial error into the calcuIation.

The NPC also has assumed that a well’s gas production will experience an exponential decline

from its initial flow rate. In reality, flow rates often

have been observed to increase over a period of

time as water drawdown increases the reservoir

rock’s relative permeability to gas and decreased

pressure increases resorption from the coal surfaces. Figure 51 shows plots of production rates

over time to illustrate this phenomenon.

The NPC calculations of minimum coal seam

thicknesses for economic gas recovery at various

prices appear to be conservative in comparison

to their own data. For gas prices in the $2.50 to

$5.00 (1 979$) range for onsite use (and, presumably, about, $3.50 to $6.00 for pipeline sale),27 the

estimated minimum coal seam thicknesses for

zJVello Kuuskraa, LeWin & Associates, I nc. , personal commu n Icatlon, 1984.

zbNational P@roleum COU ncil, Uncon\/ent;ona/ Gas !% LJrce5: COc~/

Seams, june 1980, table 7.

zTBecause Plpel i ne sale may require the producer to incur costs

for compression, liquids removal, contaminants removal, etc.
—

220 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Figure 51 .—Well Production Histories in San Juan and Other Basins
Ch. 10—Coalbed Methane ● 221

bituminous coals range from 45 to 20 ft, corresponding to production levels of 135 to 60

MCF/D. The NPC data on actual wells, however,

indicate that seam thicknesses in all cases examined were less than 25 ft and most were less than

10 ft, with production rates in all cases less than

70 MCF/D. Although the sales price of the produced gas and the profitability of the wells is not

known, presumably some of these wells are profitable, and it does not seem likely that the prices

paid for this gas could be much above the given

range. This implies that the cost of these wells

must have been lower than the NPC’s calculated

average well costs.

On balance, the examination of uncertain assumptions in the NPC study appears to indicate

that their analysis may have been overly pessimistic.

The Kuuskraa and Meyer analysis differs substantially from the NPC analysis, especially because it calculates recovery efficiency from an

analysis of diffusion from the fracture network

rather than assuming a recovery efficiency. This

exposes the KM analysis to some different kinds

of uncertainties than those encountered by NPC.

In particular, as noted in the earlier Lewin report, 28 the resuIts are extremely sensitive to

assumptions about the fracture intensity in the

seams and the diffusion constant. For example,

for Western coals, a change in the spacing between vertical fractures, from 1- to 5-ft intervals,

reduces the 10-year recovery efficiency from 30

to 2 percent, essentially eliminating the economic

recovery potential from these coals. Fracture intensity is not well-documented, especially for

deeper coals.

Another potential problem with the KM analysis is that it is uncertain whether or not its simple diffusion model adequately represents the actual physical production mechanism in the coal

seam. For example, the model and associated assumptions imply uniform production behavior

across the seam, whereas in reality production

behavior in existing coal seam methane projects

(i.e., the Black Warrior development) has fluctuated widely from well to well .29 This implies that

we do not yet fully understand the gas production mechanism.

Because of the substantial remaining uncertainties and the lack of recent economic analyses that

could take into account the latest understanding

of the nature of the coal seam methane resource,

OTA is reluctant to project a new estimate of the

recoverable resource, However, in our opinion

the NPC estimates for moderate prices–e.g., 2.5

TCF (at 15 percent rate of return) for gas prices

of $2.50/MCF in 1979$ ($3.35/MCF in 1983$)—

are overly pessimistic, and are based on past experience that does not reflect recent production

capabilities associated with improved operating

practices such as closer well spacing. What is critically needed is a reevaluation of the economics

of recovering this resource given our better understanding of the resource and improved production methods. Information that would help

such an estimate is a disaggregation of the resource base based on gas content as well as seam

thickness. The data collected for the DOE basin

analysis may be sufficient to provide the basis for

a new analysis along these lines.

Annual Production Estimates

Both NPC and GRI calculated annual production estimates. NPC estimated annual production

through the year 2000 for both production from

vertical wells and from shafts with horizontal

holes. The vertical well development scenario extends over a drilling period of 18 years with

recovery of the resource for 28 years. The development schedule requires beginning with 80 rigs

the first year and adding 80 rigs in each of the

next 7 years, with each rig drilling 45 producing

wells per year. The resulting annual production

estimates are included in figure 52.

For production from shafts with horizontal

holes, the NPC assumed that 50 shafts would be

drilled in the first year, with a 20-percent increase

in the rate of adding new shafts every year, At

this drilling rate, a 22-year program would be required to recover the total projected gas resource

29vel[o Ku Uskraa, l-e~~,l n & Associates, Inc., personal com m u n ication, 1984.

38-742 0 -85 - 1 6
222 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Figure 52. —Annual U.S. Production Rates of

Coalbed Methane as a Function of Time—

Vertical Wells

Incremental price ($/MMBtu) at 10°/0 ROR

o 3.50 5.00 7.00 9,00

1985 1988 1992

Year

SOURCE National Petroleum Council

in a period of 35 years. The annual

rates are depicted in figure 53.

996 2000

production

GRI used the recoverable resource estimates

acquired from the poll and further assumed production and drilling rates. Production rates were

estimated at 30 and 100 MCF/D for existing and

advanced wells, respectively. The number of

wells drilled per year was assumed to be 200 from

1983 to 1986 with a 10 to 15 percent increase

per year thereafter. Utilizing the resource base

as a limit, annual production estimates were calculated. The 1990 and 2000 production estimates

are included in table 60.

The NPC study assumes that the gas price will

increase steadily to $9/MCF (1 979$), Given current and expected future market conditions, this

assumption appears unrealistic. On the other

hand, if, as it appears, a majority of the recoverFigure 53.- Annual U.S. Production Rates of

Coalbed Methane as a Function of Time—

Horizontal Wells

Incremental price ($/MMBtu) at 10°/0 ROR

o 2.50 3.50 5.00 7.00

3.0

1.0

0.5

0

1985 1988 1992 1996 2000

Year

SOURCE: NPC.

able resource can be recovered at prices on the

order of $5/MCF (1979$), and if little is required

in the way of technologic advances, increasing

levels of production might still be expected. What

is required is an increased level of producer

interest-interest which at present is constrained

by questions of ownership, mine safety, environmental concerns, and other institutional considerations. Some of these issues are discussed

below.

Legal Constraints

Court decisions to date have attempted to resolve several legal questions associated with coal

seam methane production, but without much

success. Previous litigation has centered on the

issue of resource ownership and whether the

methane is a resource in its own right or an intrinsic part of the coal. The U.S. Steel v. Hoge
Ch. 10—Coalbed Methane ● 223

Table 60.–GRI Coalbed Methane Annual Production Estimates (TCF)

1990 2000

Market price Existing Advanced Existing Advanced

(1979$/MCF) technology technology technology technology

$3.00 . . . . . . . . . . . . . . . . . 0.06 0.22

$4.50 . . . . . . . . . . . . . . . . .

0.29 0.95

0.07 0,23 0.35 1.2

$6.00 . . . . . . . . . . . . . . . . . 0.07 0.24 0.42 1.4

SOURCE GRI

case of March 1980 set a precedent on both these

issues. Although lower court decisions determined that methane is a natural gas occurring in

coal, and that the land owner owns the methane until the gas rights are released, in December 1983 the Pennsylvania Supreme Court reversed that decision, remanding ownership to the

coal owner.

The recovery of coalbed methane on Federal

coal lands also is burdened with unanswered

legal questions. The current position of the Solicitor’s Office of the Department of Interior is that

ownership of a coal lease does not include rights

to the coal bed gas, but that a reservation of gas

does,30 and that coalbed gas is leasable under the

oil and gas leasing provisions of the Mineral Leasing Act. This position has not been tested in the

courts, however. Drilling permits for coal seam

methane recovery have been issued, although

administrative delays are a problem.

Environmental Constraints

The primary environmental issue associated

with coal seam methane production is disposal

of the water produced with the gas in those coal

seams characterized by high water contents.

Since dewatering is a primary production requirement, large volumes of water must be pumped

from the subsurface. The quality of the water

varies from slightly acidic to slightly alkaline

depending on the site location. The environmental regulations of the State determine whether the water must be treated, and such decisions

will influence the economic viability of the recovery project.

3f3A detailed summary of the legal situation IS presented In j. H.

Kemp, “Coalbed Gas: Recent Developments in the Ownershlp and

Right to Extract Coalbed Gas, ” The LJdmafl, November 1982.

Institutional Barriers

There are other factors that will influence the

contribution of coal bed methane to future

supply. Institutional barriers characteristic of the

coal industry will deter or possibly preclude production in some instances. A primary institutional

barrier is the lack of interest exhibited by the coal

companies. According to industry analysts, since

the companies’ primary interest is coal mining,

they tend not to want to become involved in the

more long-term nature of the methane production industry, particularly when the economics

are marginal. In

v

estment incentives may be required to create interest in producing the methane rather than venting. Alternatively, if new analyses demonstrate a real economic advantage to

producing gas prior to mining, the coal industry

may become more interested in overcoming

problems created by the mining schedule. One

problem with degassing prior to mining is the

short time period between the beginning of gas

production and the mine opening that has often

been allowed. Numerous wells are required, incurring high capital costs which cannot be recouped without a longer production period.

Another institutional barrier to production is the

strong concern with worker safety associated with

coal mining. The issue of whether stimulation

causes unacceptable damage to the mine ceiling has not been resolved. The Bureau of Mines

initiated a program at four sites to determine the

effects of stimulation. Due to various problems,

however, work was completed at only one site.

The site evaluation indicated that there were no

adverse effects on the mining operation, but the

limited extent of the test precludes extrapolation

of the results to other sites. No firm evidence exists to link stimulation effects to mine collapse at

numerous other operating facilities, but until the
224 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

technique is proven not to cause damage, many able resources, imply that the current production

companies will be reluctant to invest. projections are not adequate, and effort should

be focused on establishing a new, more scienIn OTA’s opinion, the above uncertainties, tifically based estimate of the potential contribucoupled with the technical and economic uncer- tion of coal seam methane to future U.S. gas

tainties mentioned in the discussion of recover- Supply.
Appendixes
Appendix A

Calculation of Additional Reserves From

Increased Gas Recovery in Old Gasfields

OTA calculated the effects of higher gas prices on

gas recovery in “old” gasfields by modifying a previous analysis of those effects conducted by the Shell

Oil Co.1 The OTA analysis is discussed in detail in a

recent OTA staff memorandum and is summarized

here.

The analysis focuses on the expansion of “old gas”

reserves, which are defined here as all reserves that

do not qualify for “new natural gas” status under the

Natural Gas Policy Act (NGPA). In general, old gas

is gas in reservoirs that were discovered (and reserves

reported) prior to about mid-1977; however, the precise boundaries are more complicated than this.

Shell’s Analysis

The Shell study assumed that all old gas would remain at low prices under the NGPA and would rise

to $3.50/MMBtu, the assumed free market price,

under a price decontrol policy. Shell calculated the

effect of a $3.50 gas price on recovery in the Nation’s

old gasfields by the following method:

1. Calculate the Nation’s “responsive reserves,” that

is, the old gas reserves that might grow if their prices

go up. Some reserves, such as Alaskan North Slope

gas, gas dissolved in oil, and, to a lesser extent, gas

in water-drive reservoirs will not respond much to a

gas price increase and were not included in the analysis of reserve growth. For example, gas dissolved in

oil is responsive primarily to oil prices, because the

value of the oil in the reservoir far outweighs the value

of the gas. If oil prices go up, more oil will be produced and thus more gas will be co-produced with it.

Shell’s estimate of responsive reserves in 1981: 115

TCF.

2. Calculate reserve growth in sample fields where

adequate data are available. Shell evaluated the effects of a price increase to $3.50 on lower abandonment pressures and well reworkings, infill drilling, and

well stimulation for 14 large sample fields. The lower

abandonment pressure calculation involves computing the gas flow that will produce revenues equal to

operating costs3 for the new and old gas prices. The

difference in reservoir pressures corresponding to the

‘ C S Matthews, Increase /n Untted States ‘‘old” Gas Reser~e5 Due to

Oeregu/ation, Shell 011 Co , April 1983

‘Office of Technology Assessment, Staff’ Memorandum on the Etiects of

Decontrol on (Id Gas Reco~ery, February 1984

‘Th IS IS approxl mately the abandonment poI nt tor the well, 51 nce profits

are zero at this poI nt

“new” and “old” flows, and the additional reserves

corresponding to this pressure difference can then be

calculated by using the physical gas laws. The infill

drilling calculations were made using reservoir simulation and extrapolation from previous infilling experience. The well stimulation calculations are based on

an engineering judgment that an additional 1.5 percent can be added to ultimate recovery by this means:

Reserves remaining in sample fields . . . . 41.3 TCF

Reserve growth, lower abandonment pressures

and well reworking . 9.6 TCF

Reserve growth, infill drilling ... ., . . . . . . 7.6 TCF

Reserve growth, well stimulations = 1.5 percent of ultlmate

recovery 4

3. Scale up the sample results to the Nation, assuming that, except for well stimulations, the results will

scale by the ratio of the remaining reserves:

Scaling factor = 11 5/41.3 = 2.8

National reserve growth for lower abandonment pressures and

well reworkings = 9.6 X 2.8 = 27 TCF

National reserve growth for infill drilling = 7.6 X 2.8 = 21 TCF

By examining available production records and estimates of remaining reserves, Shell estimated that the

ultimate recovery represented by the 115 TCF of responsive reserves is 475 TCF, thus:

National reserve growth for well stimulation =

0.015 x 475 = 7 T C F

Assuming that 3 TCF of the infill drilling would occur

anyway at presently available prices (an incentive

price of $2.75/MMBtu in mid-1983),

Total national reserve growth due to higher prices =

27 + 21 + 7 – 3 = 52 TCF

OTA’s Modifications to Shell’s Analysis

OTA has made a number of modifications to Shell’s

original calculations based on a detailed review of

Shell’s methodology, an evaluation of alternative data

sources, a review of literature on infill drilling and

other topics related to gas recovery, and a number

of telephone interviews with geologists and petroleum

engineers. The most important of the modifications

are:

1. Scaling to the Nation. OTA determined that an

appropriate scaling factor should be related as closely

as possible to the original volume of gas in the fields.

The basis of Shell’s scaling factor, remaining reserves,

is tied closely to the production history of the fields.

‘Ultlmate recovery = cum u Iatll e production plus remal n I ng rwerl es

227
228 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Ultimate recovery, on the other hand, is more directly

related to the original gas volume and is a more appropriate basis for the scaling factor. Using Shell’s own

calculations, the use of ultimate recovery as the basis

for the scaling factor yields an increase in the expected

national reserve growth of 36 percent (all else being

equal).

2. Responsive reserves. As noted above, Shell assumed that all old gas would remain at low prices

under the NGPA, so that, for the calculation of responsive reserves, Shell estimated the total old gas reserves

and subtracted only those reserves that would be

physically unresponsive to higher prices. However,

the NGPA provides for the decontrol or price escalation of most old intrastate reserves by 1985, and the

decontrol by 1985 or 1987 (depending on depth) of

all gas from infill wells in old intrastate fields. Consequently, these reserves will receive a high decontrolled price whether or not any additional decontrol

measure is passed, and thus are not “responsive” to

such a measure . . . . they should be subtracted from

Shell’s calculated responsive reserves. Shell also made

some minor errors in its original calculation of total

old gas reserves; it treated all “extensions” added to

reserves since 1977 as old gas, whereas some of these

reserves qualify as “new” NGPA Section 102 gas and

should have been excluded from the calculated total

of old gas reserves.

Data on the amount of reserves in each NGPA category are not available. OTA used data on reserve

volumes in interstate and intrastate commerce, interstate pipeline purchases by NGPA category, and

limited production data by NGPA category to estimate

the volume of old gas reserves in each category, and

the volume of responsive reserves. Our estimate of

responsive reserves was 63.4 to 71.4 TCF for lower

abandonment pressures and well stimulations, and 59

to 66 TCF for infill drilling, as compared to Shell’s 115

TCF estimate for each category. Consequently, all else

being equal, Shell’s results are overstated by the ratio

of “incorrect” to “correct” reserves, or by a factor

of about 1.6 to 2.0.

3. Abandonment pressures. Shell’s estimates of the

current abandonment pressures in its sample fields

generally are considerably higher than the estimates

of alternative analysts, for example, the American Gas

Association’s Committee on Natural Gas Reserves. A

higher current abandonment pressure implies a larger

growth potential, so applying the alternative, lower

pressures would yield a lower estimate of the additional reserves available from the growth of older

fields. Specifically, applying the alternative pressure

estimates in those fields where such estimates are

available more than halves the estimates of growth potential, from 8.1 TCF to 3.0 TCF. The uncertainty associated with these alternative abandonment pressure

estimates was factored into OTA’s estimates of field

growth potential.

4. Infill drilling. A key point of contention with

Shell’s analysis of infill drilling is the extent to which

the potential reserves may be available at today’s

prices without any legislative changes. Shell’s prediction that only 3 TCF of a 21 TCF potential would be

forthcoming at today’s prices is based partly on its

assumption that the low level of infill drilling activity

of the past few years must reflect a lack of economic

prospects. However, a variety of factors other than an

inadequate price may have played a role in the current inactivity. These factors include the current gas

surplus, opposition by pipelines or consumers, s opposition by other producers in the same field,6 and

State prorationing rules that prevent producers from

increasing production rates. OTA’s discussions with

producers have lead us to believe that more than 3

TCF of the total infill potential would eventually be

drilled at current prices. The range of infill potential

in Scenario 1 reflects the possibility that as much as

one-third of Shell’s “after decontrol” infill potential

could occur eventually without any further legislative

change.

5Be( a use the current Inflll Incentive price of about $2 .85/MMBtu appltes

to all gas from the Inflll well, Including gas that could have been produced

from adjacent wells at a lower price.

6Because the potential for drainage across the field means that the other

producers would have to lnhll also or face the 10s5 of some of their gas.
Appendix B

Fracturing Technologies

Introduction

A characteristic of “unconventional resources” is

that, while increased prices generally are an important condition for full commercialization, new technology developments are also required. In the long

run, technology may have more impact than price on

the amount of gas recovered. Studies of unconventional resources that OTA has reviewed have concluded that the amount of gas that could be produced

with existing technology at prices considerably higher

than today’s is less than the amount of gas that could

be produced with advanced technology at current

prices for new gas. For example, the National Petroleum Council’s tight gas study estimates that more gas

can be produced for $3.00 per thousand cubic feet

(MCF) with advanced technologies than can be produced for prices up to $9.00/MCF using base case

technology. In response to this perception, a considerable amount of Government and industry research

effort has gone into developing more advanced technologies for unconventional gas recovery,

In the past 5 years the state of technological development has advanced. With and sometimes without

additional Government financing, producers have

been willing to try innovative approaches. Nevertheless, a high failure rate still exists in probing certain

types of unconventional gas formations. The following discussion describes successful new developments

in fracturing technologies and delineates areas where

work remains to be done. This appendix will serve to

give the reader more insight into the validity of the

assumptions used in the various estimates of recoverable resources and production potential.

New Technology Developments

in Fracturing

The objective of fracturing a low-permeability reservoir is to increase the surface area of the formation

that is in direct contact with the well bore. The pressure gradient between the lower permeability formation and the higher permeability fractures is the driving mechanism for the gas flow. Thus, the greater the

area over which such a gradient can be established,

the larger the volume of gas flowing at a given point

in time.

Technologies for fracturing gas reservoirs are not

new. Explosives have been used in Devonian shales

since the late 1800s. Detonation of explosives shatters the rock immediately around the well bore, effectively increasing the well bore diameter. A large-scale

variation on this theme was tried in the late 1960s in

tight sandstone formations using nuclear explosives.

The generally unsatisfactory results (possibly due to

melting of the reservoir rock from the heat of explosion or permeability damage due to compaction of

fine particles) and the lack of public enthusiasm for

potentially radioactive gas put a quick end to this

program.

Hydraulic Fracturing Technologies

Hydraulic fracturing is the most commonly used

fracturing technology today. The concept was first developed in the 1940s for use in conventional oil and

gas reservoirs. In the early 1970s producers began to

increase the size of the fracture treatments to generate longer fractures, on the order of 1,000 ft in lowpermeability sandstones.1 This technique, known as

massive hydraulic fracturing (MHF), is now a common

means of well completion in the tight sand formations,

although it is certainly not applicable in all cases.

Devonian shale and coal seam reservoirs use more

conventional size hydraulic fracture treatments to

create fractures ranging from 100 to 500 ft. Fractures

in these types of reservoirs are designed to intersect

natural fractures, which serve as the primary pathways

for gas flow.

Hydraulic fractures are created by pumping large

volumes of fluid down the well bore. The fluid exerts

pressure on the rock formation, eventually creating

a fracture. Fluids generally carry proppant materials,

such as clean coarse sand, which are left in the fractures and hold them open when the fracturing fluid

is removed. The induced fracture has a considerably

higher permeability than the surrounding formation.

Hydraulic fractures tend to be unidirectional, generally extending out as wings in opposite directions from

the wellbore. By convention, their length is measured

along one wing. Their direction and orientation (vertical, horizontal, or inclined) are controlled by the regional tectonic forces and the depth of the target formation. Most fractures at depths greater than 2,000

ft are oriented in the vertical plane. Figure B-1 schematically represents a hydraulic fracture.

Major research efforts in fracturing technology have

focused both on increasing the fracture length and

‘C. R. Fast, G. B, Holman, and R. j. Corlln, ‘‘The Application ot Massive

Hydraullc Fracturing to the Tight Muddy j FormatIon, VVattenberg Field, Colorado, ” )ourna/ of Petro/eurn Technology, january 1977, pp. 10-16

229
230 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Figure B-1 .—Conceptual Fractures Created by Massive Hydraulic Fracturing in

- Blanket and Lenticular Formations

FI

t

r

Blanket formations

Fracture

height

1

Wings

Well

bore
App. B—Fracturing Technologies 231

solving some of the problems that reduce the effectiveness of the fracture in increasing rates of gas flow.

Maximizing the effective length of a fracture is not

simply a function of increasing the volumes of fluid

pumped into the well bore. One must make sure that

the proppant is transported to the end of the fracture,

and effectively holds the fracture open once the fracturing fluid is removed. Other problems that must be

overcome include minimizing damage to the formation caused by the fracture fluids and containing the

fracture within the “pay interval,” the layer where gas

is present. If the fracture intersects a permeable zone

that allows the fracturing fluid to “leak off” at a high

rate, further penetration of the fracture may become

impossible because the fluid loss prevents further pressure from being built up.

Each of the objectives of fracture research will be

discussed in turn:

Maximizing High Conductivity Fracture Length.–

Accomplishing this objective involves choosing appropriate fracture fluids and proppants. The proppants

should be strong enough not to crush as the fracture

closes, and of sufficient diameter to overcome any

tendency to become embedded in the formation.

Also, they must be light enough to be carried by the

fracturing fluid to the design fracture length without

settling.

Conventional practice is to use clean rounded sand

as the proppant material. It is the least expensive proppant and, at shallow and intermediate depths, has sufficient strength to hold the fracture open without

crushing. At greater depths where closure pressures

are higher and proppant crushing prevalent, a stronger

material is needed.2 Producers most commonly use

sintered bauxite under these conditions. However,

bauxite has two drawbacks–high cost and high density. Because of the latter, it is difficult to transport the

bauxite particles to the end of the fracture. Service

companies are rapidly developing alternate intermediate and high strength proppant materials. A number of these materials, including ceramic beads and

resin-coated sands, have lower densities than bauxite and appear to have sufficient strength for most fracture applications. More work needs to be done to develop materials with densities lower than sand and

adequate strength to maintain high fracture conductivities.

The need for a fracture fluid with a high capacity

to carry proppants in suspension has led to the development of very sophisticated fluids. These include

‘R. A. Cutler, D. O Ennlss, A. H Jones, and H. B. Carroll, ‘‘Compa risen

of the Fracture Concfuctlvity of Commercially Available and Experimental

Proppants at Intermediate and High Closure Stresses, ” SPE/DOE SyrnposIurn

on Low Perrneabl/lty Gas Reservoirs, SPE/DOE 11634, 1983.

water- and hydrocarbon-based polymer liquids and

gas-charged emulsions and foams.

The water-based fluids use organic polymers for friction reduction, fluid loss control, and viscosity enhancement. The polymers are long chains of organic

molecules which bond loosely with the water, forming gels. The resultant fluid is thicker than water and

has a higher surface tension. It flows with less turbulence, can suspend greater volumes of proppants

and does not leak off into the formation as rapidly as

pure water.

Probably the most significant technical development

in fracturing fluids is the process of cross-linking.

Cross-linking is a chemical reaction which bonds

polymer chains together, effectively increasing the

viscosity of the fluids as much as an order of magnitude. The reaction is timed so that cross-linking occurs just as the fluid arrives at the fracture entrance.

The increased pressures required to pump the thicker

fluid will widen the fracture and the enhanced viscosity can carry the proppant greater distances. At the

end of the treatment the fracture fluid warms up to

the higher reservoir temperatures and the cross-linked

polymers break down. Now significantly lower in viscosity, the fluid can leak off into the formation or flow

back out of the wellbore, leaving the proppant in place.

Hydrocarbon-based fracture fluids behave similarly

to water-based fluids and can also be cross-linked.

They are used in instances where water-based fluids

are likely to cause significant formation damage—as

in the presence of water-sensitive clays. However, in

gas-bearing reservoirs the introduction of a third phase

(oil, in addition to gas and water) may further impede

the flow of gas in the formation.

Minimizing Formation Damage.—In addition to

fluids designed to improve proppant transport, more

exotic fracture fluids have been designed to address

the problem of formation damage. Fracture fluids have

been a major factor in causing formation damage.

Fluid leak-off into the formation can block pores, especially if the gels are not completely broken down. introduced fluids can also cause clays to swell, or dislodge fine particles to block pores.

All three types of unconventional gas reservoirs are

susceptible to formation damage. Devonian shales

may be the most affected because they have naturally

low water content and high clay content. Devonian

shales have, as a consequence, served as a testing

ground for a number of the new fracturing fluids.

Many of the fluids developed to minimize formation damage use a gas phase to reduce the amount

of water required. Foamed fluids are gas-in-water

emulsions, where the surface tension of the bubbles

holds the proppant in suspension. Such fluids cannot
232 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

transport large volumes of proppant long distance—

they are generally used for shorter fractures. Nitrogen

(N,) is the most common gas used in foamed fluids,

although CO2 can also be used. Producers are experimenting with increasing the percentage of gas from

75 to 90 percent of the total fluid volume.

Pure N2 has also been used as a fracturing fluid. It

is not an efficient fracturing fluid as it requires very

high injection pressures. However, nitrogen fracturing has proved very effective in increasing gas flow

because it does not adversely affect the formation. Nitrogen gas cannot carry proppants, therefore it is only

effective at shallow depths where the fractures are less

likely to close. Whether wells fractured with nitrogen

will maintain higher production levels over the long

term is still unknown.

Some wells have been fractured using liquid C02

,

which has the ability to transport proppants. As the

liquid C02 warms, it reverts to the gas phase and easily

flows back out of the hole with minimal damage to

the formation. Liquid CO2 fracturing is a relatively expensive process and somewhat more dangerous to use

than foamed fluids, In addition, the casing and pumping materials must be capable of withstanding very low

temperatures.

The tradeoffs of minimizing formation damage,

transporting proppants, and containing costs all enter into the decision of which fracture fluid is used.

Generally, an important element in the decision

should be laboratory compatibility tests between formation cores and the proposed fracturing fluids, which

can identify potential damage problems.

Containing the Fracture within the Pay lnterval.–

As a fracture propagates outward from the wellbore

it may also grow vertically up or down, Vertical growth

occurs at the expense of lateral growth, thus reduces

the effective length of the fracture for the same volume of fluid pumped. Those portions of the fracture

which extend above and below the gas-producing interval are essentially wasted; also, they may extend

into water-bearing strata which will adversely affect

gas flow.

It has been recognized in the last few years that the

main factor controlling containment of a fracture is

the difference in the stress characteristics of the rocks

making up the producing and nonproducing zones.

The stress on the rocks, or “in-situ stress,” is a function of the mechanical properties of the rock and the

regional stresses acting on the rock. Thus, the same

type of rock at different locations or depths or in different tectonic environments may have different insitu stress characteristics. A sand-shale interface in the

Cotton Valley Sands may effectively contain a fracture

within the sand zone. A fracture in the Piceance Basin

may break through a similar sand-shale interface. Similarly, different rocks will have large differences in their

mechanical resistance to fracturing and thus require

substantially different applied pressures for fracturing.

No commercially available technologies exist today

that successfully deal with fracture containment. Some

recent research efforts have focused on developing

innovative techniques to control the growth of fractures out of the pay zone. GRI is testing three approaches: 3

●

●

●

Fracture initiation placement–the well casing is

perforated above or below the pay zone allowing the fracture to grow vertically into the producing interval. A field test of this technique was

performed in July 1983.4 Preliminary results indicate increased flow but further cleanup is necessary before final results can be assessed.

Controlled process zone–the fluid viscosities

and pumping rates are controlled to get preferential initial leak-off in the pay zone. This should

result in more penetrating rather than taller fractures. This technique is still being tested in the

laboratory.

Lightweight additives–impermeable floating

proppants are used to seal off upper, non-producing portions of the fracture. Appropriate proppant

materials are currently being tested.

Predicting and Monitoring Fracture Behavior.–

Another important research objective in improving

fracturing technology is to develop techniques to predict and monitor fractures. To know in advance how

a fracture is likely to perform or to be able to tell in

the field whether a fracture is conforming to design

parameters increases the chances that stimulation will

be successful. Furthermore, as fields become more developed, it is important to know the direction and

length of a fracture, and thus the drainage area of a

well in order to minimize interference from subsequent wells. Fracture diagnostics probably is one area

where the most innovation has occurred in the last

few years.

Predicting fracture behavior.–State-of-the-art prediction of fracture behavior comes mostly from formulation of sophisticated mathematical models and

comparison of the model results with results of laboratory experiments. There has been little field verification because of the cost and technical difficulty involved in obtaining a detailed picture of the physical

results of fracturing.

3“GRI’s Unconventional Natural Gas Subprogram, ” Status Report, mcember 1982.

4“New Fracturing Technique Undergoing Tests, ” oil and Gas )ourna/, Aug.

8, 1983.
App. B—Fracturing Technologies 233

Current practice in the field is to use relatively simple analytical models against which to compare fracture behavior, proppant placement, fracture length,

and well performance. Two commonly used models

are the Perkins and Kern model and the Gertsma and

De Klerk model. The first is considered by some practitioners to be the more reliable model for fractures

extending laterally without significant increase in

height, with the second more reliable for short fractures with length to height ratios less than one.56

More sophisticated models are being developed to

deal with more complex situations such as fracture

propagation response to changing stress fields, or

intersection of an induced fracture with a natural fracture. Such models have been used occasionally to design actual field stimulations where preliminary investigation indicates a simplified model would give

inadequate or misleading results. Use of complex

models for field design is limited at present due to high

costs, time required to run the simulations, and probably most importantly, inadequate input data. At present these models are mostly used as controls for design

of experiments and for comparison with experimental

results. The extent to which experimental results reproduce the simulated results both confirms the validity of the simulation and identifies the controlling parameters.

Laboratory experiments are conducted to observe

fracturing behavior under controlled conditions. In

these experiments, scale models are used to simulate

field conditions. For example, a block of reservoir material can be placed in an experimental apparatus

which can reproduce confining pressures and temperature conditions of the actual reservoir. Fluid is

pumped into a hole drilled into the block, inducing

a fracture. Sensors monitor strain buildup and release.

Finally the fractured block can be sectioned to observe

the fracture configuration. Experimental conditions

allow certain variables to be held constant while

others are varied to determine the effect each has on

the fracture, One set of experiments was run to observe induced fracture behavior in the presence of an

existing fracture system.7 Results indicated that an induced fracture would cross an existing fracture only

at high angles of approach (i e., close to perpendicular) or if the stress field created a strongly preferred

fracture orientation. Otherwise the preexisting fractures would open, diverting fracture fluid and stopping the induced fracture from propagating.

—. --——

‘Johnston & Associates, Inc., “The Status and Future ot ProductIon Technologies for Gas Recovery From Devon Ian Shales, OTA contractor report

No, 333-6810

b], W. Crafton, “Fracturing Technologies for Gas Recovery From Tight

Sands, ” OTA contractor report, 1983

The major problem with laboratory experiments is

determining whether the laboratory conditions are

truly representative of the reservoir environment. it

rarely is clear whether the small-scale laboratory fracture would behave in the same fashion if it were increased to field scale. Consequently, the next step in

predicting fracture behavior is the field test. Field tests

are extremely expensive, and therefore few have been

conducted. Perhaps the most useful are “mineback”

experiments which excavate and expose an induced

fracture, allowing comparison of actual behavior with

predicted behavior and physical measurement of the

rock, fracture, and fracturing materials.

Successful field-scale experiments of massive hydraulic fractures have been conducted at the Nevada

Test Site in volcanic rocks.8 These rocks are not particularly characteristic of tight sandstone reservoirs but

the experiments still provided useful and frequently

applicable information. One significant result indicates

that fracture tortuosity (irregularities of the fracture

path) significantly increases the pressure gradient in

the fracture, leading to wider than predicted fractures.9

Other studies demonstrated the mechanics of fluid

leak-off and sand distribution.

Because of their expense, mineback experiments

are no longer being conducted by the Department of

Energy (DOE) or GRI.10 Instead, field testing for understanding fracture behavior is focusing on experimental

well tests. These tests rely on sophisticated in-well

measurements to infer fracture behavior in contrast

to the direct observations possible with minebacks.

The largest scale well test at present is the DOE

Multiwell Experiment (MWX). This test consists of

three wells drilled in close proximity to each other in

a tight sands field in the Piceance Basin in Colorado.

The multiple wells serve many functions. They allow

collection and correlation of geologic data and provide testing sites for new logging tools. Perhaps most

importantly, they provide sites to monitor behavior

of fractures induced in one of the wells. A fracture has

been completed in the blanket sand reservoir in this

field and results have indicated the importance of an

existing natural fracture system on fracture behavior

and well performance. Subsequent stimulation treatments are planned to address specific problems of

fracturing in Ienticular formations. — . -———

‘T. L, Blanton, ‘ An Experimental Study of Interaction Between Hydra ullcal Iy Induced and Pre-Exist I ng Fractures ‘‘ SPE, DOE UrK rIn\ errIIorM/ 6-.]s

Reco) ery SyrnposIurn, SPE/DOE 10847, 198,?, pp 559-562.

8 N. R. Warplnskl, L. D, Tyler, W, C. Vollendert, and D. A, Northrup, “ Direct Observation of a Sand Propped H yd rau I IC Fracture, Sa ndla National

Laboratory Report SAND81 -0225, May 1981.

9 N , R Warplnskl, “Measurement ot Width and Pressure In a Propagating

Hydraullc Fracture, ” SPE/DOE Syrnpcwurn on Low PerrneA1/)fy G~~ /?e~ervolrs, SPE/DOE 11648, 1983.

InCharles Komar, Morgantown Energy Research center, personal ~OrnmUnlcatlon, 1984.
234 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Similar but smaller scale well tests are being conducted in Devonian shales to determine effectiveness

of different types of stimulation in improving reservoir

production.

Monitoring fracture behavior. –Most of the technologies under development to monitor fractures in the

field are adaptations of existing geophysical and well

logging techniques. They include magnetic, electrical,

and seismic instrumentation as well as temperature,

pressure, and radioactivity measurements (see box B1). Some techniques such as temperature and radiation logs are only useful in the immediate vicinity of

the borehole. They indicate fracture height under certain conditions but not depth of penetration.11 Tiltmeters and microseismic measurements which record

minute deflections and seismic disturbances caused

by the propagating fracture may be able to measure

fracture direction and total length, but cannot discern

propped (effective) length. Superconducting magnetometers may have potential for determining propped

length from magnetic material introduced with the

proppant. 12

Most of these technologies are still in the experimental stages. Their depth limitations, sensitivity, and

overall accuracy have not yet been fully evaluated.

Using a number of these technologies together would

probably be the most effective way to collect data on

a fracture13 but for practical application would be too

costly.

There are other constraints to widespread use of

fracture diagnostic techniques. For example, adverse

terrain and difficulty in obtaining surface access rights

cause problems for methods which require widely

spread surface arrays of detection equipment.14 15 The

extremely sensitive nature of the instruments and the

necessity of measuring signals that are only marginally discernible above background noise requires very

careful setup and monitoring that may not be achieved

under ordinary operating conditions.

—

I !c, M, Hart, El. Engl, and H. E. Morris, “A Comprehensive Fracture Diagnostics Instrumentation Fielding Program, ” SPE/DOE Symposium on Low

Permeabl/ify Gas Reservoirs, SPE 11810, 1983, pp. 461-485.

l~M, D, Wood, C. W, parkin, R. Yotam, M. E. Hanson, M. B. Smith, R.

L. Abbot, D. Cox, and P. C)’ Shea, “Fracture Proppant Mapping by Use of

Surface Superconducting Magnetometers, ” 5PE/DOE Symposium on Low

Permeability Gas Reservoirs, SPE/DOE 11612, 1983,

I ID, A, Northrup, A, R. Sattler, and j. K. Westhuslng, ‘‘Multiwell Experiment: A Field Laboratory for Tight Gas Sands, ” SPED(3E Symposium on Low

Permeabi/lty Gas Reservoirs, SPE/DOE 11646, 1983.

ldHa~, Engi, and Morris, Op. cit.

1 Sjohnston & Associates, Inc., OP. cit.

The technique most commonly used today to

evaluate whether a fracture satisfies design criteria is

pressure transient testing. This type of test generally

is run after the fracture treatment is completed, although it can be useful as a pre-fracturing test as well.

Essentially, a post-fracturing test matches the actual

performance of a well for a given period of time

against the simulated performance of a fracture of

given propped configuration. This gives a minimum

estimate of the propped length. The technique gives

valuable empirical data on the flow rate and pressure

decrease with respect to time for the well. However,

it is generally considered as not providing sufficient

information to allow producers to discern whether

lower-than-predicted flows are due to fracturing out

of the pay interval, inadequate fracture conductivity,

or formation damage.16

Improved fracture diagnostic techniques may reduce some of the undefined variables (e.g., actual

propped fracture length). This would allow the reasons for success or failure of a particular fracture treatment in a given formation to be better understood,

resulting in improved fracture design.

High Energy Gas Fracturing or

Tailored Pulse Loading

This technique is dramatically different from hydraulic fracturing techniques, and is derived from earlier

explosive fracturing. A propellant charge is used that

can pressurize the wellbore at a slower rate than the

conventional explosives, changing the characteristics

of the fractures created.17 The loading rate—i.e., the

rate at which the energy stored in the gas is released—

can be controlled to create different types of fractures.

For example, at intermediate loading rates, fractures

form radially around the well bore. At slow rates, fractures form in an analogous manner to hydraulic fractures, directionally controlled by the regional stress

field. This technique may have significant potential for

commercial use, especially because it causes little formation damage. Commercial application in the Devonian shales may occur in the near future. Application

in tight formations is more problematic, however.18

lsThis is a matter of some dispute, because some Speclallsts Clalm to be

able to distinguish among the possible causes of disappointing flows,

1

7Crafton, op. cit.

18s, A, HoldItch, personal commu nlcatlon, 1984.
App. B—Fracturing Technologies ● 2 3 5

Box B-1. --Well Logs

Well logs are measurements of rock formation

characteristics taken by devices, called sondes,

that are lowered into the wellbore on an electric wireline and transmit back information to a

surface recording device. There are a great variety of these devices. The most common are:

1. Eletrical logs measure the electrical characteristics of the rock surrounding the wellbore before the well is cased. Electrical logs

measure either resistivity or spontaneous

potential.

● Resistivity logs pass an electric current

through the rock formation and measure

its ability to conduct electricity. These

logs help to determine the type of fluid

contained in formations and the relative

saturation of oil and water. There are a

variety of resistivity logs, including:

–Induction logs, which measure formation resistivity in wells drilled with

freshwater drilling fluids or with nonconductive fluids such as air or oil.

–Laterolog, which can identify thinner

formations than ordinary resistivity

logs. These are used with saltwater

drilling fluids.

–Microlog, which is used to identify the

porous and permeable zones by measuring the resistivity of the thin layer

around the wellbore that is invaded by

drilling fluids.

● The spontaneous potential log measures

the electrical potential created by the differences in salinities between the formation water and drilling fluids. This log

helps to differentiate between rock types

(e.g., sand and shale) and to define formation water salinity.

2. Radioactive logs measure either the naturally occurring radioactivity in the rock formation or the response of the formation to

bombardment by neutrons or gamma rays.

These include:

● Gamma-ray logs record the naturally

occurring gamma rays in the rock formation surrounding the well bore. They differentiate between shales and other formations, or measure the amount of shale

in the formation.

* Neutron logs bombard the formation

with neutrons and measure the induced

gamma rays: They delineate porous formations, and indicate the amount of fluid

(and, in some cases, fluid type). They are

useful in locating gas zones and determining rock types.

● Formation density logs measure the scattering of gamma rays bombarding the formation from a source on the logging tool.

They are used to determine porosity, and

help in determining rock types in conjunction with sonic or neutron logs.

● Gamma spectrometry logs measure both

the scattered neutrons and the gammaray spectrum from neutron bombardment. They help in measuring ’hydrocarbon saturation, porosity, formation water

salinity, and rock types.

3. Acoustic veIocity, or sonic logs, measure the

velocity of an acoustic (sound) wave along

the wall of the borehole. They are used to

measure porosity, to distinguish between

salts and anhydrites, to detect shales with

abnormal pressures, to determine rock

types, and to identify fractures.

4. Nuclear magnetism logs measure the effects

of applying a large magnetic field to the

rock formation. They are used to measure

permeability, porosity, producibility, and

water saturation.

5. Temperature logs are used to identify zones

where drilling mud is being lost into the formation or, in air-drilled wells, the locations

of gas entry into the wellbore.

SOURCES: F. A. Giuliano (cd.), Irrtruducfion to 0# and Gas Technology, 2d ad., M#comp ~De#qmMM and Engineering, Inc., Houston, TX, 1981; Brit~sh

Petroleum Co. Ltd., Our Industry Petrokum. 1977; and Schhsmberger Well !kwiccs, @40k -’m Catalog, Ig8J.
Appendix C

Double Counting

A Comparison of the PGC and

NPC Tight Gas Estimates

A major problem with estimating the natural gas resource from unconventional reservoirs is determining

how much of this unconventional gas has already

been included in estimates of the conventional resource. The primary areas of overlap would be the tight

sands and Devonian shales. Much of the tight sands represents the lower end of a continuum of gas-producing

reservoirs. Except for its lower porosities and permeabilities, the “blanket” portion of the tight sands resource is quite similar in other respects to conventional formations and, in fact, gas is presently being

produced from tight blanket formations and even, in

some cases, from Ienticular formations. The Devonian

shales have been producing gas since the early days

of petroleum development in this country. Obviously,

these categories cannot be considered entirely new

additions to the resource base.

There is no clear-cut boundary between gas that has

been included in conventional resource estimates and

that which has not. The cutoff point for the conventional resource varies from assessment to assessment

and tends to be loosely defined on the basis of rather

ill-defined economic and technical constraints. For example, the Potential Gas Committee (PGC) defines its

resource estimate to include gas from “all wells which

would be drilled in the future under assumed conditions of adequate economic incentives in terms of

price/cost relationships and current or foreseeable

technology.” 1

The PGC assessment, Potential Supply of Natural

Gas in the United States, is one estimate of the conventional resource which overlaps with the “unconventional. ” Given its broad definition of what constitutes the undiscovered recoverable resource, the PGC

chose not to define a physical cutoff point, such as

a permeability limit, to separate out tight gas from conventional gas. To do so would exclude from the resource base gas that conceivably could be produced

under the assumptions of reasonable price and technology. Thus, the PGC has consistently designated

some “tight” gas as part of the conventional resource.

Recently, the PGC has made an attempt to determine the percent of its total resource estimate that occurs in tight formations. (It includes in the tight gas

category both tight sands and Devonian shales.) For

I Potential Gas Agency, Potential Supply of Natural Gas in the United States

(as of Dec. 31, 1980), 1981.

each of its reporting areas (fig. C-1 (a)), it estimates the

percentage of gas that occurs in tight formations,

above and below 15,000 ft. Table C-1 gives the PGC

estimates, in TCF, for each reporting area.2 The total

tight gas included in these estimates is 172 TCF, or

20 percent of the total potential resource.

The following analysis compares the PGC tight gas

breakout with the National Petroleum Council’s (N PC)

estimates of tight sands and Devonian shale resources. s It has been suggested that there may be a

considerable amount of overlap between these two

estimates. Because estimates of the United States’ gas

resource base and future supply often add conventional and unconventional gas contributions, elimination of any overlap would decrease the projected total

resource base and supply. Additionally, since an overlap is most likely to occur among the most attractive

gas prospects, elimination of the overlap may affect

near- and mid-term supply forecasts disproportionately.

In order to compare the PGC breakout with the NPC

estimates, the assumptions underlying the estimates

need to be reviewed. Some of the assumptions are

documented, others have been confirmed through

personal communications.

The definition for tight gas used by the PGC is similar to the FERC definition and includes all gas in formations with average permeabilities less than 0.1 milIidarcy (red). The NPC report does include some gas

in formations with average permeabilities greater than

0.1 md, but the amount is small, less than 1 trillion

cubic feet (TCF). Therefore, the permeability levels for

the two estimates are generally compatible.

Not all the gas in the PGC tight gas estimate will

overlap the NPC estimate. For example, PGC tight gas

includes gas from new pools and reservoirs i n formations that are already being produced. By definition,

this gas is mostly accounted for in the probable category. 4 The N PC report specifically excludes areas

already producing tight gas from its evaluation, since

its objective is to estimate “new potential reserve additions.” Thus, tight gas in the PGC probable category,

amounting to some 56 TCF, cannot be part of any

overlap between the two estimates.

The NPC report does not include any potential gas

resources in formations at depths greater than 15,000

ft, although it postulates that a significant additional

ZBased on the 1982 revised figures for the total resource: Potential Gas

Agency news release, February 1983.

3Natlonal Petroleum Council, Unconventional/ Gas Sources, 1980.

4Harry Kent, Director, Potential Gas Agency, personal communication,

1984.

236
App. C—Double Counting ● 237

NOTE: From Figure 1—Reporting areas and total potential gas supply. 1982 Potential Gas Committee

NPC Tight Gas Basins n

1. Western

Great Plai

1. North

2. Willis

Rock MO

3. Great

4. Wind River Other Known Southwest

5. Uinta Basins studied by NPC F. Raton

6. Piceance G. Anadarko

7. Denver H. Ouachita

Il. Greater Southwest Region 1. Arkoma

Other Known Western Southwest Appraised J. Fort Worth

A. Snake River 8. San Juan K. Western Gulf Coast

B. Big Horn 9. Val Verde-Ozona Trend

C. Wasatach 10. Val Verde-Sonora Trend Ill. Eastern Region

D. Douglas Creek 11. Edwards Lime Trend L. Appalachian

E. Western Shallow Cretaceus Trend 12. Cotton Valley Trend M. Black Warrior

38-742 0 -85 - 17
238 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Table C.1.— PGC Estimate of Gas Occurring in Tight Formations Included in Its 1982 Estimate of Total

U.S. Undiscovered Recoverable Resources (in TCF)

Probable Possible Speculative

PGC area <15,000 >15,000 <15,000 >15,000 <15,000 >15,000 Total

A 23.49 — 0.4 — — 23.89

B::::::::::::::::::::

—

0.32 0.18 0.24 0.3 0.3 0.48 1.82

c . . . . . . . . . . . . . . . . . . . . — — — — — — —

D . . . . . . . . . . . . . . . . . . . . 0.8 — 3.0 — 3.0 0.8 7.6

E . . . . . . . . . . . . . . . . . . . . — — —

G 0.28 -

—

. . . . . . . . . . . . . . . . . . . . 0 3 0.54 -

048 0.12 -

016 1.88

H . . . . . . . . . . . . . . . . . . . . 21.75 5 14.43 14.56 7.02 29.2 91.96

I 0.94 — 0.33 – 1.27

Jn” : : : : : : : : : : : : : : : : : : : —

— —

1.98 14.06 3 20.06 40.2

Js . . . . . . . . . . . . . . . . . . . 0.49 — 0.38 – — 0.87

L . . . . . . . . . . . . . . . . . . . .

—

0.04 0.3 0.3 0.6 0.7 0.4 2.34

Total . . . . . . . . . . . . . . . 55.87 50.72 65.24 171.83

SOURCE” Potential Gas Agency. Potential Supply of Natural Gas in the United States (as of Dec 31, 1982), Report of the Potential Gas Committee, Colorado School

of Mines, June 1983

resource could exist at these depths. However, over

half of the PGC tight sands estimate is found at greater

than 15,000 ft depths—89 TCF total, 81 TCF in the possible and speculative categories. We assume that there

is no overlap between the PGC tight gas below 15,000

ft and the NPC estimate.

The gas projected by the NPC to be recoverable

from tight sands at $5.00/MCF,5 with a 15 percent discounted cash flow rate of return (DCF ROR) and using

base technology, is assumed to represent a reasonable upper economic limit to gas that might be included in the PGC estimate6 (the N PC’s “maximum

recoverable” gas would be an extreme upper limit).

In other words, tight gas considered produceable at

less than $5.00/MCF using present technology is likely

to be included in the PGC tight gas estimate.

In summary, the most potential for overlap exists

between the PGC tight gas in the possible and speculative categories at less than 15,000 ft and the NPC

tight sands and Devonian shales gas recoverable at

$5.00/MCF (1979$) using base technology. This is

graphically represented in figure C-2. It should be

noted that the overlap determined by a straightforward

comparison using the above assumptions may be too

large. PGC used FERC criteria as a guide to defining

the tight formations and the FERC interpretation of

what constitutes tight gas has tended to be generous

relative to the NPC interpretation.

Other specific assumptions need to be made to

compare individual areas. These are discussed in more

detail below.

—

‘For simplicity, the N PC prices (in 1979 dollars) are used In this analysis.

bThe “boundary conditions’ for the PGC resource estimate are imprecise,

and no Iimlt on price is specified other than what may be inferred from the

phrase “adequate economic Incentives In terms of price/cost relationships, ”

To be precise, the NPC definition of Its “base case” technology allows

evolutionary improvements (n presently available technology.

Areas of Overlap

The PGC reporting areas and the NPC appraised and

extrapolated basins are shown in figure C-1 (a) and

(b), respectively. Table C-2 lists the comparable areas

and notes where the PGC has specifically identified

tight gas included in the potential resource. The total

PGC estimate of gas in tight formations is about 172

out of a total of 870 TCF, or approximately 20 percent of the remaining undiscovered recoverable resource. NPC estimates 607 TCF of recoverable gas

from tight sands8 and an additional 25 TCF, at least,

from Devonian shales. Our comparison attempts to

determine how much of this 633 TCF of gas has already been included in the PGC estimate of conventional undiscovered resources and cannot be considered as additions to the U.S. resource base.

Our analysis indicates that the greatest potential for

overlap occurs in the Rocky Mountain region covered

by the PGC reporting area H (fig. C-1 (a)). The comparable NPC area is the Rocky Mountain Basins plus

the Northern Great Plains (fig. C-1 (b)). This area is

already the site of considerable production of gas from

tight formations (e.g., from the Wattenberg field of the

Denver Basin). The extent of the duplication is summarized in table C-3.

For a first approximation, we assume that the PGC

tight gas does not include gas from the Northern Great

Plains. 9 Basins that probably are included in both

Rocky Mountain estimates are the Greater Green

River, Uinta, Piceance, Wind River, and Denver

basins, Within these basins, the most likely overlap

occurs between the blanket formations of the NPC re-

@This IS the “maximum recoverable” gas. Using present technology, NPC

estimates that 365 TCF would be recoverable at $5.00/MMBtu

‘Kent, op. cit.
App. C—Double Counting ● 239

Figure C-2.— PGC and NPC Categories of Tight Gas

NPC tight gas

(includes both tight sands and Devonian shales)

SOURCE Off Ice of Technology Assessment,

Table C.2.—Comparable Areas—PGC Report and NPC Report

PGC reporting areas

Area A. . . . . . . . . . . . . . . . . . . . .

Area B. . . . . . . . . . . . . . . . . . . . .

Area D. . . . . . . . . . . . . . . . . . . . .

Area G . . . . . . . . . . . . . . . . . . . .

Area H . . . . . . . . . . . . . . . . . . . .

Area I . . . . . . . . . . . . . . . . . . . . .

Area J north. . . . . . . . . . . . . . . .

Area J south . . . . . . . . . . . . . . .

Comments NPC basins

Includes some Devonian shales Appalachian Basin Devonian shales

recoverable by normal drilling, well

stimulation, and completion and Eastern extrapolated tight sands

analogous in geologic setting to

previous production

— Eastern extrapolated tight sands

Includes tight formations of Travis Peak Cotton Valley appraised, Southwest

and Cotton Valley extrapolated (east)

— Edwards Lime Trend, Southwest

extrapolated (south)

Includes tight formations of Greater Rocky Mountains appraised, Northern

Green River, Uinta, Piceance, and Wind Great Plains appraised, Western

River extrapolated

— San Juan appraised, Southwest

extrapolated (west)

— Southwest extrapolated (east)

— Val Verde Ozona-Sonora appraised,

Southwest extrapolated (central)

SOURCE: Office of Technology Assessment

Table C-3.–Comparison of PGC and NPC Tight Gas Resource, Rocky Mountain Region (in TCF)

Recoverable Maximum PGC area H

NPC Rocky Mountain Basinsa

$5.00/McFb recoverable <15,000 ft Tight gas Percent overlap

Blanket . . . . . . . . . . . . . . . . . . . . 19.7 34.5 Probable 21.75 None

Possible 14.43

Speculative 7.02 )

62-100

Lenticular. . . . . . . . . . . . . . . . . . 68.9 164.9 None

Combined. . . . . . . . . . . . . . . . . . 12.6 15.5 None

Total , . . . . . . . . . . . . . . . . . . . . . 101.2 214.9 Total 43.20 10-21

aIncludes. appraised Greater Green River, Uinta, Piceane, and Denver basins, and other Western extrapolated basins.

bGas recoverable at $500/MCF (1979$), 1570 DCF ROR, assuming base technology.

SOURCE Office of Technology Assessment
240 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

port and the PGC possible and speculative categories

at depths less than 15,000 ft. We are assuming that

the PGC estimate does not include any gas in lenticuIar formations or in combined blanket and Ienticular

formations. This assumption may not be strictly correct because individual lenses have been produced

in past drilling by directly intersecting the lens with

the wellbore. There is no existing technology, however, for producing lenses remote from the well bore.

Much of the Rocky Mountain gas occurring in blanket formations appears to be included in both the NPC

and PGC estimates. The NPC estimated range of gas

recoverable in blanket formations, from gas available

at $5.00/MCF, 15 percent DCF ROR, and base technology, to the maximum recoverable gas, is 20 to 34

TCF (see vol. V, table 9 of the NPC report). This includes 7 to 10 TCF in extrapolated blanket formations

in this region. The NPC estimate for gas in blanket formations is very close to the PGC estimate of 21 TCF

of possible and speculative gas occurring in tight formations at less than 15,000 ft, and probably represents

a duplication of the PGC estimate.

Another significant area of overlap may occur in the

Cotten Valley Trend of east Texas and Louisiana. This

area is included in PGC area D and is one of the appraised basins of the NPC report. The NPC range of

gas in the Cotton Valley, from $5.00 to the maximum

recoverable, is 7 to 12 TCF, which probably overlaps

the 6 TCF of possible and speculative tight gas in formations less than 15,000 ft as estimated by the PGC.

In south Texas, the NPC estimate ranges from 44

(at $5.00) to 60 TCF (maximum recoverable). The estimate covers extrapolated formations as well as the appraised Edwards Lime Trend, with an estimated gas

potential between 6 TCF (at $5.00) and 9 TCF (maximum recoverable). it is also covered by PGC reporting area G. Here, PGC estimates 0.66 TCF of gas in

the possible and speculative categories above 15,000

ft. It is likely that the PGC estimate, even if it does not

specifically refer to the Edwards Lime Trend, is duplicated somewhere in the NPC appraised plus extrapolated formations.

In the PGC’s area 1, including the San Juan Basin,

most of their estimated tight sands gas is derived from

infill drilling of the Dakota and Mesaverde formations

and is most likely included in its probable category.

The 0.33 TCF remaining in the possible category may

be new gas occurring in these formations, and most

or all of it may overlap the NPC estimates of 1.49 to

2.31 TCF for the appraised San Juan Basin. Although

the NPC extrapolates an additional 11 to 16 TCF in

this region (which would include gas in the Raton

Basin in northeastern New Mexico), the PGC estimate

probablv does not overlap with any extrapolated gas.

A large quantity of gas–40 TCF–is estimated by the

PGC to occur in tight formations within its reporting

area Jn. Most of this gas is thought to be found in the

Deep Anadarko and Springer sands. Thirty-six TCF are

found at depths greater than 15,000 ft. This leaves only

4.1 TCF in the possible and speculative categories

above 15,000 ft to potentially overlap the NPC tight

gas. All the NPC basin estimates in this region are extrapolations with a total range from 16 to 24 TCF. It

is likely, but not conclusive, that the 4.1 TCF of PGC

gas does overlap NPC gas.

The amount of overlap in tight formations in the

Eastern United States is more difficult to determine.

This area encompasses reporting areas A and B of the

PGC report and the Eastern U.S. extrapolated tight

sands and the Appalachian Basin Devonian shale of

the NPC report. in area A, excluding the estimated

probable gas, which is likely to be primarily gas from

producing formations in Devonian shales and interIayered sandstones, leaves 0.4 TCF in the possible category. In area B, there are 0.54 TCF in the possible

and speculative categories at depths less than 15,000 ft.

Producible gas from Devonian shales as estimated

by the NPC falls in the range of 12 TCF at $5.00/MCF

and 25 TCF maximum recoverable using traditional

technologies only. The extrapolated tight sands resource for the Eastern United States ranges from 72

to 101 TCF. In OTA’s opinion, the 0.94 TCF of gas in

the PGC areas A and B are likely to be included somewhere in the total of the NPC extrapolated tight sands

and the Devonian shale resource,

Table C-4 summarizes the total overlap between

NPC and PGC estimates, amounting to approximately

30.5 TCF. The percent reduction due to duplication

for the total NPC tight gas resource (including both

tight sands and Devonian shales) is 8 percent for the

gas recoverable at $5.00 and 5 percent for the maximum recoverable gas.

The amount of overlap, then, is not vitally important in terms of reducing the size of the total additional

resource from unconventional reservoirs. More important are the specific areas of overlap, since these ocTable C-4.–Overlap of PGC and NPC

Resource Estimates

NPC total recoverable gas

PGC total tight sands and Devonian shales Total

tight gas At $5.00a Maximum overlap

171.83 TCF —— 376.6 TCF 633.5 TCF 30.5 TCF

aGas recoverable at $5.00/MCF (1979$), 15%. DCF ROR, assuming base technology,

SOURCE: Office of Technology Assessment
App. C—Double Counting ● 2 4 1

cur in areas which have been predicted to be main

contributors to supply in the next 20 years.

For example, the NPC estimates that the Rocky

Mountain Basins will contribute over 14 TCF to production over the next 20 years and 43 TCF to reserve

additions, according to its standard development scenario. It is likely that much of this production will be

from the blanket formations, as these are generally the

more profitable prospects. However, if these formations are already partially counted in conventional resource estimates, and these estimates are used in forecasting supply, what the NPC is estimating cannot be

considered as additions to existing projections of

future conventional supply.

Another primary contributor to the NPC reserve addition and supply forecasts in the next 20 years is the

Greater Southwest, including primarily the Cotton

Valley, the Val Verde Ozona-Sonora Trend and the

Edwards Lime Trend. The Cotton Valley Trend potential, however, appears to be duplicated in the PGC

report; thus it, also, cannot contribute additional reserves or supply.

This analysis deals only with the overlap between

the PGC and the NPC assessments of the natural gas

resource. Similar duplication is Ii kely to exist in other

geologically based estimates such as the U.S. Geologic

Survey’s (USGS) estimate of undiscovered recoverable

gas resources.10 However, because of varying approaches to estimating the resource, no categorical

statement of the amount of overlap between conventional and unconventional resource estimates can be

made.

A final comment needs to be made regarding the

PGC estimates of tight gas recoverable from formations at depths greater than 15,000 ft. This gas represents a resource additional to the N PC estimated tight

sands resource, In general, these resources would be

considered even less economic to produce than the

NPC gas because of the higher costs and greater technical difficulty of drilling and fracturing at these depths.

However, Potential Gas Committee members felt that

the technology did exist to produce tight gas from

deep formations, and under certain conditions there

might be sufficient incentive to produce this gas.

Nevertheless, we feel that the 89 TCF of deep tight

gas in the PGC estimate should be regarded with at

least as much, if not more, caution than the NPC estimates in terms of evaluating their potential for contributing to near- and mid-term supply.

10G L, Dolton et al., Es(jfna(es of Undlscmwed Recoverable COfJ\’entlonal Resources of OIl and (2sIn the United States, U.S. Geological Survey

Circular 860, 1981.
Appendix D

Glossary

adsorbed gas: Natural gas that is physically bound to

the surfaces of the reservoir rock.

anaerobic: Conditions that exist only in the absence

of oxygen.

anisotropy: A characteristic of certain rocks wherein

certain properties, such as permeability, exhibit different values when measured along axes in different

directions.

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).

blanket formations: Thin gas-bearing formations that

take the form of one or several stacked layers extending laterally over a wide area.

borehole shooting: A method of stimulating increased

gas flow by detonating explosives inside the borehole of a well.

cleat: The pervasive, vertically oriented natural fracture system in coal seams.

coal seam (coalbed) methane: Natural gas formed as

a byproduct of the coal formation process and

trapped in the coal seam.

combination trap: A trap for oil or gas that has both

structural and stratigraphic elements.

deviated drilling: Drilling that has been deliberately

angled away from the vertical.

Devonian shale gas: Gas trapped in the shales of Devonian age located in the Eastern United States, primarily in the Appalachian, Michigan, and Illinois

basins.

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 well.

fault: A sudden displacement of rock strata along a

fracture.

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 of individual beds

or units with similar physical characteristics or

origin.

formation damage: A reduction in permeability caused

by drilling, fracturing, or producing a well–e.g.,

by the plugging of pores by water-sensitive clays

dislodged or caused to swell by water-based fracture fluids or drilling fluids.

formation water: Water present in a water-bearing formation under natural conditions, as opposed to introduced fluids, such as drilling mud.

infill drilling: Drilling at a smaller spacing than called

for in the original development plan, designed to

speed up production and/or increase ultimate

recovery.

interference: A condition whereby adjacent wells in

a field are close enough together that their areas

of (pressure) influence overlap, generally reducing

“per well” gas recovery below the level that would

be obtained with an isolated well.

lens: An individual reservoir in a tight Ienticular formation (see below), often oval in cross-section.

Ienticular formation: A thick formation containing

large numbers of small, separate, lens-like reservoirs interspersed with impermeable shales or coal.

Iineament: A linear feature of the Earth’s surface that

may reveal a subsurface feature such as a fault.

log, well log: Measurements of the physical properties of a reservoir, taken while drilling, generally

by lowering measurement devices down the well bore.

massive hydraulic fracturing (MHD): Creation of large,

manmade fractures in reservoir rock by pumping

fluids into a well under high pressures. “Frac” jobs

generally are considered “massive” when the volume of fluid used is 100,000 gallons or more, but

there is no universally accepted criterion.

methane: The primary constituent of natural gas, the

gaseous hydrocarbon CH4

.

natural fracture system: A series of fractures, often

aligned in some way, created by natural processes.

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 areal 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 well: See extension test.

pay: A rock stratum or zone that yields oil or gas.

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.

242
App. D—Glossary . 243

play: A rock formation or group of formations within

a sedimentary basin with geologic characteristics

simiIar 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.

proppant: Small particles of a hard material (sand,

bauxite, etc.) that are suspended in fracturing fluid,

to be left behind when the fluid is removed to prevent the created fractures from closing under the

pressure exerted by the overlying rock.

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: The portion of the total gas resource base

that has been identified by drilling and estimated

directly by engineering measurements, and that is

recoverable at current prices and technology.

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 oiI 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.

stimulation: Any process that mechanically or chemically disturbs the reservoir rock in order to increase

gas flow to the well.

stratigraphic trap: A trap for oil or gas, resulting from

changes in rock type, porosity, or permeability, that

occurs as a result of the sedimentation process

rather than structural deformation.

structural trap: A trap for oil or gas resulting from folding, faulting, or other deformation of the Earth.

thermal maturity: The extent to which the organic

matter in sedimentary rocks has been “cracked”-

broken into simpler molecules–by heat.

trap: Any barrier to the upward movement of oil or

gas that allows either or both to accumulate. A trap

includes a reservoir rock and an overlying impermeable roof rock; the contact between these is concave, as viewed from below. See also stratigraphic,

structural, and combination traps.
Index
Index

AAPG. See American Association of Petroleum

Geologists

abandonment pressures, 73-75, 93, 228

abiogenic gas. See “deep source gas”

acidizing, 74

Alabama, 8, 59, 133, 207, 219

Alaska, 7, 17, 26, 43, 53, 66, 106, 114-115

Alaskan Natural Gas Transportation System, 112,

114-115

Alaskan Natural Gas Transportation Act of 1976,

114

American Association of Petroleum Geologists, 62

American Gas Association, 9

addition to reserves and, 24, 54, 83

conventional/u nconventional boundary and, 140

decline in RIP and, 95

economic incentives to recovery and, 66-69

extensions and new discoveries and, 88-91

import estimate, 113, 115

production estimate, 106-107

tight gas estimate, 169-171

Anadarko Basin, 22, 45, 57, 65-66, 76, 88, 168

anaerobic process, 29, 242

ANGTS. See Alaskan Natural Gas Transportation

System

anticline, 30, 242

Antrim shale, 183

Appalachian Basin, 57, 149

coal seam methane in, 207, 211

Devonian shales in, 8, 129, 132, 179-181, 183,

185-186, 190-203

undiscovered resources in, 59

aquifers, geopressurized, 6, 26, 121

Arkansas, 59, 88, 168

Arkoma Basin, 168, 211

Atlantic shelf, 46

Austin Chalk, 88

availability, natural gas. See supply, natural gas

Baltimore Canyon, 22, 53, 76

Big Sandy Field, 129

biogenic gas, 29-30, 147-149

biomass, 26

bituminous coal, 218-219

Black Warrior Basin, 8, 136, 149, 207, 219, 221

Blanco Basin, 73

blanket formations, 125, 141-142, 151, 153, 230,

242

Border Gas, 112

borehole shooting, 200, 242

Bromberg/Hartigan, 19-20, 49, 61

“bubble” of gas, 3, 17, 25

California, 53, 57, 114

Canada, 7, 17, 26, 106, 111, 113-115

carbon dioxide, liquid, 188-189

Carnegie Natural Gas Co., 207

“Circular 725, ” 47, 54

“Circular 860,” 47, 50, 54

“cleat,” 134, 207, 212, 215-216, 242

coal seam methane

defined, 6, 133, 207

estimate uncertainties, 7-9, 134-136, 211-212

FERC estimate, 135, 210

in-place estimates, 134-135, 209-212

NPC projections, 3, 209-210, 217-219, 221-222

production, 7, 207, 212-224

as recoverable resource, 3, 5, 7-10, 26, 29,

121-122, 133-136, 210-212, 217-221

regions, 208

Colorado, 139, 233

Colorado School of Mines, 51

conservation, 3, 94, 112

Consolidated Coal Co., 215

conventional gas. See also proved reserves;

recoverable resources; reserves; resources

defined, 5

parameters of supply estimate, 5, 50

production cycles, 20

resource estimates of, 5-9, 19

unconventional boundary, 140

year 2000 production, 6-7, 18

Corcoran Cozette, 148

data availability, 18

decontrol, iii, 9, 75

“deep source gas, ” 6, 29, 43, 53, 60, 66, 75-76,

121

deliveries, curtailment of, 3

Delphi approach, 42-43, 48, 50, 192, 196

Delta provinces, 71

demand for gas

exploration and, 5, 17, 45

production and, 5-6, 17, 94

Denver Basin, 71, 76, 126, 144, 147-148, 157

depletion, 39, 41, 69, 105

resorption, 212-213

Deul and Kim, 135, 210

development strategy, 5

Devonian shales

in Appalachian Basin, 8, 129, 132,

183, 185-186, 190-203

areas found, 8, 129, 132, 179-187,

defined, 6, 128, 179-182

development problems, 122, 130

79-181,

90

247
248 ● U.S. Natural Gas Availability: Gas Supply Through the Year 2000

FERC estimate, 182

in-place resource, 182-186, 190

NPC projections, 3, 131, 182-183, 186, 191,

194-196, 199-203

OTA assessment (1977), 192

production from, 7, 181-182, 190-203

as recoverable resource, 5-6, 8-10, 26, 121-122,

128-133, 190-201

resource estimates, 131-133, 182-183, 186,

190-201

dewatering systems, 10, 212-214

discovery, natural gas

demand and, 5, 17, 45

estimate of prospects, 17-18, 39

extrapolation from past trends, 21, 23-24, 43-45,

66, 88

inadequate indicators for, 23

new field, 24-25, 45-46, 61-64, 81-90, 98-99,

1 0 5

technical prospects for, 5, 45

double counting, 167, 236-241

Drew, L. J., 71

drilling, 5, 24. See also infill drilling

advances in deep, 22

costs, 22, 66-67, 76, 94, 215

deviated, 189, 242

directional, 189

exploratory, 33-34, 44, 46, 54, 73

improved technology, 10, 83

low- v. high-risk, 62, 68

NPGA and, 66

success rates, 68-69

East Anschutz Ranch, 66

Eastern Gas Shales Project, 135, 182, 186, 197

Eastern Overthrust Belt, 7

economic conditions, natural gas and, 20, 24, 41,

45, 66-67

Effects of Decontrol on Old Gas Recovery, iii

EIA. See Energy Information Administration

Electric Power Research Institute, 3

Ellsworth shale, 183

energy conservation. See conservation

Energy Information Administration, 10, 24, 34,

88-90, 95, 107

“Enhanced Recovery of Unconventional Gas,”

193

environmental constraints, 223

Equitable Gas Co., 207

exploration, natural gas, 69

basic techniques, 33-34

evolution of technology, 17, 20, 82-83

high-risk, 62, 67-68

history of, 57

unconventional gas, 130-131, 156, 189-190

Export Administration Act of 1979, 114

“extensions,” 23-24, 34, 65, 75, 81, 86-90,

98-102, 242

Exxon, 49, 60, 76, 107

Federal Energy Regulatory Commission, 121-122

coal seam methane estimate, 135, 210

Devonian shale estimate, 182

tight gas estimate, 123-124, 126, 139-140,

142-144, 166, 236

Federal Power Commission, 66, 121, 126, 142-144

foamed fluids, 188

FERC. See Federal Energy Regulatory Commission

Fletcher Field, 94

Florida, 59

Fort Union, 148

fracturing, 74, 94

coal seam methane, 216-217

Devonian shales, 130, 187-189

technologies, 229-235

tight gas, 8-10, 125, 127, 139, 149-154, 163-165

Garrett, R. W., 49

gasfields

field size, 42, 62-65, 69-73

new discoveries, 24-25, 45-46, 61-64, 81-90,

98-99, 105

new gas from older, 7, 21-22, 24, 46, 66, 73-75,

227-228

role of small, 7, 21, 53, 66, 69-73, 84

gas hydrates, 6, 121

Gas Research Institute, 9

coal seam methane estimate, 135-136, 209-210,

215, 217, 219, 222-223

mineback experiments, 233

tight gas estimate, 127, 156-158, 160-164, 166,

169-172, 174

Georges Bank, 7, 22

Gold, Thomas, 29

“growth factor” projections, 98-102

Gulf of Alaska, 46, 53, 76

Gulf of Mexico, 7, 22, 53, 57, 59-60, 71, 76, 84,

95

history-based estimates, 43-46, 52-56, 60-61, 66,

99, 203

Hubbert, M. King

methodology of, 54-56, 60-61, 81-82, 103-104

OTA assessment of estimate, 77, 105

resource estimate, 19-20, 39, 41, 43, 47, 49, 65

Hugoton field, 62, 65, 73, 95

Huron Intervals, 197-198

hydrates, gas, 6, 121

hydrocarbons, liquid, 29-30
Index ● 2 4 9

IGT estimate, 49

Illinois, 114, 129, 179, 211

imports, 7, 26, 39, 111-116

infill drilling, 73-75, 93, 228, 242

Jensen Associates, Inc., 99

Kansas, 57, 59, 65, 73, 95

Kentucky, 129, 192-193, 197, 199

Kuuskraa and Meyer (KM), 133, 135, 209-210,

217-219, 221

leases, 46, 83, 123, 190, 201-202

legal constraints, 3, 222-223

lenses, 8, 10, 125, 242

Ienticular formations

defined, 125, 142, 242

gas recovery from, 127, 148, 151, 154, 156,

162, 172, 175, 230

Lewin & Associates

coal seam methane estimates, 219

Devonian shale estimates, 131-134, 182-183,

191-194, 197-203

Mexican gas and, 113-114,

tight gas estimates, 126-127, 142, 144-145,

157-159, 161-162, 165, 168-170, 172-174

unconventional resource estimates, 121

limestone formations, 6, 121, 123, 139, 141, 183

liquefied natural gas, 7, 17, 26, 106, 112, 115-116

LNG. See liquefied natural gas

logging, 9

Louisiana, 59, 65, 84, 88, 91, 95

Lower Cretaceous-Jurassic, 148

low-permeability reservoirs, 6, 18, 25, 121,

123-124, 139

McKelvey Box, 40-41, 45

Mesaverde, 148

methane. See coal seam methane

Methane Recovery From Coalbeds Project, 135,

211-212, 221

Methanol, 115

Mexico, 7, 17, 26, 106, 111-113

Michigan, 129, 179, 183

Mineral Leasing Act, 223

mine safety, 8

Mississippi, 59

Mobil Corp., 49

models, 81

Monsanto Corp., 131, 196

Monte Carlo simulation, 47-48, 184

Morgantown Energy Technology Center, 192

Mound Facility, 131, 182, 185-186, 190-191,

196-197

Multiwell Experiment, 163, 233

National Academy of Science, 121, 135

National Energy Board, 111, 113

National Energy Plan (Canada), 113-114

National Gas Survey, 121, 142

National Petroleum Council

coal seam methane estimates, 3, 209-210,

217-219, 221-222

Devonian shale estimates, 3, 131-136, 142,

144-149, 182-183, 186, 191, 194-196,

199-203

tight gas estimates, 3, 124, 126-128, 142,

144-149, 154, 157-175, 236-241

unconventional gas estimates, 3, 121

natural gas basics

defined, 29

how formed, 29-31

nonassociated, 30

where found, 30-31

Natural Gas Policy Act of 1978, 22, 66, 74-76,

121-123, 139, 227-228

Nehring, Richard, 52-54, 58, 60, 71, 77

New Albany shale, 183

New Mexico, 8, 65, 133, 207

“new pool discoveries, ” 23-24, 34, 65, 81, 86-90,

98-102

NGPA. See Natural Gas Policy Act of 1978

nitrogen foam, 188, 216

Northern Great Plains, 165-166

tight gas and, 8, 126-127, 140, 147-150, 157,

161, 165-166, 168-169, 172-175

North Slope gas, 112, 114-115

NPC. See National Petroleum Council

offshore natural gas, 8, 25, 46, 50, 57, 60

Ohio, 57, 132-133, 189, 192, 197-200, 203

Oklahoma, 59, 65, 73, 94, 168

onshore deep gas, 7-8

Outerbanks, California, 53

Outer Continental Shelf, 66

Overthrust Belt, 53, 57, 65-66. See a/so Eastern

Overthrust Belt; Western Overthrust Belt

Pennsylvania, 207

Pennsylvania Supreme Court, 223

permeability, 6, 30, 94, 145

Permian Basin, 22, 71, 73, 76, 88

PGC, See Potential Gas Committee

Piceance Basin, 126, 144, 146-147, 157, 211, 233

pipeline imports, 7, 17-18, 26, 39, 112

policy, energy, 9-10

policy, natural gas, 9-10, 66

Potential Gas Committee

Devonian shales and, 52

OTA assessment of estimate, 77, 82

production estimate, 103-106
250 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

resource estimate, 3, 5, 17, 19, 39-40, 49-52,

58-60, 65, 100

tight gas estimate, 236-241

unconventional gas estimate, 122, 124, 167-168

Potential supply of Natural Gas in the United

States, 236

Powder River Basin, 76

Powerplant and Industrial Fuel Use Act of 1978,

iii, 3

prices

controlled, 22, 67, 74, 76

conventional gas, 5-6

declining, 3, 22, 66

and economics of recoverability, 3, 5, 9, 17, 41,

45, 66-67, 73-76, 83, 163, 193-194, 201

increased gas, 3, 9

market level, 9, 75

pressures to decontrol, iii, 9, 75

technology development and, S, 9

tight gas and, 8

unconventional gas and, 5, 7-8, 121, 139, 163,

193-194, 201

wellhead, 5, 17, 26

probabilistic estimates, 46-48, 52

production, natural gas. See also coal seam

methane; Devonian shales; tight gas

AGA estimate, 106-107

assessment of, 17-26, 39, 97, 100-106

bases for OTA projections, 25

basic mechanics of, 35

coal seam methane, 7, 207, 212-224

demand and, 5-6, 17, 94

enhancement, 22

1950-85, 4, 19

pessimistic scenarios for, 5, 39, 101

potential, 81-107

projection for year 2000, 6-7, 17-19, 81, 97,

100-102, 105-106

tight gas forecasts, 7, 168-175

uncertainties in estimates of, 5-7, 18-25, 105-106

USGS estimate, 103-105

proppants, 125, 150, 152, 188, 216, 243

proved reserves, 40. See also reserves; recoverable

resources

additions to, 4, 18, 23-24, 43, 61, 65, 81-97

current level of, 3-4, 17, 23

rate of additions to, iii, 18

revisions to estimates, 90-93

total U. S., 1977-1983, 34

uncertainties in calculations, 46-47

withdrawals, 18

Prudhoe Bay Field, 111, 114

Pulle, C. V., and Seskus, A. P., 131, 191-192,

195-196, 199-200

pumps, 213, 217

Purchase Gas Adjustment, 122

RAND Corp.

OTA assessment of estimate, 77, 105

resource estimate, 19-20, 47, 49, 52-54, 61-62

Reagan, Ronald, 114

recession, effect of, 112

recoverable resources. See also coal seam

methane; Devonian shales; tight gas

alternative estimates, 49, 55

Hubbert estimate, 19-20, 39, 41, 43, 47, 49, 65

PGC estimates of, 3, 5, 17, 19, 39-40, 49-52,

58-60, 65, 100

price changes and, 3, 5, 9, 17, 41, 45, 66-67,

73-76, 83

uncertainties in estimates, 5, 8, 17-18, 52, 58

USGS estimates of, 3, 5, 39-40, 47-50, 59-60,

65, 82, 100, 104

regions, gas supply, 4, 31, 59, 100-102

regulations, government, 45, 66, 75, 94

reserves. See also proved reserves

additions to, 4, 18, 23-24, 43, 54, 61, 65, 81-97

defined, 3, 40

“inferred,” 49

1981-2000, 3, 97, 100, 102

OTA estimate of, 8, 39-50, 56-74, 97

reserves-to-production ratio

decline in, 95

implications, 23-25, 81, 93-96

projected, 19, 96-97

for years 1945-80, 95

reserves, proved. See proved reserves

resources. See also recoverable resources; supply,

natural gas

credibility of estimates, 60-61, 77

defined, 3

estimate comparison problems, 41, 45-47, 60-61

geology-based estimates, 42-43, 45, 48, 52-53,

60

OTA assessment of base, 39-50, 77, 82

PGC estimate, 3, 5, 17, 19, 39-40, 49-52, 58-60,

100

uncertainties in extrapolating discovery trends,

23-24

uncertainties of magnitude and character, 7-9,

18-24

undiscovered, 54, 59, 82

USGS estimate, 3, 5, 17, 19, 39-40, 47-50,

59-60, 65, 82, 100, 104
Index 251

responsive reserves, 228

“revision s,” 23-24, 34, 65, 75, 81, 98-102

risk taking by industry, 83

rocks, source, 30, 35, 46, 125, 243

R/P ratio. See reserves-to-production ratio

SAI estimate, 196-197

sandstone formations, 6, 121, 123, 141, 147, 183

San Juan Basin, 8, 65, 73, 144, 157, 207, 211, 220

satellite imagery, 156

Scheunemeyer, J. H., 71

sedimentary basins, 29-30

shale oil, 188

Shell Corp., 19, 49, 76, 107, 227-228

shortages, 5

Soter, Steven, 29

Southeast Georgia Embayment, 22, 53, 76

South Texas Lobo Trend, 88

stratigraphic traps, 7, 22-23, 30, 53, 66, 76-77, 243

“stripper” wells, 22

subduction, 71

supply, natural gas

long-term trends, 3, 5, 17

national perception of (1 978), 3, 17

for next few decades, 5, 39

private sector forecast, 107

shortage, 5

short-term, 3, 17

surplus, 3, 17, 25, 113

warning of shift in, 9-10

synthetic gas, 18, 26

tailored pulse loading, 188, 234

technology, new

and currently uneconomic production, 5, 9

development, 9

forecasting problems, 7, 17, 41

fracturing, 229-235

gas recovery and, 3-5, 9, 24, 45, 73, 83

Texas, 59, 65, 84, 88, 95

Texas Railroad Commission District, 73, 87, 91

tight gas

AGA estimate, 169-171

deep, 167-168

defined, 6, 123-125, 139-140

FERC estimates, 123-124, 126, 139-140, 142-144,

166, 236

in-place estimates, 144-149, 168

NPC projections, 3, 124, 126-128, 142, 144-149,

154, 157-175, 236-241

PGC estimate, 236-241

price, 8

production forecasts, 7, 168-175

recoverable, 5-6, 8-9, 122-128, 139-149, 157-168

sands, 26, 52, 88, 121, 139, 156, 174

uncertainties in estimates, 139, 145-149,

161-168, 236-241

TransAlaska Gas System, 112

traps, petroleum, 30, 32, 46, 243

TRW, 135

unconventional gas, 26, 39. See a/so coal seam

methane; Devonian shales; tight gas

defined, 5, 121-122

exploration, 130-131, 156, 189-190

Federal role and, 121

NPC supply projections, 3, 121

parameters of supply estimate, 5-7, 50, 121-123

PGC estimate, 122, 124, 167-168

prices, 5, 7-8, 121, 139, 163, 193-194, 201

USGS estimate, 103-105, 122, 131, 134, 183-186

U.S. Bureau of Mines, 223

U.S. Congress

Alaska and, 114

perception of long-term supply, iii

U.S. Department of Energy

contractors, 121, 126, 142

Eastern Gas Shales Project, 135, 182, 211-212,

221

Methane Recovery From Coalbeds Project, 135,

211-212, 221

mineback experiments, 233

Morgantown Energy Technology Center, 192

policy, 10

research, 156

resource estimate, 134, 210

U.S. Department of the Interior, 223

U.S. Geological Survey

coal resource data, 209-210

Devonian shale estimates, 182-185

gasfield growth estimate, 99

production estimate, 103-105

resource estimate, 3, 5, 17, 19, 39-40, 47-50,

59-60, 65, 82, 100, 104

unconventional gas estimates, 103-105, 122,

131, 134, 183-186

USGS. See U.S. Geological Survey

U.S. House of Representatives

Committee on Energy and Commerce, iii, 4

Subcommittee on Fossil and Synthetic Fuels, iii,

4

U.S. Senate

Committee on Energy and Natural Resources, iii,

4

Subcommittee on Energy Research and Development, iii, 4

U.S. Steel, 136, 219

U.S. Steel v. Hoge, 2 2 2
252 . U.S. Natural Gas Availability: Gas Supply Through the Year 2000

Van Driest, 11, E. R., 49, 52

Ventura Basin, 53

Warrior Basin, 133, 211

Wattenberg Field, 139, 144

well. See also well stimulation

classification, 33-34

completions, 67

conventional v. tight gas, 150

expenditures for, 67

exploratory, 69

head prices, 5, 17, 26

horizontal, 134, 215

logs, 155, 235, 242

measurement technology, 10

number drilled, 43, 65, 67, 69,

workover, 74, 93

well stimulation

defined, 243

Devonian shales

215-216

new gas from old fields, 73-75

safety factors, 223

technology, 8-9

tight gas and, 153-154

Western Overthrust Belt, 4, 7, 22, 45-46, 51, 53,

60, 76, 88-89, 189-190

West Virginia, 129, 132-133, 192-193, 197-200,

203, 207

Whitney Canyon/Carter Creek, 66

wiIdcats

new field, 33-34, 45-46, 54, 56, 61-65, 68-69

success rate, 69, 84, 144

Wiorkowsky, J. J., 19, 49, 61

Wise and Skillern, 135, 210

Wyoming, 95

201

Zielinski, R. E., and Mclver, R. D., 131, 191-192,

196-197, 199-200

and, 130, 187, 189, 203,

0