Status Report on the Gas Potential From Devonian Shales of the Appalachian Basin

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Status Report on the Gas Potential From Devonian Shales of the Appalachian Basin

November 1977

NTIS order #PB-274856



Library of Congress Catalog Card Number 77-600061

For sale by the Superintendent of Documents, U.S. Government Printing OfficeWashington, D.C. 20402 Stock No. 052-003-00500-0

i i



TECHNOLOGY A SSESSMENT BOARD DANIEL DE SIMONE

EDWARD M. KENNEDY, MASS., CHAIRMAN A C T I N G DI R E CT O R

LARRY WINN, JR., KANS., VICE CHAIRMAN O FFICE OF TE C H N O L O G Y A S S E S S M E N T

ERNEST F. HOLLINGS, S.C. OLIN E. TEAGUE, TEX.

HUBERT H. HUMPHREY, MINN. MORRIS K. UDALL, ARIZ. W ASHINGTON , D.C. 20510CLIFFORD P. CASE, N.J. GEORGE E. BROWN, JR.. CALIF.

TED STEVENS, ALASKA CLARENCE E. MILLER, OHIO

ORRIN G. HATCH, UTAH JOHN W. WYDLER, N.Y.

November 23, 1977

The Honorable Ted Stevens

Technology Assessment Board

Off ice of Technology Assessment

United States Senate

Washington, D.C. 20510

Dear Senator Stevens:

On behalf of the Board of the Office of Technology Assessment. I

am pleased to forward the results of the assessment you requested

of the potential of enhanced recovery of oil and Devonian gas in

the United States.

This report, A Status Report on the Potential for Gas Production

From the Devonian Shales of the Appalachian Basin, is the first

to be completed. Work on the enhanced oil recovery report will

be completed soon.

These assessments will provide additional perspective on future

U.S. energy supplies and we hope that they will be helpful as the

Congress continues its review of national energy policy.

Enclosure

. . .Ill



Foreword

This report is an analysis by the Office of Technology Assessment of the potential

for producing gas from the Devonian shales of the Appalachian Basin. It was prepared

in respo nse to a reque st f rom Sena tor Ted Stev ens, a m em be r of the Tec hnolog y

Assessment Board.

Few data are now available on the distribution and physical and chemical charac-

terist ics of the Devonian shales of the Appalachian Basin. A comprehensive assess-

ment must therefore await the results of extensive dri l l ing throughout the region. In

the meantime, however, this report, which is based on plausible economic, geologic,

and technological assumptions, provides reasonable estimates of the recoverable gas

in the Basin.

The Devonian Brow n shales of t he Ap pa lac hian Basin, so-ca lled be c ause they ac -

cumulated during the Devonian age, have the potential of contributing signif icantly to

the U.S. natural ga s supp ly. It c a n rea sona b ly be a ssume d tha t t hese sha les c ont ain a s

much as 15 to 25 tri l l ion cubic feet of readily recoverable reserves that could be pro-

duced economical ly over a 20-year period at prices of $2.00 to $3.00 per thousand

c ub ic fee t. These reserves c ould ultima tely sup po rt a prod uc tion rate o f ab out 1 trillion

cubic feet of natural gas per year, which is about 5 percent of the current level of

domestic gas production. Such a production rate is likely to require extensive drilling

(on the order of 69,000 wells), a considerable expansion of the gas pipeline collecting

network and, therefore, up to 20 years to achieve. These estimates are less optimistic

than some that have been reported by the Energy Research and Development Ad-

ministration and others, but they are generally consistent with current work at the U.S.

Geological Survey.

This report is another in the series of energy assessments that are being provided

to the Congress for its consideration in the development of national energy policy.

DANIEL DeSIMONE

Act ing Di rector

Office of Technology Assessment

.



OTA EnergyAdvisory Committee

Milton Katz, Chairman

Director, International Legal Studies, Harvard Law School

Thomas C. Ayers George E. MuellerPresident and Chairman President and Chairman

of the Board of the BoardCommonwealth Edison Company System Development Corporation

Kenneth E. BouldingProfessor of EconomicsInstitute of Behavioral ScienceUniversity of Colorado

Eugene G. FubiniFubini Consultants, Ltd.

Levi (J. M.) LeathersExecutive Vice PresidentDow Chemical USA

Wassily LeontiefDepartment of EconomicsNew York University

Gerard PielPublisher, Scientific American

John F. Redmond, RetiredShell Oil Company

John C. SawhillPresidentNew York University

Chauncey StarrPresident, Electric Power

Research Institute

vi i



o

Enhanced Oiland Gas RecoveryAdvisory Panel

Richard Perrine, Chairman

University of California

Gerard BrannonGeorgetown University

Frank CollinsOil Chemical and Atomic Workers

International Union

Robert EarlougherGodsey-Earlougher, Inc.

Lloyd Elkins

Amoco production CompanyRobert M. Forrest

Columbia Gas System Service Corp.

Claude HocottUniversity of Texas

John M. McCollamGordon, Arata, McCollam

and Watters

Walter MeadUniversity of California

Fred H. PoettmannMarathon Oil Company

Lyle St. AmantLouisiana Wildlife and

Fisheries Commission

Hal Scott

Florida Audubon SocietyA.B. Waters

Halliburton Services

Ex officio

John Redmond, RetiredShell Oil Company

NOTE: The Advisory Panel provided advice, critique, and assistance throughout this assessment, for whichthe OTA staff is deeply grateful. The Advisory Panel, however, does not necessarily approve, disapprove, or en-

dorse all aspects of this report. OTA assumes full responsibility for the report and the accuracy of its content.

Viii



OTA EnergyProgram Staff

Lionel S. Johns, Program Manager

Robert J. Rebel, Project Leader

Thom as A. Cotton, Asst. Project Leader

External Support Staff Ad ministrative Sta ff

H.C. Slider Lisa Jac ob son

Robert L. Bates Linda ParkerEdward W. Erickson Cindy Pierce

William L. Peters Joanne Seder

William H. MiernykRobert J. Yedlosky

OTAPublicationsStaff

John C. Holmes, Publications Officer

Kathie S. Boss Joanne HemingCynthia M. Stern



Contents

Chapter

1.

Il.

Ill.

Iv.

v .

v i.

EXECUTIVE SUMMARY. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .The Resource . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Gas Potential. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Policy Options To Encourage Shale Gas Production . . . . . . . . . . . . . . . . . . .Price Policies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Tax Policies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Research and Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Information Collection and Dissemination . . . . . . . . . . . . . . . . . . . . . . .Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

The Natural Gas Situation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

REGIONAL EFFECTS OF PRODUCING GAS FROM DEVONIAN SHALE, . . . .

THE RESOURCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Geographic Extent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Terminology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Origin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Thickness. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Attitude and Depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Composition. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Fractures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Natural Gas in the Brown Shale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

CENTRAL RESERVOIR CHARACTERISTICS . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Reservoir Evaluation Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Core Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Permeability, Porosity, and Saturation, . . . . . . . . . . . . . . . . . . . . . . . . . .Core Data Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Flow Tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Logging , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Stimulation Techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

ECONOMICS OF BROWN SHALE GAS PRODUCTION . . . . . . . . . . . . . . . . .

Price, Tax, and Other Economic Assumptions . . . . . . . . . . . . . . . . . . . . ., . .Price Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Tax Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Other Economic Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Cost and Technical Characteristics of Brown Shale

Gas Production in Three Localities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Analytical Results for After-Tax Net-Present Values Under Alternative Price

and Tax Assumptions . . . . . . . . . . , . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Extent of the Economically Producible Area . . . . . . . . . . . . . . . . . . . . . . . . . .

Page

3

3

3

46

6

6

7

7

7

11

11

15

19

19191921

21

232324

31

323232343435

35

45

464647

48

51

5457

xi



An Estimate of Readily Recoverable Resources . . . . . . . . . . . . . . . . . . . . . . . 59General Observations and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

VII. BARRIERS TO BROWN SHALE GAS PRODUCTION ....... . . . . . . . . . . . 69

Obstacles to Development Using Available Technology . . . . . . . . . . . . . . . 69Obstacles to Advances in Shale Gas Technology . . . . . . . . . . . . . . . . . . . . . 70

VIII, POLICY OPTIONS TO ENCO URAG E SHALE GA S PRODUCTION . . . . . . . . 75

Price Policies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 75Tax Policies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76Research and Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76Information Collection and Dissemination . . . . . . . . . . . . . . . . . . . . . . . . . . . 77Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

lx. SUMMARY AND CONCLUSIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81



LIST OF TABLES

Table Number Page

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

14.

15.

16.17.

LIST

Proved Reserves of Natural Gas in the United States, 1959 -76 . . . . . . . . . . . 11U.S. Produc tion o f Natural Gas and Cu rta ilment s of Firm Custo mers, 1959-76 12Comparison of Core Data for Brown Shale and Reservoir Rocks from Other

Gas Producing Areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31Production Statistics of Natural Gas From Brown Shale in Three Localities . 51Direct Investment Costs for Producing Wells in Brown Shale . . . . . . . . . . . . 52Effect of Reduction in Initial Investment Cost . . . . . . . . . . . . . . . . . . . . . . . . 52Effect of Dry Holes on the Cost of Producing Wells . . . . . . . . . . . . . . . . ... , 53After-Tax Net-Present Value of Brown Shale Natural Gas Wells in Three Loca-

tions-case A*. . . . . . . . . . . . . . . . . . . . . . . . . . . . . , . . . . . . .After-Tax Net-Present Value of Brown Shale Natural Gas Wells

tions—Case B* . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .After-Tax Net-Present Value of Brown Shale Natural Gas Wells

tions—Case C*. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .After-Tax Net-Present Value of Brown Shale Natural Gas Wells

. . . . . . . . . . . 54

n Three Loca-. . . . . . . . . . . 55n Three Loca-. . . . . . . . . . . 55n Three Loca-

tions-Case D*. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56

Estimated Gross Production of Natural Gas of the Five Largest ProducingStates, 1976 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60Typical Well Costs (1976 Constant Dollars) High-Quality Brown Shale Well 63Typical Well Costs (1976 Constant Dollars) Medium-Quality Brown Shale

Well. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63Typical Well Costs (1976 Constant Dollars) Medium-Quality Brown Shale

Well. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64Typical Well Costs (1976 Constant Dollars) Lower-Quality Brown Shale Well 64Typical Well Costs (1976 Constant Dollars) Lower-Quality Brown Shale Well 65

OF FIGURES

Figure Number Page

1.

2.

3.

4.5.

6.7.

8.9.

10.1 1’.

Proved Reserves of Natural Gas in the United States, 1959-76 . . . . . . . . .Projected U.S. Natural Gas Production, 1975 -2000 . . . . . . . . . . . . . . . . . . . . .The Appalachian Basin. ... , . . . . . . . . . . . . . . . . . . . . ., , , ., . . . . . . . . . . . . . .West-East Cross Section Across Central West Virginia ... , , , . . . . . . . . . . . .Model Showing Fractures Generated by Deep Seated Basement Faulting and

Propagated upwards into the Devonian Shale. . . . ... , . . . . . . . . . . . . . . .Averaged Production Decline Curves for 50 Devonian Shale Gas Wells. . . .Devonian Shale Major Gas Production Areas . . . . . . . . . . . . . . . . . . . . . . . . . .Locations of Core Wells in a proposed Inventory of Brown Shales by ERDADiagram Showing Relationship of Maximum Principal Stress and Least Prin-

cipal Stress to the Plane of an Induced Hydraulic Fracture. , . . . . . . . . , . .Deviated Wells and Earth Fracture Systems Process , , ., ., . . . . . . . . . . . . . .Comparison of Gas Production From Brown Shale Wells and a Typical

Offshore Gas Well. . . . . . . . . . . . . . . . . . . . , , . . . . . . . . . . . . . . ., . . . . . . . .

11

1220

22

25263434

3739

50

Xlli



1. Executive Summary



1. Executive Summary

Declining d ome stic reserves of natural gas and seam s of the Eastern United State s, and Devonian

a widening gap between d omest ic product ion shales of the Appalachian Basin.and demand has led to new interest in several un- This report examines the potential for produc-conventional or exotic sources of the fuel. These ing gas from one of these sources—the Devonianinclude the geopressurized zones off the gulf shales—Using existing technology under a varietycoast, the tight sands of the Western Basin, coal of economic assumptions.

Findings

A major finding of the analysis is that Devo-nian shale, unlike the other exotic sources, can betapped for natural gas without the development

o f comple te ly new product ion equ ipment o rtechniques.

A second finding is that the so-called “Brown”Devonian shales of the Basin could yield between15 trillion cub ic feet * (Tc f) and 25 Tc f of na turalgas during the first 15 to 20 years of production.Over an additional 10 to 30 years of production,the Brown shale could yield half again as much,for a tota l produc tion of a bout 23 Tc f to a bout 38Tc f.

A third finding is that because Brown shale

deposits are distributed over extensive areas, itmay take as many as 20 years to drill all of thewells and complete the pipeline system thatwould b e required to p rod uce as muc h as 1.0 Tc fof natural gas per year.

T h e f i n d i n g s a r e b a s e d o n t h eassumptions:

q

q

q

q

q

following

there will be no significant changes in real

The Resource

costs of drilling, stimulating the flow of gasor production;

t he economi c a nd p roduc t ion c ha rac -teristics of three regions analyzed in theassessment represent the more promisin g

sources of natural gas from Devonian shale;

wellhead prices for natural gas will be inthe range of $2.00 to $3.00 per thousandcub ic feet (Mc f);

current tax t reatmentnatural gas production

a nd

o f i ncome f romwill be continued;

approximately 10 percent of the Brownshale resource is of high enough quality topermit commercial development.

The darker layers of shale of Devonian age,which are referred to throughout this report asBrown shale, are found below ground throughout

the Appalachian Basin. The Brown shale can bereached by drill in southwestern Pennsylvania,

qNatural gas is measured in cubic feet: Mcf = thousandcubic feet, MMcf = mil l ion cubic feet, Bcf = bi l l ion cubicfeet , Tc f = trillion c ubic feet ,

southern New York, eastern Ohio, most of WestVirginia, and eastern Kentucky. It also is exposedat the ground surface along the northern and

western sides of the Basin.

The Brown shale is thickest and therefore morelikely to yield commercial quantit ies of naturalgas in the west-central region of the Basin. In thatarea, it comprises between 30 and 40 percent of

3



4 q Ch. I—Executive Summary

the total mass of Devonian shale. To the west,the Brown shale becomes thinner and to the eastit splits into separate beds that eventually disap-pea r in a thick ma ss of c oa rser sed iment s. TheBrown shale originally formed as a black mud,rich in organic matter, on the floor of a Devoniansea. Individual beds of Brown shale are up to1,200 feet thick; maximum depth is about 12,000feet.

The Brown shale consists of alternating paper-thin laminations of inorganic and organic matter.The inorganic layer consists of clay, quartz, andother common sedimentary minerals. The organiclayer consists of extremely fine particles of coal-Iike material and of minute shreds of coalifiedwo od y ma tte r. Thus the Brown shale is not a n

“oi l shale” l ike the shales of Colorado andWyoming but rather, it is coal-like.

Gas production from the shale is greatest fromhighly fractured zones. Evidence suggests that thegas that moves most readily in the Brown shale isin these fractures, and possibly in some of the

coarser-grained laminations. The vast bulk of thegas is held in the shale mass itself, the “matrix,”from which it will move into fractures and wellbores at very slow rates, Initial production fromBrown shale wells is relatively high, as free gas infractures moves to the well bore, but the flowdecreases steadily to that determined by the rateat which the gas in the shale matrix is released.Estimates of the total amount of gas in the Brownshale of the Appalachian Basin range up to manyhundreds of Tcf.

Gas Potential

I t appears that under p lausib le economic,geolog ic , and tec hno log ica l assumpt ions theBrown shale of the Appalachian Basin contains atleast 15 to 25 Tc f of read ily rec ove rab le ga s.1 Thisis gas that would be producible in the first 15 to20 years of life of typical Brown shale wells. Shalegas production has a slow flow rate over a longperiod of time, so ultimate recoverable reservesover the 30- to 50-year expected life of produc-tion could be 40 to 50 percent greater than the

15 to 25 Tc f estimat e. The rec ove rable g as pote n-t ia l o f the Brown shale depends on the (1)wellhead price and production costs, (2) extentof the Brown shale resource, and (3) the relativeamounts of high-, medium-, and low-grade gas-producing brown shales.

The $1.42 to $3.00 per Mcf price assumptions(equivalent to oil at $6.90 to $14.50 per barrel)used in this study are consistent with generalmarket conditions for both interstate and intra-state gas sales. The dri l l ing, well completion,

1Read i ly recoverab le reserves” is no t a ca tegory ineither the American Gas Association or U.S. GeologicalSu rve y n o me nc la ture . In th e p re se n t co n te x t , “ re a d i lyrecoverable reserves” are resources which can be converted

to proved reserves and actually produced in a 15- to 20-yeartime frame.

stimulation, and production cost estimates arebased on actual operating experience in 1976. Allcost and price calculations are in constant 1976dollars.

There is a g ood de al of evidence tha t in a largeoil and gas area the discovery wells tend to bedrilled into the better structures and subsequentdrilling defines the geologic and economic limitsof the resource base. In a marginal resource base

such as the Brown shale (where the extensivegeologic existence of gas-bearing reservoirs is notin doubt), the definit ion of “the better struc-tures” includes the location relative to existingproduction and pipelines. Except in southeasternKentucky, the Brown shale has only recent lybecome a primary target of drilling operations.Even if the current areas of Brown shale develop-ment activity were init ial ly byproducts of otheractivity, the “better” Brown shale prospects areprobably already developed. But “better” as usedhere includes the factor of location relative to ex-isting gathering lines.

There may be a dd itiona l area s which a re asgeologically promising as the localities examinedin this stud y. These ot her a reas, althoug h m oreremote relative to existing pipelines, probably



become economically feasible at the $2.00 to$3.00 per Mcf price levels.

if higher-quality, gas-productive Brown shaleaccounts for as much as 10 percent of the totalestimated extent of the shale (the currently pro-ducing area is less than 5 percent of the 163,000-

square-mile extent of the Appalachian Basin),then a conservat ive est imate of the readi lyrecoverab le ga s is approxima te ly 15 to 25 Tc f. Ifthere are 15 to 25 Tcf of readily recoverable gas,then it is possible that shale gas production inOhio, West Virginia, New York, Kentucky, Ten-nessee, and Pennsylvania could account for asmuch as 1.0 Tcf per year in the future.

The estimates presented in this report arebased on the analysis of 490 producing wells inthree localities. These 490 wells were drilled by alarge number of operators with different financialsituations and technical capabilities. Data from asmaller number of wells drilled by a single opera-tor exhibit higher production than the 490 wells.If the production from these single-operator wellsis representative of a significant portion of theBrown shale of the Appalachian Basin, the Brownsha le might c onta in more than 15 to 25 Tc f ofr ead i I y r ec ov e r ab le gas and a p r oduc t i oncapability of greater than 1.0 Tcf per year. Thisgreater potential could result from either or both(1) greater average productivity per well, or (2) alarger resource ba se which wo uld p erm i t agreater number of wells of average productivity.However, even under an optimal combination ofcircumstances (1 5-percent higher average pro-duction per well and a 50-percent increase in theareal extent of the quality shale resource), onlyabout 30 to 35 Tcf of readily recoverable reserveswould be producible over 15 to 20 years. Underthese optimal conditions, annual shale gas pro-duction from the Appalachian Basin might ap-proach 1.5 to 2.0 Tcf.

production of gas from the Brown shale islikely to be scattered over extensive areas, thus

resulting in a relatively slow pace of develop-ment because of the need to build a pipelinegather ing sys tem. Th is sugges ts that theeconomical ly feas ible expansion of the gaspipeline network required to collect new gas pro-duc tion will be on a n incremen ta l basis. The loc a-t ion of indiv idual wel ls re lat ive to potent ia l

pipeline connections ( in addit ion to geologicpromise) will continue to be an important deter-minant of the economic quality of Brown shaledrilling prospects. Since Brown shale gas produc-tion is relatively well intensive and is likely to bescattered over an extensive area, it is prudent topresume that Brown shale gas development willproceed at a gradual pace, probably requiring atleast 20 years to reach a 1.0 Tcf annual produc-tion level (about 69,000 wells in the Brown shalewill be nee de d to prod uc e 1.0 Tc f pe r yea r). If im-provements in drilling or stimulation technologyare achieved and economic incentives provided,the time necessary for the development of thegas potent ia l of the Brown shale might beredu c ed . The refore, the C ong ress ma y wish toconsider the desirability of some publicly sup-p o r t e d r e s e a r c h a n d d e v e l o p m e n t a c t i v i t ydirected toward improvements in Brown shaledrilling and stimulation technology.

The p otential impa ct of e ither (1) drama ticallybe t te r t ec hno logy , o r ( 2 ) im pr ov em en ts i neconomic incentives beyond those examinedher e m us t be c ons ide r ed w i th c au t i on . I f

economic incentives were twice as good as thoseconsidered in this study, or if drilling and stimula-tion technology were to improve so that theseoperations would cost only half as much as theynow do, it is unlikely that twice as great a quan-t i ty of reserves would become economical lyfeasible. This is because additional developmentefforts, which such economic or technologicalimprovements would induce, would be pressingfurther and further into the poorer sites andgeologic prospects.



6 q C h . I — E x e c u t i v e S u m m a r y

Policy Options To Encourage Shale Gas Production

Policy options available to encourage produc-tion of gas from the Brown shale fall into fourgeneric categories. These categories are:

. price incentives,q tax policies,q research a nd d evelopme nt funding, and. information collection and dissemination.

Price Policies

Brown shale natural gas resource developmentis sensitive to price. The price of Brown shale gassold in interstate commerce is currently restrictedby Federal Power Commission (FPC) ceiling priceregulations. There are three basic price strategies

with respect to shale gas which could be pur-sued. These are:

q

q

q

A

exempt shale gas from FPC price control orestablish higher prices for gas from theBrown shale;

deregulate the wel lhead price of al l newnatural gas supplies; or

take no ac tion.

policy which permits higher prices or ex-empts Brown shale ‘gas from FPC control wouldbe analogous to a proposed policy that would

permit the free market price for oil produced byenha nc ed rec overy techniques. The qua lific ationfor gas from the Brown shale might be based on(1) geologic identification of the Brown shale asthe source of gas, (2) regional specification, (3)production rate limitations, or (4) some combina-tion of these factors.

Brown shale gas product ion is of ten com-mingled with production from other geologiczones. Therefore, a prec ise identific at ion of ga sproduction from the Brown shale could be ex-tremely difficult.

Similar-appearing, gas-productive brown andblack shales of differing geologic ages extendthroughout many portions of the United States inaddit ion to the Appalachian Plateaus, and areg iona l spec if ica t ion rest ric t ed t o t he Ap -palachian Plateaus might therefore omit substan-

tial shale gas resource potential. Production ratelimitations for eligibility for exemption from priceregulation might be more manageable, and alsowould apply to gas production from tight forma-

tions in other parts of the country. Definition andadministration of a multitiered pricing system forgas from the Brown shale could become arbitrary,complex, and cumbersome.

Deregulation of the wellhead price of all newgas supplies would include prospective additionsto the U.S. natural gas supply from the Brownshale of the Appalachian Basin. Such a strategywould create price incentives in the range of$2.00 to $3.00 per Mcf, on which conclusionspresented in this report are based. Such price in-centives might provide the stimulus necessary for

an extensive testing of the economic feasibilityof Brown shale gas production. If 10 percent ofthe 163,000-square-mile extent of the Brownshale is medium- to high-quality gas-productiveshale, an expansion in drilling efforts could resultin prod uc tion of app roxima tely 1.0 Tc f pe r yea rof gas from the Brown shale of the AppalachianBasin within the next 20 years.

If Congress takes no action on prices, existingprices would be the only incentive to encouragegas production from the Brown shale. Currentmaximum interstate gas prices encourage gas

production with existing technology from onlythe high-quality Brown shale areas. Therefore,continuation of present gas pricing policy couldresult in foregoing substantial additions to theU.S. natural gas supply which may be availablefrom the Brown shale of the Appalachian Basin.

Tax Policies

The ta x policies ava ilab le to Co ngress to en-courage Brown shale gas production include:

q restoration of the general 22-percent deple-tion allowance;

q definition of Brown shale gas production asenhanced recovery so as to maintain thedepletion allowance for small producers;

q retention of expensing of intangible drillingcosts as a tax option; and



q creation of a 1 O-percent investment taxcredit for gas production from the Brownshale.

The analysis reported here indicates that a 10-percent investment tax credit has little effect onshale gas production. Areas of low er resource

quality did not become economically feasible forshale gas production when a 10-percent invest-men t t ax c red i t was i nco rpo ra t ed i n t o t heanalysis. However, the addition of a 22-percentdepletion allowance increased the after-tax, net-present value of shale wells and made certainproduction methods economical ly feasib le inshales of lower quality. Basically, a 22-percentdepletion allowance has about the same positiveeffect on the economics of shale gas productionas a $.50 per Mcf increase in the wellhead priceof shale gas.

Research and Development

There are several areas in which research anddevelopment with special relevance to the Brownshale of the Appalachian Basin might be fruitfullypursued. These include:

q defining resource characteristics,q development of dr i l l ing techniques and

equipment, andq improvement of logging and st imulat ion

techniques.

Even though about 10,000 wells already pro-duce gas f rom the Brown shale of the Ap-palachian Basin, few quantitative data are availa-ble to adequately characterize the resource po-tent ial of the ent ire 163,000-square-mile Ap-palachian Plateaus. Until the Brown shale resourceis adequately characterized, specific targets fortechnology development are not possib le. Asystematic coordinated inventory of Brown shaleshould be one of the first steps in developing thegas potential of the Brown shale sequence.

The mo st c omm on tec hniques used to c harac -

terize the Brown shale are those developed foruse in traditional oil and gas reservoirs, Develop-ment of special dri l l ing techniques and equip-ment specifically for use in the Brown shale couldexpedite the development of its gas potential.Because of the importance of well stimulation inthe production of gas from the Brown shale, im-provement in the effectiveness and reductions in

costs of stimulation techniques could make gasproduction from Brown shale more economicallyattractive. Price incentives can be expected to in-duce some private activity in these research anddevelopment areas. However, bec ause muchdrilling, well stimulation, and production will be

done by operators who do not control largeshares of Brown shale resources, it is unlikely thatthose operators will invest large amounts in ag-gressive research and development programs.Therefore, it ma y be p rude nt to c om mit pub licfunds for research and development activitydirected specif ically toward improvements inshale drilling and stimulation technology.

Information Collection and Dissemination

Although the Devonian shale sequence is dis-

tr ibuted over a wide geographic area, only asmall portion of it has potential as a commercialsource of gas. If the gas potential of the Brownshale is exploited, a large number of independentoperators are likely to be drilling a large numberof wells in many different locations on the Ap-palachian Plateaus. Under these conditions, par-ticularly in the early years of the developmenteffort, it might be desirable to fund publicly thecollection, coordination, and dissemination of in-formation and analyses detailing the results of ac-tual operating experiences. This activity shouldbe undertaken by a creditable public group so

that the results are available to the public and pri-vate sectors alike. The information collection anddissemination efforts might initially include thepublic funding of conferences where researchand development results and improved dri l l ingand stimulation technologies are reported. If theBrown shale has a potential to produce 1.0 Tcf ofgas per year, and economic incentives are pro-vided, it is l ikely that private enterprise wil lassume necessary research and developmentefforts within a comparatively short period oftime.

Conclusions

There are a numb er of policy op tions ava ilab lewhich could encourage production of gas fromthe Brown shale of the Appalachian Basin. A sig-nificant and substantial policy option is to permitfree-market prices for gas from Brown shale for-mations. Restoration of the 22-percent depletion



8 q Ch. I—Executive Summary

allowance would have about the same effect as wells, and increase the gas production from wells,increasing the well head price of shale gas by $.50 could increase the - economic attractiveness ofper Mcf . Research and development ef for ts producing gas from the Brown shale of the Ap-which characterize the Brown shale resource, pa lachian Basin.decrease the cost of drilling and stimulation of



Il. Introduction



Il. Introduction

The Natural Gas Situation

Sinc e 1970, the United States has consumednatural gas faster than it has discovered newreserves (table 1 and figure 1). Annual productionhas declined steadily from a peak of 22.6 trillioncubic feet (Tcf) in 1973 to a 1976 level of 19.5Tc f; the dec line is projec ted to c ontinue in thefuture unless new gas is discovered and added tothe Nation’s reserves (figure 2). Producers are cur-rently delivering 20 percent less natural gas to

Table 1Proved Reserves of Natural Gas in

the United States, 1959-76

(Trillions of cub ic fee t; 14.73 PSIA at 60ºF)

Year

1959 . . . . . .1960. , ...

1961. , ...196 2 . . . . . .

1 9 6 3 . . ,1964 . . . . . .

1965 . . . . . .

1966 . . . . . .

1967 . . . . . .

1968, . . . . .

1969 ..., . .

1970 .....,

1971. . . . . .

1972 . . . . . .

1973 . . . . . .

1974 . . . . . .

1975 . . . . . .

1976 . . . . . .

Proved

Reserves atBeginning

of Year

252,8

261.2

262.3

266.3

272.3276.2

281.3

286.5

289.3

292.9

287.4

275.1

290.8

278.8

266.1

250.0

237.1

228.2

Proved

Reserves

at Endof Year

261.2

262.3

266.3

272.3

276.2281.3

286.5

289.3

292.9

287.4

275.1

290.8

278.8

266.1

250.0

237.1

228.2

216.0

Net Change

FromPrevious Year

+ 8 . 4+ 1.1+4.0

+ 6.0

+ 3.9+ 5.1

+ 5.2

+ 2.8

+ 3.6

-5.5

-12.3

+15.7

-12.0

-12.7

-16.1

-12,9

-8.9

-12.2

interstate pipelines than is called for in firm con-tracts (table 2). The shortages of gas for industrialuse are the most serious, but supplies for resi-dences and small businesses have also been cur-tailed in some areas.

Three ge neral cha nge s in po lic y have be enproposed by industry, Government, and inde-pendent analysts as ways to stem the decline in

Figure 1. Proved Reserves of Natural Gasin the United States, 1959-76

Reflects addition of PrudhoeBay natural gas resews

I I I I 1 1I I I I I I I I I I

Note: 1970 flgure~ reflect the addition of Prudhoe Bay, A l a s k a

1960 ’62 ’64 ’66 ’68 1970 ’72 ’74 ’76S o u r c e . Reserv(’s of c rude oil, natura l gas Iiqulds, a n d n a t u r a l

g as In the United State\ and Canada as o f December 31, 1976 jointSource” Reserves of crude 011 natural gas Ilqulds, and natural gas in the

publlc at!on by the American Gas Assrx Iatlon, Amerlc an PetroleumUnited States and Canada as of December 31, 1976 Joint publication of theAmerican Gas Assoclatlon, American Petroleum Institute, and Canadian

In$tltute, and Canadian Pet ro leum ASS(X Iatlon Vol. 31, May 1977 Petroleum Assoclatlon Vol 31, May 1977

11



12 Ž Ch.11—lntroduction

Figure 2. Projected U. S. Natural GasProduction, 1975-2000

(assuming 8.0 Tcf reserve additions per year)

1975 1980 1985 1990 1995 2000

Year

Source Federal Power Commission.

production and narrow the gap between supplyand de ma nd fo r nat ural ga s. They a re:

1.

2.

3.

Decontrol natural gas prices so that in-creased costs would encourage consumersto use less fuel and increased wellheadprices would encourage producers to inten-sify their efforts to locate new reserves.

Permit price increases under regulation toachieve some, but not all, of the stimulus ofproduction that is anticipated as a result ofderegulation.

Accelerate efforts to produce natural gasfrom unconventional geologic formations,such as the t ight sands of the WesternBasins, coal seams in the Eastern UnitedStates, geopressurized zones off the gulf

Table 2U.S. Production of Natural Gas and

Curtailments of Firm Customers, 1959-76

Year

1959 . . . . . .1960 .., . . .1961 . . . . . .

1962 .., . . .1963 . . . . . .1964, . . . . .1965 . . . . . .1966 . . . . . .

1967 . . . . . .1968 . . . . . .1969 . . . . . .1970 . . . . . .1971 . . . . . .1972 . . . . . .1973 . . . . . .1974 . . . . . .

1975 . . . . . .1976 . . . . . .

Production(Trillions ofcubic feet)

12.413.0

13.413.614.615.4

16.317.5

18.419.4

20.722.022.122.522.621.3

19.719,5

Interstate Pipellne

Curtai lments(Trillions of c ub ic fe et )

-o--o-

-o-

-o-

-o-

-o-

-o-

-o-

-o-

-o-

-o-

0.0

0.3

0. 7

1 .1

1. 7

2. 6

4. 0

Source: Federal Power Commission and American Gas Associa-

tion.

coast , and Devonian shales of the Ap-palachian region of the Eastern UnitedStates.

This repo rt examines the ga s-prod uc tive p o-t en t i a l o f t he l as t o f t hese unconven t i ona lsources, the Devonian shales, which containma ny hundreds of Tc f of nat ural ga s, loc at ed inan area of the Nation where natural gas is in shortsupply. The report assesses the potential for pro-ducing natural gas from the Devonian shales ofthe Appalachian region and the impact on thisproduction potential of various policy optionsavailable to Congress, Among all unconventionalsources, the Devonian shales have the advantageof being productive, at least locally, in the Ap-palachian Basin wi thout the development ofcompletely new and novel techniques for gasrecovery.



Ill. Regional Effects ofProducing Gas From Devonian Shale



Ill. Regional Effects ofProducing Gas From Devonian Shale

The regional effects of the p rod uction of ga sfrom Devonian shale will depend largely on whathappens to the price of natural gas. If the regu-lated price were allowed to move closer to thelevel that would be determined by prevail ingmarket forces, there undoubtedly would be an in-crease in investment in new wells in the Devo-nian shale area. The same result would likely oc-cur if controls on gas prices were eliminated.1

A significant addition to the available supplyof natural gas might reduce upward pressure onga s prices. The reg ions tha t w ould p roba bly

benefit most from reduced pressure on gas pricesare the New England, Middle Atlantic, East NorthCentral, and South Atlantic States.2 These areregions in which the price of natural gas has con-sistently been above the national average, andthey include the major industrial States east ofthe Mississ ippi . On ly four Sta tes in theseregions—West Virginia, Virginia, Pennsylvania,and I l l inois—are among the Nat ion’s 20 topenergy-producing States. The other 18, andWashington, D. C., import most or all of the coal,oil, or natural gas they consume.

States which have been hardest hit by the dra-

matic rise in energy prices since 1973 are thosewhich are both heavily industrialized and largelyor entirely dependent on outside sources for theirenergy supplies. These States were industrializedat a time when energy prices were low, relativeto other prices, and when the costs of transport-ing or transmitting energy were also relatively

1 See A V. K n e e Sc >, ‘ ‘ N a t u r a l R e s o u r c e s Po l i c y ,

1976-1 9 8 6 , ” In U. S E( ononIIc GroI$th Irorn 7976 [ o 1986:F ’MMp ( ’ ( (5 , Prob)emj, a nd Patt( ’ rn~, Vol 4, R e s o u r c e s a n dEnergy, Congress of the United States., Joint Economic Com-

mi t te e p , 139, Nov. 16, 1976.

‘ The States Included In these regions are: Ne w England:M a Irre, Massac huset[s, C o n n e c t i c u t , V e r m o n t , N e wHampshire, and Rhode Island; MId d / e A( l an? /c : New York,New Jersey, and Pennsylvania; East Norfh Central: Ohio, ln -d iana , Illlno is, M i c h ig a n , a n d Wlsc on sln; south A ( / a n ( / c ;D e l a w a r e , M a r y l a n d (inc Iudlng D.C, ), Vlrglnla, WestVirglnla, the Carolinas, Georgia, and Florida.

low. Of even greater importance is the growingnumber of people who are unable to buy naturalgas at any price. Some consumers would benefitgreatly from an increase in the Nation’s supply ofnatural gas, even if this gas were available in thefuture only at substantially higher prices thanthose that have prevailed up to now.

In an economy in which prices are determinedby market forces —whether the markets are con-sidered to be “perfect ly” compet i t ive or not—there will always be some shifting about of in-dustry. There ha ve b een ma jor industrial mig ra-tions in the past, notably a shift of much of thetext i le and garment industr ies from north tosouth. These and other industrial migrations ofthe past have been the result of interregionallabor cost differentials. Wage differentials havebeen reduced in recent years, and as the impor-tance of labor costs as locational determinantshave diminished, other costs which vary overspace have become more important.

The cost of energy is likely to become an in-creasingly important locational determinant for afair ly wide range of industr ial act ivi t ies, butequally important—and in some cases more im-

portant—will be energy availability. Industrialistsin relatively energy-intensive activities—such asthose producing various chemical, plastic, rub-ber, and glass products—might be willing to relo-cate, or at least to expand, in areas with knownreserves of natural gas. Indeed, one characteristicof Devonian shale gas wel ls—their long pro-ductive Iives—could be considered a major ad-vantage by manufacturers anxious to avoid sup-ply interruptions over a long period of time. Mostconsumers of natural gas, including industrialconsumers, buy their gas from a utility. But in anera of supply uncertainty, however, with strong

inflationary pressures which will guarantee risingga s prices, there may be a g rowing incentive forindustrial establishments to own their own gaswells and reserves. The availability of natural gascould make the Devonian shale areas highly at-tractive locations for energy-intensive activities.

15



IV. The Resource



IV. The Resource

Geographic Extent

Sedimentary rocks of the geological ageknown as Devonian are present in the Ap-palachian region from New York to Alabama, inan area of some 209,000 square miles. The regionincludes two geological provinces of unequalsize. in the smaller of these, an eastern beltknown as the Valley and Ridge province, all rockshave been so intensely folded and faulted thatfew geologists consider them important sourcesof oil or gas, although recent studies indicate thatthe southern part of the Valley and Ridge hasconsiderable potential for gas production. In the

larger area, t he Appa l ach i an P l a t eaus i m-mediately to the west, the rocks are flat-lying oronly gently folded. Furthermore, the upper partof the Devonian system of rocks in this province

contains dark brown or black shale, r ich inorganic matter, that yields some natural gas atpresent and reportedly has the potential of yield-ing a great d eal more. The a rea of the Ap -palachian plateaus is 163,000 sq ua re miles.1

These shales are covered by younger rocks butcan be readily reached by the drill, and are lo-cated in southwestern New York, western Penn-sylvania, eastern Ohio, most of West Virginia,and eastern Kentucky (f igure 3). In addit ion,Devonian dark brown or black shales outcrop atthe surface or beneath a few feet of glacially

deposited debris in western New York, in a beltextending from Cleveland southward throughcentral Ohio, and in a series of disconnected out-crops in north-central Kentucky.

Terminology

The term Devonian shales refers to all the shalestrata that lie beneath a widespread younger for-mation known as Berea sandstone and above ano l de r l i mes t one t e rmed O nondaga o r Co r -

niferous. The shales are found in one-half dozenAppalachian States; similar strata are known inIndiana, Illinois, and Michigan. They occur in thesubsurface, where they are encountered in wells,and a t the sur face , where they have beenmapped and studied. Over time, they have ac-quired a variety of geographically based names:Chattanooga shale in the Appalachian States;Marcellus shale in New York; Ohio shale in Ohio;and New Albany shale in Kentucky and Indiana.

In this report, these terms are considered to besynonymous.

The De von ian sha les include strata tha t a re

gray, greenish gray, grayish brown, and deepbrown to blac k. The d eep brown to blac k shalescontain much organic matter, and are local lyproductive of gas. In most reports, including thisone, they are called Brown shale. It is importantto keep in mind the dist inct ion between thewhole thickness of Devonian shales and thoseparts—the Brown shale—that are r icher inorganic matter and of greater interest as a sourceof gas.

Origin

The po sition of the Devonian shales in the Ap - ca n best be understood b y looking briefly at theirpalachian Basin, and their relation to other rocks, origin. To do this, it is necessary to erase one’s

men t a l i mage o f p resen t -day Appa l ach i an

NOTE: All references to footnotes in this chapter appear g e o g r a p h y f o r a m o m e n t a n d su b s t i t u t e L a t eon page 27. Devonian geography of some 350 million years

19



20 q Ch. IV—The Resource

Figure 3. The Appalachian Basin

In gray areas Devonian rock outcrop at the surface. Numberedlines give to ta l thickne ss of a ll be d s of Brow n sha le in the

Devonian shale sequence. In cross-ruled areas gas has beenor is being produced from Brown shales. (From deWitt et al.,1976, U.S. Geol. Survey Map I-917 B)

-+

Index map.

0 4 ”

4 2“ I

I

I



ago. To the east of the region shown in figure 3,in a position roughly parallel to that of the pres-ent-day coastl ine, was a lofty range of moun-tains. Erosion of these mountains produced im-mense volumes of mud, silt, and sand, whichwere carried westward by streams and deposited

in a grea t c om po und d elta, the C at skill Delta. TheDelta was built out into a seaway that coveredparts of what is now the Appalachian Basin. Inthis sea, black organic-rich muds accumulated.The Devonian shoreline was not fixed: at timesthe sea level rose and marine muds were spreadacross the seaward parts of the Delta; at othertimes deltaic sands and silts flooded westwardinto the seaway, displacing the shoreline far tothe west. As a result of these fluctuating condi-tions, the Brown shale interfinger to the east with

much thicker and coarser deltaic rocks (figure 4).To the west, the blac k-mud bo ttome d sea wa s attimes restricted by a lowland area termed theCincinnati arch, and at other t imes it f loodedacross this feature to merge with seas in theMichigan basin and the Illinois basin. Although

Brown shale deposition of Late Devonian timewas not restricted to the Appalachian Basin, thisregion appears to be most important from theviewpoint of potential gas supply. In the longst retch of geologic t ime s ince the Devonianperiod, both the deltaic rocks and the shales havebeen buried by younger sediments. Around theiredges they have been part ial ly uncovered byuplift and erosion, but they remain under coverof younger rocks in much of the AppalachianBasin.

Thickness

As indicated on f igure 4, Upp er De v o n ia nroc ks are a great w edg e-shap ed dep osit, thin a ndshaly on the west and becoming thicker andmore sandy toward the east. In south-centralKentucky, the section consists of about 20 feet ofblack shale.2 This sec tion t hickens to abo ut 400feet at about the Kentucky-West Virginia l ine,and merges into a mass of siltstone, black silt,and sandstone some 7,OOO feet thick still farthereast near the West Virginia-Virginia I ine. Theshale section increases in thickness from less than500 feet at the outcrop in southern Ohio toabout 4,200 feet at the eastern edge of the State.3

Only a fraction of these thicknesses, however,represents Brown shale of potential interest as acommercial source of gas. A generalized log ofthe shale section penetrated by wells in eastern

Kentucky, for example, shows an overall shalethickness of 677 feet, of which only an averagethickness of 228 feet was Brown shaled4 —One-third of the section. Of the eastern shales ingeneral, “a 1 ,000-foot interval generally containsapproximately 600 feet of l ight-colored shalesand 400 feet of dark shales.” 5 A general idea ofBrown shale thicknesses in the Appalachian Basinis given by the contours on the map, figure 3. Thethickness values on this map are stated to repre-

sent net thickness of Brown shale beds only;6 t hevalues are higher in the eastern part of the Basinthan is suggested on the cross section, figure 4,because the geologists who compiled the mapincluded more shale as Brown shale than thosewho made the cross section. Gas has been foundthrough the entire Devonian shale, although theBrown shale has the highest concentration.

Attitude and Depth

In common with the other rocks in the Ap-palachian Basin, the Devonian shales have a gen-tle inclination, or dip, to the southeast. In easternKentucky, for example, they dip southeast at 30

to 50 feet per mi le.7 At the surface in centralOhio, the top of the shale section has an eleva-tion of about 800 feet, but in southeastern Ohiothis surface is some 1,400 feet below sea Ievel. aThis is a decline of 2,200 feet in 85 miles, or a dip

of 26 feet per mile. It places the top of the shalesection at a depth of about 2,000 feet in theOhio R iver Va l ley be tween Oh io and WestVirginia. A well in Carter County, northeasternKentucky, near the common corner of Kentucky,West Virginia, and Ohio, reached the top of theshale sect ion at 1,173 feet; in Pike County,easternmost Kentucky, the top of the shale lies atabout 5,000 feet; the top of the shale is 12,000



Figure 4. West-East Cross Section Across Central West Virginia

Land Surface-Central West Virginia-

Approximately2,400 feat to the sutface

o 5 10

A’

i

q

n

Thickness of the total Devonian shales is about 2,000 feet at the west end of the section and6,600 feet at the east end. Brown shales disappear into thicker strata toward the east. (Modifiedfrom Martin and Nuckols, 1976, ERDA Pub. MERC/SP-76/2. Fig. 4.)



Ch. IV—The Resource . 2.3

feet below the surface of northeastern Penn- bearing strata. There are minor variations in thesylvania. At no place in the Appalachian Basin is southeastward dip, b ut these do not seem todepth to the shale too great to be reached by the have had a signif icant ef fect on ac cumulat ion ofdrill; indeed, many wells in parts of the Basin are gas.

drilled through the shale to deeper oil- or gas-

Composition

The basic unit of the Brown shale is a pair, orcouplet, of microscopically thin layers: one richin mineral matter and the other made up chieflyof organic matter. The fineness of the resultinglamination is hard to appreciate. Samples of Ohioshale taken from the outcrop in central Ohiowere found to have as many as 230 Iaminae(couplets) in a 5-inch thickness.9 References to“ha i r l i ne bedd i ng p l anes ” and “pape r - t h i nlaminat ions” in pub lished d esc ript ions of theBrown shale from cores makes it clear that thischaracteristic persists in the subsurface as well.

Core samples of dark brown organic-rich shalefrom a producing gas well in the Cottagevil leField, Jackson County, W.Va., were analyzed.10

The inorga nic pa rt of the rock wa s found to c on-sist chiefly of clay minerals, mainly illite, with theextremely fine grain size that is typical of clay(less than 0.004 mm). Silt-size grains of quartzand feldspar were present in amounts of 5 per-cent or more, and there were small amounts ofcalcite, dolomite, and pyrite. Another core from

the same f ie ld analyzed at 60 percent c layminerals, 35 percent quartz and feldspar, and theremainder most ly pyr i te and dolomi te.11 Th egrains of quartz and feldspar, mostly coarser than0.004 mm, tend to occur in very thin Iaminae orlenses.

The orga nic frac tion, red dish brown to c hoc -olate brown in color, is made up of particles ofcoal-like material in the micron size range (0.001mm ). There a re also m inute shreds of coa lifiedwood y substance, and of spo res and alga e. Theevidence from the organic material shows that it

was mostly derived from pIants, and this conclu-sion is supported by carbon-isotope studies. Inthe jargon of the coal petrologist the material

consists largely of “humic degradat ion prod-uc ts, ” which were washed into the sea fromlands to the east and possibly from lowlands onthe C incinnati arch. There must ha ve b een a“ de nsity stratificat ion “ in the wate rs of the Devo -nian Sea, a stagnant condition that inhibited ver-tical circulation and prevented the organic matterfrom being oxidized and destroyed as it accumu-lated on the bottom. A reasonable assumption isthat each couplet of mineral-rich and organic-rich

sediment may represent an annual accumulation.Organic matter typically makes up 10 to 20 per-cent of the rock by weight, or 40 to 60 percent byvolume. 12

It should be noted that the Brown shale is not“oil shale” like that of Colorado and Wyoming.13

The o rga nic ma tter is not the type of kerogen tha tcharacterizes such oil shales; rather, as notedabove, the Brown shale are coal-like.

At outcrops, shales almost always split intothin f lakes and plates parallel to the bedding.Another interesting aspect of the Brown shale istheir content of uranium. Little is known of thereasons for this, except that the association oforganic matter and uranium is evident ly pri-mary—the uranium was present at the time themuddy sediment was deposited, and was not in-troduced in later time.14 The uranium c onte nt ofthe Brown shale, which ranges from 0.005 per-cent to slightly more than 0.007 percent, has notyet allowed them to be of use as a commercialsource of uranium, although it is conceivable thatthey may be of such use in the future. Theradioactivity of these shales, however, is a highly

useful characteristic in the search for gas, as theradioactivity makes Brown shale readily recog-nizable on gamma-ray logs of drilled wells.

Fractures

A feature of the Devonian shales, which is of shale, is a system of nea r-vertica lspecial significance in the gas-bearing Brown known as joints). Most of these are

fractures (alsoonly a fraction



24 q Ch. IV—The Resource

of a millimeter wide. In well cores, some fractureshave been observed to be f i l led with browncrystalline dolomite, which helps make the frac-ture p orous and pe rmea ble. Spa cing o f the frac -tures is variable, but they may occur closeenough together so that two or more are often in-

tersec ted in a 6-inch w ell bore. The frac tures arenot randomly oriented, but occur in “sets” thatare alined in certain directions.

The relationship be twe en frac tures and ga sproduction is well shown by cores taken fromtwo wells in the Cottagevil le Field, JacksonCounty, W. Va.15 16 The cores intersect numerousfractures and a study of the orientation of thesefractures resulted in two important findings. First,the dominant direction of the fractures is North40° to 50° East. This is the regiona l trend of theAppalachian Mountains (though the significanceof the parallelism is not well understood); more

practically, it is also the direction in which themost productive gas wells in the CottagevilleField are alined. This clearly suggests a relationbetween gas production and this set of fractures.Second, in the well from which the larger flow ofgas comes, there is a wide variation in fracturealinement. Only 21 percent of the fractures area lined North 40° to 50° Ea st; o the r prefe rreddirections are slightly west of north, slightly eastof north, and nearly east-west. parts of the corefrom this well are “completely shattered” by

fractures, and the well had a natural flow of morethan 1 million cubic feet (MMcf) of gas per day.The c ore from the sec ond well show ed few frac -tures, and the well had no op en flow a t all. Theconclusion seems clear that here, as elsewhere inthe Appalachian Basin, gas production from the

Brown shale is controlled largely by fractures,with the production rate dependent on the num-ber, length, openness, and direction of these frac-tures.17

Although mapping of fracture patterns and in-tersections may well be the best guide to gas ac-cumulation, mapping is a very difficult task. Thecause of fracturing is not well understood, and atleast nine theories have been suggested, 18 Thefracture systems may be related, for example, tothe deformation that produced the AppalachianMountains; to settling above deep-lying faults,

thousands of feet below the Devonian shales(figure 5); or to major zones of fracturing (“linea-ments”), scores or even hundreds of miles long,that are known or suspected to ex is t in theregion. Until the origin is known, a rational searchfor fracture-controlled gas accumulations will bedifficult. A few fractures extend upward throughoverlying rocks and reach the surface, and theirpatterns can be detected by remote-sensingtechniques (LANDSAT imagery). This is probablythe best current approach to the problem.

Natural Gas in the Brown Shale

Although it has been known for more than 150years that shallow wells drilled into the Devonianshales along their belt of outcrop would yieldnatural gas, the Brown shale was not generallyconsidered a primary objective in exploration fornatural gas until recently. In most parts of the Ap-palachian Basin, wells were drilled to deeper,more promising formations. If those failed to pro-duce, the wells were “p lugged back ” to theBrown shale and attempts were made to stimu-

late enough gas from the formation to make aproductive well,19

Drilling for gas started in western New York asearly as 1820, and moved westward along thesouth shore of Lake Erie across northwesternPennsylvania and into Ohio as far as Cleveland.20

Shal low wel ls in the Brown shale suppl ied

Louisville, Ky., with gas in the 1880’s.21 Two fa c tsabout this early production stand out. First, therate of gas production was low; only enough tosupply a small local industry, or a small cluster ofhouseholds for heating and cooking could be ex-pe cte d from a given we ll. Sec ond , the we lls werevery long-lived. Two wells at Fredonia, N.Y.—one drilled in 1821 and the other in 1850—had acombined annual production of only 6 MMcf(16,400 cubic feet per day), but when plugged 60

years later they were still producing 6 MMcf peryear.22 It was clear from this early experience thatthere was gas in the shale, but that the shalewould yield it only at a low rate over a long timepe riod. Tod ay w e know that ga s move s rea dilyonly in fractures, and perhaps along some of themore silty bedding surfaces. The vast bulk of thegas is held in the shale mass, or “matrix,” from



Ch. IV—The Resource • 25

which it will move into fractures and well boresat very low rates and over long time periods.

Estimates of the total amount of gas in theDevonian shales of the Appalachian Basin rangef rom a few Tc f to ma ny hundreds of Tc f .2 3

Although the magnitude of the total resource is

not known, there can be no doubt that it is largeenough to be of potent ial importance to theEastern United States.

Present-day wel ls producing gas from theBrown shale recover only 2 to 10 percent of theoriginal gas in place; 90 to 98 percent is left in

the ground. The h istory of produc t ion in 50Brown shale wells is indicated by the “declinecurves” on figure 6. Initial production is relativelyhigh, as free gas in fractures moves to the wellbore, but the flow decreases steadily to somevalue determined by the slow rate at which thegas in the shale matrix is released. Various tech-niques are being applied to the shale in an at-tempt to create artificial fractures extending out-ward from the well bore, thus potentially increas-ing the amount and rate of gas recovery by con-necting more fracture systems to the well and ex-posing more surface area.

Figure 5. Model Showing Fractures Generated by Deep Seated BasementFaulting and Propagated Upwards Into the Devonian Shales

Land Surface Land Surface Land Surface

/

Source Overbey, 1976, Energy Research and Development Admlnlstratlon Pub. MERCLSP-7612, Fig. 9



Figure 6. Averaged Production Decline Curves for 50 Devonian Shale Gas Wells

240

220

200

180

160

1 I 1 I I I I I I I I I I I I I I I I I I I I I I I

0 2 4 6 8 10 12 14 16 18 20 22 24 26

Time in Years

Lincoln, Mingo, and Wayne counties, West Virginia. Wells were metered on open flow aftershooting or fracturing of the shale pay zone. Mcf = thousand cubic feet. (From Bagnall and

Ryan, 1976, ERDA Pub. MERC/SP-76/2, Fig. 11; and W. D. Bagnall, personal communication.)





V. GeneraI Reservoir Characteristics



V. General Reservoir Characteristics

The reservoir characteristics of Brown shale arevastly different from those of typical oil- and gas-producing formations. Porosity indicates how

much space exists in a particular formation whereoil, gas, and/or water may be trapped. A com-mercial ly oi l- or gas-productive sandstone orlimestone reservoir has porosities in the range of8 t o 30 pe r c en t . By contrast, gas-producingBrown shales have porosities of 4 percent or less(tab le 3).

Much of the oil and gas in a formation may beunrecoverable because the pore structure is suchthat reasona ble f low ca nnot take p lac e. Theability of fluids and gases to flow through a par-ticular formation, or permeate it, is called the per-

meab ility. The typ ica l oil- and ga s-produc ing for-mation has a permeability in the range of 5 to2,000 millidarcies (mD). By contrast, most of themeasured permeabilities of the Brown shale inproductive areas are in the range of .001 to 2.0mD (see table 3).

Since the characteristics of Brown shale reser-voirs are so different from those of the usual oiland gas reservoir, evaluations of gas-productionpotential of the shales’ by using conventional oiland gas techniques may result in erroneous con-clusions. In the conventional oil and gas reservoirit is a simple matter to measure the percentage ofthe total reservoir that is occupied by oil, gas,and water. However, in dealing with the Brownshale it is very difficult to accurately determinethese percentage saturations because the poresare so very small.

The manner in which natural gas is held in theBrown shale is a subject of considerable specula-tion. Some scientists believe that it is simplyentrapped in extremely small pores. Others thinkthe gas is adsorbed or molecularly held on thesurface of the shale particles. ’ Some of thenatural gas may be dissolved in solid and liquid

hydrocarbons in the reservoir. There is also somereason to believe that the gas may be in a liquidstate in pores in the Brown shale. Available evi-

NOTE: All references to footnotes in this chapter appearon page 41 .

Table 3Comparison of Core Data for

Brown Shale and Reservoir Roks

From Other Gas Producing Areas

Hugoton -Anadarko Basin . .San Juan Basin’Permian Basin a . . .Brown Shale:

Jackson

County, W. Va. b

(whole-core

analysis). . . .(conventional-

core analysis)

Lincoln County,W. Va, ’

(whole-coreanalysis). . . . . .

Perry County,Ky. d

(whole-coreanalysts). . .

TypicalPermeability( m i I Iidar -

cies)

20 .

1.

15 .

2. 0

0. 1

.004

.3

TypicalPorosity

(percent)

14

10

12

3.2

3. 0

0.6

4.0

TypicalWa te r

Saturation(percent)

40

30

35

65

70

0.0*

35

“Centr i fuge measurement, s e e t e x t ,

‘S Rudisell , N Beck ner, a nd W.B Tay lor I Phillips Petroleum

Company), Personal communicat ion, 197[J

“ W . L . P in n e l l ( Co n s o l i d a t e d G a s Su p p l y Co r p . ) c o r e d a t a o n

WeII #11440 and #12041 Personal communication), 1976

( Phase Report No. 1, Massive Hydraulic Fracturing of the Devo-

nian Shale, Co lum b ia / ERDA Con t rac t E (46 -1 ) - 8014 Research

Department, Columbia Gas System, October 1976,

‘ {Final Report—Well No. 7239, Perry County, Ky, , ERDA-MERC,

July 1975.

d e n c e 2 indicates that virtually all of the Devonian

shale contains gas that is released or flows fromthe shale when the shale is placed in a relativelylow-pressure atmosphere. However, current com-

mercial production appears to enter the wellsmainly from the Brown shale.

All subsurface reservoirs initially exist at ele-vated pressures, regardless of whether they con-tain water, oil, or natural gas, J In conventional oiland gas reservoirs, a normal reservoir pressure (in

31



32 . Ch. V—General Rcservoir Characteristics

pounds per square inch) is generally obtainableby multiplying the depth (in feet) below the sur-face of the ground by a factor of about 0.4. Forexample, an oil and gas reservoir at a depth of3,300 feet in the Clinton sand in Ohio would beexpected to have an init ial pressure of about1,300 pounds per square inch (psi), Since Brownshale formations produce gas at very low rates, itis difficult to determine an accurate initial reser-voir pressure. However, shale wells that are shutin for long periods often exhibit pressures in therange of 0.125 times the depth, which is much

less than would be expected in a normal oil orgas reservoir. The initial reservoir pressure is veryimportant if the gas in the shale exists in agaseous state, because the amount of gas in thereservoir measured at atmospheric conditions isproportional to the reservoir pressure. For exam-ple, all other things being equal, a reservoir witha pressure of 2,000 pounds per square inch ab-solute (psia) will contain twice as much gas in agiven volume of reservoir rock when measured atatmospheric conditions as a similar reservoir atthe same depth whose pressure is 1,000 psia.

Reservoir Evaluation Tools

Core Analysis

In drilling an oil or gas well with rotary tools

(the drill bit rotates at the bottom of the hole asopposed to moving up and down as in cable-tooldrilling), it is possible to use a special type of drillbit that works much like a doughnut cutter andpermits the operator to cut plugs or cores fromthe formation and bring them to the surface assamples of the rock being drilled. This operationis referred to as “coring. ” The samples so ob-tained can then be subjected to various types ofanalyses.

Geologists and engineers examine cores ofBrown shale to detect fractures or joints, The

visual appearance, odor, or taste of a core sampleprovides an indication of the presence of gas, oil,or water in the pores of the core.

After a quick gross examination, 6-inch longpieces of the core may be sealed in cans or othercontainers to maintain the fluid content insofar aspossible. These samples are used to determinethe porosity, permeability, and fluid saturation ofthe sha le . I t i s impor tan t to no te tha t thelaboratory procedures used to analyze the Brownshale were designed for normal sandstone andlimestone reservoirs which have much greater

porosities and permeabilities.4Basic to an understanding of the gas produc-

tion potential of the Brown shale is the need forana ly t i ca l t echn iques capab le o f accura te lydetermining critical reservoir characteristics fromcore samples. If it is not possible to determine ac-curately from the core samples (1) the physicalnature of the pore structure that constitutes the

reservoir (subsurface gas container); (2) the per-centage of the total bulk volume of the reservoirthat is made up of pore space; (3) the ability of

fluids to flow through these pores; and (4) thepercent of pores occupied by gas, l iquid hy-drocarbons, solid hydrocarbons, and water, thenthere is much smaller chance of determiningthese same parameters from less direct methodssuch as electrical logs. A log is a record of somephysical property (e.g., electrical resistivity orradioactivity) of the rocks penetrated in a well,

The “ c onvent ional” t ype of c ore a nalysis in-volves cutting a 3/4-inch-diameter, 1 -inch-longplug from the core, whereas the “whole core”type of analysis uses the entire sample which is

3-1 /2 to 4 inches in diameter and 6 inches long.“Whole-core” analysis is generally thought to bemore applicable than the “conventional” type.

Permeability, Porosity, and Saturation

The p erme ab ility, porosity, a nd sat uration o fthe Brown shale are vastly different from thesame parameters of most gas-producing reser-voirs. A general comparison of these charac-t e r ist ics is g i ven in t a b l e 3 . The Hugo t on -Anadarko, San Juan, and Permian Basins represent

some of the better known gas-producing areas.They tend to contain reservoirs that are on the“t ight ” ( low permeabi l i ty) s ide, as comparedwith offshore production, where the reservoirsmay have a permeabil ity of 1,000 mD and aporosity of 35 percent. Nevertheless, the typicalsandstone reservoi r has permeabi l i t ies andporosities that are much greater than those of



Brown shales. This is a strong indication thatmethods different from those used in conven-tional gas-producing reservoirs must be used toobtain commercial rates of production from theBrown shale. Development and evaluation ofsuch methods can only come from basic researchand field testing.

The characteristics of Brown shale listed in ta-ble 3 vary widely, even though the data pre-sented are all from the same geographical regionin southwestern West Virginia and eastern Ken-tucky. This variation is probably due principallyto the heterogeneity of the shale itself.

it appears that whole-core analysis gives moremeaningful informat ion for the Brown shalebecause it includes the effects of joints and frac-tures. Conventional-core analysis, run on a smallplug, will be affected by a fracture if one exists insuch a sample, but the plug may not contain oneeven though fractures appear to be present everyfew inches in the Brown shale. Fractures causedby drilling and coring operations may producespurious data from both coring analyses.

Tab le 3 do es not indica te the very high p er-me ab ilities of som e o f the samples. The w hole-core analysis of the Lincoln County well repre-sents 19 samples distributed through 1,300 feet ofshale. Three of these samples had permeabilitiesof 906 mD, 502 mD, and 93 mD, whereas theother 16 samples ranged from .0002 mD to .023mD. Similarly, the whole-core analysis of the

Perry County well represented 12 samples cover-ing 64 feet, with two permeabilities of 9 mD and23 mD and the others between 0.1 mD and 0.9mD.

T he L i nco l n Coun t y , W . Va . , who l e -co reanalysis shown in table 3 is markedly differentfrom the other Brown shale analyses. This is prob-ably due to the manner in which the analysiswas made. The cores from the Jackson and PerryCounty wel ls were analyzed using horizontalflow, while the analysis of the Lincoln Countywell was based on vertical flow. Since vertical

flow is likely to encounter impermeable barriersof paper-thin Iaminae that would not af fecthor i zon ta l f l ow, much lower permeab i l i t i eswould be ca lc ulated . The lack of vertic al co m-m u n i c a t i o n w o u l d a l s o r e s u l t i n r e d u c e dmeasured porosities. This Lincoln County coreanalysis also indicated a water saturation of 0.0percent, 5 6 w h e r e a s t h e o t h e r sh a l e a n a l y se s

showed substantial water content, The LincolnC o u n t y a n a ly sis w a s b a se d o n c e n t r if u g emeasurements, The centrifuga l force c rea ted ap -parently did not exceed the capillary or otherforces holding the water in the very small pores;hence, it appeared that the water saturation ofthe shale was 0,0 percent. These examples clearly

emphasize the need for research in the area ofcore analysis of the Brown shale.

The Brow n sha le is cha rac terized by a porosityo f abou t 3 pe rcen t . Howeve r , a 3 -pe rcen tpo rosity estimat e ma y be to o low. The op erato rwho dr i l led the L incoln County wel l cannedwhole-core samples throughout the entire 1,300feet. All of these samples liberated sufficientnatural gas to cause the pressure in the can to in-crease considerably, Although it took about 3weeks for most of the cans to reach a static gaspressure, some of the cans containing the tighter

sections of the shale were sti l l increasing i npressure after a 2-month period,7 The gas liber-ated in the cans had a volume greater than couldbe accounted for by the measured porosity andthe assumed initial reservoir pressure. In otherwords, the gas-occupied porosity may be greaterthan the 3 percent currently indicated by the coreanalysis.

Because it takes as much as 2 months for thegas to escape or flow from a core sample 3.5 or 4inches in diameter and 6 inches long, it may be

that the amount of gas in the Brown shale can bemost accurately determined by measuring the gasthat escapes from core samples. In a normal oiland gas format ion this would be impossiblebecause most of the gas would escape from thecore during normal canning or handling opera-tions. However, in dealing with a material withsuch a low permeability as the Brown shale, it isobvious that very l it t le gas is lost during theperiod of time necessary to remove the core fromthe bottom of the hole and place it in a con-tainer. The amount of gas lost from the cores dur-ing the canning operation would apparently be

limited to the gas in the permeable fractures andwould be negligible compared with the gas in thematrix of the Brown shale. Use of this method ofdetermining the gas in the shale might eliminatethe necessity of measuring the porosity, satura-tions, and reservoir pressure. A technique similarto this is used by the U.S. Bureau of Mines todetermine the amount of natural gas in coal.8



34 . Ch. V—General Reservoir Characteristics

Core Data Distribution

The ga s-prod uc ing po tent ial of the Brownshale cannot be realistically evaluated unti l i tsphysical and chemical characteristics throughoutthe area have been determined. Even though

there are about 10,000 wells currently producinggas from the Brown shale, coring to date has beenlimited almost entirely to the better-producingareas shown in figure 7. The data of table 3 relateonly to wells in the producing area of Kentuckyand West Virginia. Recent research has involvedthe coring of 12 experimental wells, but only 4 ofthese are very far outside currently producingareas.

Figure 7. Major Devonian Shale

Gas Production Areas

OHIO

WEST VIRGINIA

Source Energy Research and Development Admmistration.

An expanded shale inventory by the EnergyResearch and Deve lopment Admin is t ra t ion(ERDA) will provide core samples from wells dis-t r ibuted across a wide expanse in the Ap-palachian Basin and areas to the west and north-west (figure 8). Such da ta are need ed to e valuate

the extent of the natural gas resource in theDevonian shales.

Figure 8. Location of Core Wells in a ProposedInventory of Brown Shales by ERDA

Source Energy Research and Development Administration

Flow Tests

The a c tual significance o f c ore analysis da taand visual observation of core quality can onlybe obta ined through f low tests of the wel ls ,which determine how fast the gas can movethrough the shale. Due to the extremely low per-meability of the shale, it may take several yearsto detect drainage of the potential drainage areaof a we ll. To reduc e the t ime required to d ete r-mine flow rates in Brown shale, a special type oftest is required. The so-called “isochronal” flowtest involves determining flow rates under condi-tions where the entire drainage area of a well hasnot yet been affected and extrapolat ing theresulting data in order to estimate what the wellbehavior will be after the well has affected theentire d rainage area.

Pressure buildup and drawdown tests are con-ducted to determine the significance or accuracyo f the core-ana lys is or log-measured per -

meability, thickness, and saturat ion data.9 10 Apressure drawdown analysis is a mathematical



analysis of the pressure that results in the welldue to continued production at a constant rate,whereas a p ressure bu i ldup ana lys is i s amathematical analysis of the increase in wellpressure that results when the well is shut-in afterbeing p rod uce d at a co nstant rate. The increasein wellhead pressure is determined at regular in-tervals for a specific number of days, weeks, ormonths.

Determining the initial pressure in the Brownshale is difficult and time consuming because ofits low permeability. Reservoir pressures are nor-mally determined by temporarily shutting in awell and then measuring the pressure in the wellbore at the depth being investigated. Using thisprocedure after shutting in a well in the Brownshale will provide an accurate measure of thereservoir pressure only after weeks or monthsbecause of the t ime required for equi l ibr ium

pressure to be reached between the well boreand the adjoining shale pore space. ” Much of thevariation in formation pressure gradients (i.e.,pressure per foot of depth) that has been ob-se rved and reco rded m i gh t be caused bymeasurements taken before reservoir well borepressures are equalized.lz1314

Logging

The term “ logg ing” is applied to a variety of

measurements made in a well by lowering a

mea suring d evic e on a n electric c ab le and rec ord-ing variations of the particular physical propertybeing measured. The p lot of the d at a ve rsusdepth is known as a log. After permeabilities,porosities, and gas saturations have been deter-mined from core analysis, logging techniques areused to measure various physical properties ofthe subsurface formations in place. Interpretationo f we l l l ogs permi t s the de te rmina t ion o fporosities, saturations, and permeabilities of theformation.

A wide variety of physical properties are tradi-

tionally measured in oil and gas wells in this man-ner. Some of these 15 are electrical resistivity,difference in electrical potential between mud inthe well and the fluid in the rock (self-potentiallog), natural radioactivity (gamma-ray log), in-duced radioactivity (neutron log), speed of sound

in the formation (sonic log), formation density,hole size (caliper log), temperature, sound inten-sity (sibilation Iog16), earth gravity,17 and fo rma-tion dip.

Most of these logs may be made either inempty holes or holes containing drilling fluid or

water. Only a few types of logging can be doneafter casing has been set and cemented in thehole,

Whether or not water-based liquids damagethe Brown shale by reducing its permeability iscurrently a subject of controversy.18 19 This poten-tial water damage is not only a problem in log-ging but also causes difficulty in drilling the welland in st imulat ing product ion by f ractur ing.Various combinations of logs must be run to ob-tain the porosity, water saturation, oil saturation,gas saturation, and organic content of formations.

It may be possible to obtain logs in an emptyhole, but it appears to be somewhat easier andsimpler to use a series of wet-hole logs to deter-mine these parameters,20

The sibilation, temperature, and Seisviewerlogging techniques have special applications inthe Brown shale.21 The sibilation log is a high sen-sitivity, high frequency noise detector that can beused to determine where gas is entering the borehole. The temperature log measures changes intemperature to detect where gas is entering thewell bore. Both of these logging techniques areuseful to determine which part of the well in amassive shale section should be treated. TheSeisviewer log produces an acoustic picture ofthe bore hole. Such pictures often detect forma-tion fractures and this is of course useful in thecompletion of the well.

Stimulation Techniques

Knowing that there is a great amount of gas inthe Brown shale, where it is geographically, andwhich vertical portion of the formation is capableof producing it, is of no commercial use unless

some method can be devised which will permitproduction of the gas at an acceptable rate. Inother words, it makes little difference how muchgas is in the shale unless some method can bedeve l oped t o pe rm i t i t s p roduc t i on a t aneconomic rate.



Evaluation of any drilling, stimulation, or pro-duction method is very difficult, because no twowells are the same. This problem is magnifiedconsiderably in dealing with the Brown shale,since its characteristics vary so widely from wellto well even in the same area. Various techniques

have been used to stimulate or increase the flowof gas from the shale. Early gas wells were stimu-lated by explosions (“shoot ing"). 22 More re-cently, hydraulic fracturing has become a usefultechnique. There is no clear-cut experimental evi-dence concerning the relative merits of shootingand fracturing, a l though hydraul ic f ractur inggeneral ly produces sl ight ly higher f low rates.Some companies reportedly continue to shoottheir Brown shale wells while others claim frac-turing gives superior results.23 Other techniquesare now being tested. Descriptions of severalstimulation methods follow.

Explosive Stimulation

Explosions tend to develop fractures and shat-ter a formation, due to the rapidity with whichthe force is applied. Explosive stimulation doesnot affect a formation to as great a d epth as doeshydraulic fracturing.

Convent ional Shooting. -Prior to about 1965,stimulation of oil and gas production from Brownshale was most ly l imited to “shoot ing.” 24 Thisentails setting and cementing casing in a drilledhole with its bottom above the prospective pro-

ducing formation, then detonating explosives inthe open (uncased) hole opposite the prospec-tive producing formation. The explosion cracksand/or shatters the formation, thereby increasingthe size of the well bore and the permeability ofthe formation around the enlarged well bore dueto the cracks therein, Improving the permeabilityof even a few feet of the formation around thewell bore normally greatly improves the capacityof that well to produce.25 Explosive stimulation isthe method that has been used in the completionof most existing Brown shale wells.26

An explosion in the well tends to fill the un-c ased we ll bo re w ith shat tered rock, The generalconsensus seems to be that rubble in the wellreduces the productivity of the well.27 Therefore,most operators attempt to remove the loose

material from the well before trying to producegas from it.

Most prospective Brown shale wells producelittle or no gas before treatment. Consequently, atypical percentage increase in production cannotbe predicted from stimulation efforts. Some wells

have a dramatic increase in gas production aftershooting, whereas others are not benefited.

Explosive Fracturing. —This technique com-bines some of the features of hydraulic fracturinga n d s h o o t i n g .28 The well is f irst fractured hy-draulically and into those fractures explosives areinjec ted and det onate d. The explosion c rea tesadditional small fractures away from the large hy-draulically induced fracture and may also shattersome of the material near the hydraulic fracture.It is theorized that the shattered material willhold op en the frac tures and ma ke a system with a

much higher productivity than a simple-hydraulicfracture would create. The outward explosiveforce of the artificial hydraulic fracture also tendsto open up natural fractures that were encoun-tered by t he a rtific ial hydraulic frac ture. There hasbeen very little experience with this technique inDevonian shales and it is therefore necessary toclassify it as experimental. One of three tests in-volving ERDA and the Petroleum TechnologyCorporation has been performed.

Dynafrac.-Dynafrac is an experimental proc-ess in which several radiating fractures from the

well bore are created and extended by using aslow-burning solid propellant above a column offluid.29 Mechanically, the shooting takes place asfollows: 1) a small diameter solid propellant iscentralized in the hole opposite the producingformation; 2) this solid propellant is covered witha liquid that extends upwards into the casing; 3)a slow-burning solid propellant is placed in atrapped airspace above the fluid level in the cas-ing; 4) both the small-diameter charge and slow-burning solid propellant are f ired at the sametime; 5) the small-diameter charge communicatesits force quickly to the surrounding formation and

causes several radiating fractures to form; 6) theslow-burning solid propellant develops pressuremore slowly and applies this pressure to the fluidbeneath it; and 7) the fluid is forced out throughthe fracture formed by the explosion of the small



diameter charge and the fractures are extendedout into the formation.

The result of the Dynafrac treatment is severalradiating fractures through the formation with aminimum of rubble in the well bore. Developingseveral radiating fractures from the well bore will

give a better opportunity to encounter additionalvertical fracture systems in the Devonian shale.

Nuc lea r Explosive s. —The use of nuclear ex-plosives in the Brown shale is a possible stimula-tion technique. However, the minimal successachieved in stimulating gas production in forma-tions in the West is not encouraging.30 The lackof successful nuclear shots and the sociopoliticaldi f f icul t ies of conduct ing nuclear explosionslargely negate the possibility of using this tech-nique to stimulate Devonian reservoirs.

Hydraul ic Fractur ing

H y d r a u l i c f r a c t u r i n g ( “ h y d r o f r a c t u r i n g ” )became available in the Appalachian Basin in thelate 1950’s. This technique involves injectingfluid into the formation at a rate and pressuresufficient to shatter and fracture the formation.The plane of the resulting fractures is generallyvertical, except at very shallow depths (f igure9).31 This frac ture g rea tly inc reases the c ap ac ityof a well to produce.32

Hydraulic fracturing of a formation can oftenbe ma de more effec tive b y using a fluid tha t has a

high viscosity. In order to keep a fracture opensand normally is added to fracture fluids, as it canprop open the fracture and give i t high per-meability. Because the Brown shale has extremelysmall-sized pores, it has been assumed that anycontact of the formation by liquids, particularlywater, would result in a great reduction in thepermeab i l i t y o f the fo rmat ion to gas . I t i stheorized that the liquid would be held by capil-lary attraction in the extremely small pores andthe threshold pressure of this adsorbed liquidwould be so high that much of the liquid wouldblock the gas from flowing into the well bore.

Also, water-based fluids might swell the clay par-ticles in the shale and thus further reduce the per-meabi l i ty. 33

Consequent ly, unt i l recent years Devonianshale wells were not hydraulically fractured but

s t imu la ted en t i re l y by shoot ing . Recent l y ,however, some hydraulically fractured wells haveperformed better than adjacent wells shot withexplosives. 34

Figure 9. Diagram Showing Relationship of

Maximum Principal Stress and LeastPrincipal Stress to the Plane ofan Induced Hydraulic Fracture

7

Source Overbey, 1976, Energy Research and Development Admlmstratlon

Pub MERC/SP-7612, Fig 3

One of the disadvantages of fracturing a gaswell with a liquid is the length of time requiredfor the fracture liquid to flow back into the wellbore. In low-capacity gas wells, fracture fluidsmay interfere with the gas production for longperiods of time.

Normal Hydraul ic Fractur ing.—Normal hy-draulic fractures are defined and differentiatedfrom massive hydraulic fractures by the amountof fluid in the treatment. Any fracture requiring

less than 100,000 gallons is defined as a normalfracture. On the other hand, the use of foam orgas as described later in this section is differenti-ated from a normal fracture treatment by reasonof the unusual fluids being used for fracturing.



38 q Ch. V—General Reservior Characteristics

Most fracture treatments of the Brown shale arenow made using water-based fluids with chemi-cals added to minimize the effect of water on theclays or minimize reductions in permeability.

It is very difficult to quantify the effect of frac-turing on gas production, because most Brownshale wells produce little or no gas before treat-ment, Generally, increased gas production resultsfrom fracturing Brown shale.

Massive Hydraulic Fracturing ‘ 35,36, 37, 38.—A mas-sive hydraulic fracture is defined as one in whichmore than 100,000 gallons of fluid are used in thefracture treatment. Some massive hydraulic frac-tures have used over 1 million gallons of fluid.

Questions continue to exist concerning thelateral extent of fractures resulting from massivehydraulic treatment.39 In many cases, subsequent

flow tests have not corroborated the formation ofa large fracture. Conflicting opinions exist con-cerning the advisability of massive fracturing. Amajor di f f icul ty has been the tendency of thefracture to leave the target area of a formationand migrate into portions of a formation that donot contain oil or gas.40 Fluids moving into non-productive parts of the shale sequence will notincrea se g a s prod uc tion. This prob lem ma y beminimal in Brown shale, since shale fracturesmore readily than most formations above andbelow it.

Another difficulty with massive hydraulic frac-tures is the long cleanup time required. As muchas 6 months may be required to get all of themobile fracture fluid out of a well.41, 42 An add i -tional problem is that more than an acre of sur-face spac e is needed to a cc ommod ate the equip-ment required for a massive treatment. In hillyApp alac hia, flat sites of mo re tha n an ac re a re noteasily found or constructed, particularly if thewell is located on a steep mountain side or in anarrow gorge,

In spite of all the problems inherent in massivehydraulic fracturing, this stimulation technique

may still have potential in the Brown shale.43

f rac tur ing Wi th Foam 44, 45, 46 .—There is con-siderable question about the ex ten t o f thedamage done to Devon ian sha le fo rmat ionswhen liquids, especially water, come in contact

with the shale.47, 48 Mixing of appropriate chemi-ca ls w i th the t rea t ing water min imizes thed a m a g e t o t h e s h a l e .49 Foam, a mix tu re o fnitrogen, water, and a foaming agent, tends tominimize the leak-off of the fracture fluids intoassociated permeability zones.50

A properly compounded foam can shorten thetime needed to recover fracture fluid after a treat-merit.51 When injected, the foam is compressed;after fracturing, it expands towards the lowerpressure at the well bore and helps expel thefracture fluid from the rock into the well. A time-and/or temperature-effective emulsion breakerca n be ad ded to the foam so that by the time thewell is ready to produce, the foam has brokeninto a mixture of gas and liquid, which facilitatescleaning the well bore.52

Fracturing WithI G a s53.-Using a liquefied gas

as a f r ac t u r i ng agen t ove rcomes c l eanupdifficulties and potential damage to the forma-tion by liquids; no water is used and the liquefiedgas vaporizes as the pressure in the well bore isdropped, However, this technique is quite ex-pensive.

Dendritic Fracturing 54 , —Instead of obtainingone long fracture, the Dendritic fracture methodattempts to form a fracture that branches in manydi rect ions.55 After one small fracture has beencreated, the well system is placed on productionfor a very short time to reverse the stress in the

formation. Addit ional small fractures along themain fracture are thought to form due to thisreversal of stress. When a new fracture force isapplied, one or more small fractures branchingfrom the large fracture are extended. This pro-cedure of f racture-re laxat ion is cont inued todevelop a Dendritic-shaped fracture.

Assertions that such a Dendritic fracture canactually be formed by this technique still requireconfirmation. 56 If the technique does cause frac-tures to develop in a variety of directions andthus intercept a large number of the natural

parallel fractures in the Brown shale, the tech-nique might have potential for increasing gas pro-duction from them.

Directional Dri l l ing 57, 58.—Directional drilling isanother production stimulation technique that



may have potential in the Brown shale. Becausemost natural fractures in the Brown shale appearto be parallel vertical fractures,59 it is theorizedthat a well drilled diagonally across this verticalsystem of fractures would encounter more of thefractures and thus result in substantially greater

product ion. Very l it t le d i rec t ional dr illing hasbeen done in the potential producing area of theBrown shale.60

Considerable difficulty was encountered in anexperiment with directional wells in the Brownshale.61 Although the mechanics of the dri l l ingoperation were successful (figure 1 O), gas pro-duction did not meet expectations and thereforeonly one of three planned wells was drilled.

Figure 10. Deviated Wells and

Earth Fracture Systems Process

Directionally<Deviated Wells>

Source Energy Research and Development Administration

Other Stimulation Methods

Many, other techniques have been proposedfor recovering gas from the Brown shale, although

most of these are techniques that have been usedto recover oil rather than gas.

Microbial .—It has bee n proposed tha t ba cte ria

could be introduced into oil reservoirs to formgases and/or change the interracial tension andviscosities to make the trapped oil more mobile.

Microbial techniques do not appear to have greatpotential for gas recovery where the gas mobilityis limited by the tight matrix of the Brown shale.Although there are bacteria able to withstandtemperatures and pressures found at a depth of3,000 to 4,000 feet, none are known that willboth successful ly generate useful modifyingproducts in sufficient amounts and also toleratethe chemical and thermal environments at thosede pt hs. The job of inoculating a large area of verylow-permeability shale would be very difficult, ifnot impossible, unless a microbial hydrofracturetechnique could be perfected. Further, any strainof bacteria developed would need to be carefullyscreened for potential environmental impacts.Even should the conceptual process be feasible,it is unlikely that the necessary strains could bedeveloped, field tested, and put into commercialoperat ion wi th in t ime to in f luence shale gasrecovery by the year 2000.

Thermal.—A variety of thermal methods havebeen successfully used to increase recovery of oilfrom various formations. The value of thesemethods for reducing the viscosity of gas wouldappear to be minimal, although laboratory results

indicate that gas is released from Brown shalefaster when the shale is heated. This appears tobe due to the expansion of gas in the shale andthe resulting increase in pressure which forces thegas from the shale at a higher rate. It seems possi-ble that such an effect might be useful in theDevonian shale reservoir. Burning of gas in theDevonian shale (or applying heat by other means)could increase gas pressures locally and cause thega s to m ove m ore rap idly tow ard the we ll. Thecost of supplying oxygen to the formation tomaintain a fire, and the poor heat conductivity ofshales in general, make it unlikely that thermalprocesses would be economical.

Mining. -Brown shale outcrops cover an ex-t remely wide area in the Appalachian Basin(figure 3). It is technologically possible to minethe Brown shale, then recover the gas from the



shale by means of various thermal-chemicalmethods. Such methods might also recover anyl iqu id hydrocarbons conta ined in the Brownshale. Because of the low volume of gas in theBrown shale, costs of mining and retorting proba-b ly wou ld be g rea t . Likewise, environmentalproblems associated with processing the shaleand disposing of the spent shale could be obsta-cles to any large-scale mining venture. It appearsthat most proposed approaches to recovering gasfrom strip mined Brown shale will not result innet energy gains. Producing shale gas by subject-ing mined shale to var ious thermal-chemicalprocesses will probably result in costs of $5.00 to$6.00 per Mcf, comparable to, or higher than thecost of producing high Btu gas from coal.

Potential of Alternative Stimulation Methods

None of the thermal, microbial, or thermal-chemical methods proposed for recovering gasfrom the Brown shale appear to have a high po-tential for recovering a significant amount of gaswithin the next 20 years. It has been shown that

thermal, microbial, and thermal-chemical tech-niques are capable of recovering gas from theBrown shale under very limited and controlledcondi t ions, but the physical and economicfeasibility of commercial operation has not beendemonstrated to date.







VI. Economics ofBrown Shale Gas Production



VI. Economics ofBrown Shale Gas Production

There are three principal areas of uncertainty inevaluating the commercial potential of naturalgas production from the Devonian shales. Thesebasic uncertainties are:

. economic

q technological, and

q geologic.

The e c ono mic un c erta inties involve primarilyexpected well head prices and the tax treatmentof income f rom natura l gas product ion, buteconomic uncertainty also intersects technologi-

cal uncertainty. The areas of intersection involvepossible progress in drilling technology and theeffects of stimulation techniques on production.The principal geologic uncertainty involves theBrown shale resource base, i.e., how much of theBrown shale is a high-qual i ty, gas-product iveresource, how much is medium quality, and howmuch is low quality? As natural gas prices in-crease to reflect the value of this resource moreclosely, it is reasonable to expect that relativelylarge amounts of shale gas might becomeeconomically attractive. What is not now ade-quately known, and can only be determined fromactual drilling and production experience over awide geographic area, is the quantity of high-,medium-, and low-quality areas of Brown shale. ’

The a pp roa c h used here i s to d ea l w itheconomic uncertainty by considering a range ofwe llhea d prices and tax trea tme nts. These rang esof price and tax cases are used to evaluate theafter-tax net-present values (ATNPV—Currentworth of a flow of income after taxes); of gaswel ls dr i l led in to the Brown shale in threegeographic localities in the Appalachian Basin.The drilling costs, dry-hole experience, and pro-

I See the section titled [xtent of th e Economically Pro-

ducible Area for rationale used to estimate the quantity ofcommercial ly productive Brown shale In the Appa lach ian

Basin,

duction profile information used in the ATNPVcalculations are the actual data for each of thethree Iocalities,2 and each locality is evaluatedseparately. J The three were chosen as examplesof high-, medium-, and lower-quality resourcesfor which adequate data were available on aconsistent basis to support ATNPV calculationsunder alternative assumptions concerning theprice and tax determinants of economic incen-t ives. I t must be real ized that these threelocalities are situated in a small area of the Ap-palachian Basin which is known to be gas pro-duct ive. Therefore, the te rms h igh-qua l i t y ,

medium-quality, and low-quality resource arerelative to each other only, and production datafrom these three localities cannot be extrapolateddirectly to the entire 163,000-square-mileextent ofthe Appalachian Basin.

Production data from 490 shale wells in thegas-productive area of the Appalachian Basinwere used to estimate the potential productionfrom other areas of the Appalachian Basin whereshale gas production might be economicallyfeasible. This part of the analysis is the point ofmost crucial interest and the weakest link in the

overall analysis, Until substantially more drillinghas been done over a wide area, the amount ofthe Brown shale resource with economic poten-tial will not be known with any more confidencethan the judgmentally plausible estimates used in

zThe a ft er. tax net-present value (A TNPV) calculations

w e r e m a d e w i t h t h e a i d o f a c o m p u t e r i z e d r o u t i n ed e v e l o p e d b y Drs, Robert Kalter and Wal lace Tyne r. This

ATNPV calculation routine is described in Wallace E, Tyn er

and Robert ] . Kalter, “ A Simula tion Model fo r ResourcePolicy Evaluation, ” Co rnell Ag ricultural Ec ono mic s Sta ff

Paper No. 76-35, November 1976.3These ind iv Idual localit ies a r e n o t h o m o g e n e o u s I n

terms of either the quality of the resource base or thestimulation technique used. As a result, seven types ofBrown shale gas production in the Appalachian Basin are ac-tually evaluated on an ATNPV basis.

45



46 • Ch. VI—Ec ono mic s of Brow n Shale G as Produc tion

this analysis. q The assumptions used here are ex-plicit, and are subject to sensitivity variation andrevision as more a c tual d rilling results b e c o m eavailable.

The general result of the analysis is relatively

opt imist ic:q if 10 percent of the total Appalachian Basin

shale is as attractive as the higher qualityresources examined here;5

q if there” is no improvement in drilling tech-nology or stimulation techniques; and

. i f current tax t reatment of income f romnatural gas production continues; then,

Price, Tax, and Other

In recent years, wellhead gas prices have in-creased substantially and the tax treatment of in-come f rom gas product ion has become lessgenerous. In this analysis, four alternative pricesfor prospective Brown shale gas and four taxcases are c onsidered, The b asic p rice a nd taxassumptions are firmly rooted in the current factsof interstate and intrastate gas markets and inter-nal Revenue Service (IRS) treatment of incomefrom ga s prod uc tion. The a dd itiona l price a lter-natives and tax cases are designed to cover a

broader range of p ossib il it ies for enhanc edeconomic incentives and to test the sensitivity ofthe ATNPV o f sha le gas po ten t ia l t o suchpossibilities.

4There a re approximately 1 0 , 0 0 0 wells producing ga s

from the Brown shale. But data for many of these wells arenot readily available, a large fraction of the wells are in arelatively small area, and for many wells production fromthe Brown shale is commingled with production from otherzones. It is possible that careful screening and analysis oft h e s e d a t a w o u l d s i g n i f i c a n t l y i m p r o v e o u r c u r r e n t

knowledge of the Brown shale resource, but such an effortwas beyond the scope of this assessment.

sThe rat ionale for considering 10 percent of the Ap -

pa lach i an Basin as higher-quality resources is presented inthe section of this report titled, Extenf of th e Economica l ly

Producible Area.

q at wellhead prices for natural gas in the$2.00 to $3.00 per Mcf range, it is notunreasonable to conclude that the Brownshale of the Appalachian Basin may have aproduct ion potent ial in the neighborhoodof 1 trillion cubic feet (Tcf) per year for a

considerable future period.

Such a level of production would require asubstantial effort (69,000 wells), but the addi-tional supply is not inconsequential in the con-text of the current and prospective U.S. naturalgas situation. One trillion cubic feet (Tcf) per yearof Brown shale gas would be equivalent to about5 percent of current U.S. production.

Economic Assumptions

Price Assumptions

The four alternative assumed prices are:

. $1.42 per Mcf,

. $2.00 per Mcf,

. $2.50 per Mcf, and

. $3.00 per Mcf.

The current Federal Power Commission (FPC)wellhead ceiling price for sales of natural gas ininterstate commerce is $1.42 per Mcf.6 This pric ei s sub j ec t t o a 1 -cent escalat ion every 3months. It also contains a provision for an up-ward proportional adjustment if the gas sold con-tains more than 1,000 Btu’s per cubic foot.7 Muchof the gas from the Devonian shale of the Ap-palachian Plateaus has a substantially greater Btucontent than the FPC standard upon which the$1.42 per Mcf new-gas ceiling rate is based—it isnot uncommon for gas from Brown shale to havea Btu content as high as 1,350 Btu’s per cubicfoot. In addition, although a considerable part of

the area of Brown shale potential, particularly inWest Virginia, is served b y interstat e p ipe linessubject to FPC ceil ing price regulation, much

6Federal p o w e r c om mission, o p in io n No . 7’70-A, P. 181 ~

Tbid, pp. 186-187.



Ch. VI—Ec ono mic s of Brown Shale G as Produc tion q 47

prospective shale gas may be sold in intrastatecommerce. prices in intrastate markets aretypically higher than those in interstate markets.8

For these two reasons —Btu adjustment and in-trastate market sales—the current $1.42 Mcf ceil-ing price may be considered a lower-limit base

case on wellhead prices, which will be a determi-nant of the economic feasibility of Brown shaleproduct ion. 9 In addition, there are the prospectsof higher FPC ceilings for new gas or of congres-sional deregulation of new gas sales. Both ofthese later possibi l i t ies support t reatment of$1.42 per Mcf as a lower limit base case.

The we ighted average price per Mc f for na-tional natural gas sales in intrastate commerce fornew contracts signed in the second quarter of1976 was $1.60 per Mcf. Many contracts were inthe neighborhood of $2.25 per Mcf. Prices in thisrange ca n be considered the leading ed ge o f the

intrastate gas market. Intrastate sales of gas fromBrown shale in Ohio and Kentucky have broughtprices of over $2.00 per Mcf, The recent trends ofboth interstate and intrastate wellhead priceshave been upward. Current shortages suggestthese trends will continue. Leasing, drilling, andwell-completion decisions on the basis of priceexpectations of $2.00 per Mcf or more for Brownshale gas in various areas are therefore not anunreasonable assumption. The second alternativeprice is $2,00 per Mcf.

The t hird a nd fourth a l ternat ive p ric es are

$2.50 and $3.00 per Mc f. The prices of alte rna-tive fuels such as fuel oil, propane, syntheticnatural gas (SNG), or liquefied natural gas (LNG)are either at or substantially above these valueson a Btu basis. Use of prices in this range is

Ssee Federal Power Commission form 45 d a ta .

qwellhead prices a lso reflect unit transportation c05ts to

end-use markets. Unit transportation costs are a decreasingfunction of the volume of shipments. Shale gas output perp ro d u c in g a re a ma y so me t ime s b e sma l l e n o u g h th a trelatively high unit transportation costs have an adverse

effect on the wellhead netback from end-use markets. Forthe purposes of the analysis here, we assume that the high-

quali ty Btu characteristics of Brown shale, its proximity tomajor markets, the possibility of intrastate sales, the form of

pipeline and distribution company regulation, and the costof alternative supplies all operate to make the !$1 ,42 per Mc fvalue a lower-limit base case.

therefore appropriate in the ATNPV calculationsin order to test the potential sensitivity of naturalgas production from the Brown shale to substan-tially enhanced economic incentives. It must beemphasized, however, that these values are notprice projections or forecasts. For the purposes of

the calculations reported herein, they are merelyelements of the sensitivity analysis.

All prices are specified in constant 1976 dol-lars. In each of the ATNPV calculations reportedbelow, if a price of $1.42 per Mcf (or $2.00,$2.50, or $3.00) is specified that price is assumedto hold in constant 1976 dollars for the life ofp roduc t i on . D r i l l i ng , we l l - comp l e t i on , andoperating costs are also specif ied in constant1976 dollars. These cost components are dis-cussed in more detail in the section on cost andtechnological considerations.

Tax Assumptions

Four cases for the tax treatment of incomefrom gas product ion are considered in theATNPV calculations reported below. These are:

q

q

q

q

zero percentage depletion allowance andno investment tax credit;

22-percent depletion allowance and no in-vestment tax credit;

zero percentage depletion allowance and a10-percent investment tax credit; and,

22-percent depletion allowance and a 10-percent investment tax credit.

The a ssump tion of zero pe rcenta ge de pletiona l l owance and no i nves t men t t ax c red i t i sconsistent with the current treatment of incomefrom natural gas production for producers withaverage daily output in excess of 2,000 barrels ofoil or 12 MMcf of natural gas. Relative to typicallease output for Devonian shale product ion,these are large amounts of natural gas. But mostU.S. oil and natural gas output is produced by the

very large number of operators (whether corpora-tions, partnerships, or sole proprietorships, etc.)wi th product ion above these cutof f levels. I feconomic incent ives are suf f ic ient to makeBrown shale prospects an attractive investmentopportunity, and if the Brown shale resource is



48 Ch. VI—Ec ono mic s of Brow n Shale G as Produc tion

extensive enough to allow significant volumes ofproduction, then this tax treatment is relevant formany potential Brown shale operators. Togetherwith the $1.42 per Mcf price assumption, this taxtreatment defines the lower-limit base case con-sidered here.

The 22-perce nt de pletion allowance and zeroinvestment tax credit is the tax treatment rele-vant to many, perhaps most, current Brown shaleop erato rs. The sma ll-produc er exemption pha sesdown, on an allowable output basis over theperiod 1976-80, to 1,000 barrels of oi l or 6million cubic feet of gas per day. Beginning in1981, the appl icable percentage deplet ionallowance rate begins to decrease on a phasedbasis from 22 percent until it reaches 15 percentin 1983. However , a 22-percent dep le t ionallowance rate for production not in excess of1,000 barrels of oil per day or 6 million cubic feet

of natural gas per day will be allowed for produc-t ion which results f rom enhanced or tert iaryrecovery. Because of the following reasons:

q

q

q

eligibility of small Brown shale operators for22-percent depletion allowance until 1981,

importance of the early years’ receipts in thenet present value calculations, and

possible classification of Brown shale opera-tions as tertiary or enhanced recovery pro-duct ion;

the second tax case is a relevant component oft he sens i t i v i t y ana l ys i s f o r t he economi cfeasibility of Brown shale gas supplies.10

The third tax c ase c onsidered p uts the t axtreatment of income from gas product ion onmore of an equal footing with the tax treatmentof other nonextractive investment opportunitiesin the U.S. economy. In this third case, percent-age depletion is set at zero and an investment taxcredit of 10 percent is assumed.

lc)Con5ideratlon of this tax case is not an implicit recom-

mendation for differential tax treatment by size or status ofoperator. Rather, it is simply a recognition of the current lawand the fact that different categories of operators focus theirac t iv i t ies in d i f fe ren t a reas and on d i f fe ren t types o fprospects.

The fourth tax case is a liberalized tax treat-ment of income from gas production. Percentagedepletion is assumed at 22 percent and a 10-per-cent investment tax credit is allowed.

In all four tax cases considered, no change isassumed in the tax treatment for expensing of in-

tangible drilling costs.

State income and severance taxes are assumedto be e quivalent to an ave rag e State incom e taxof 12 percent. Actual income and severance taxrates in the Appalachian Basin States in which in-creased Brown shale production may become afactor are typically Iower.11 However, experiencein Gulf Coast and Southwestern States, whereseverance taxes have been converted from a unitto

to

sit

an ad valorem basis, suggests that it is prudentuse conservative State tax rates for the sen-vity analysis reported below,

Other Economic Assumptions

The ATNPV calculations are also sensitive to anumber of other factors. These include:

q

q

q

q

q

the discount rate;

the lag between initial investment costs andthe commencement of sales;

the time profile of production;

the amount of recoverable reserves per unitof investment cost; and

operating costs.

The discount rate used in the ATNPV calcula-tions reported below is 10 percent in real termsafter taxes. (“Real terms” means in constant dol-la rs ad jus ted fo r i n f la t ion . ) Many ind iv idua lentrepreneurs and corporate decision makers nowrequire rates-of-return for project evaluat ionwhich are substantially in excess of 10 percent,but these higher rates are expressed in current

I IThe highest marginal rate for corporate income ta x is

5.8 percent in Kentucky, 8 percent in Ohio, and 6 percent inWest Virginia. Ad valorem and severance taxes for these

States are approximately 2,2 percent for Kentucky, 2.6 per-cent for Ohio, and 10 percent for West Virginia of typicalgross revenues expected for a Brown shale well.





50 q Ch . VI—Eco nom ics of Brown Shale Ga s Produc t ion

Figure 11. Comparison of Gas Production from Brown Shale Wellsand a Typical Offshore Gas Well

Year of Production

100 ‘

90 -

Year of Production

Source. OCS production rates developed by Exxon, USA for the Federal Power Commtswon’s Natural Gas Survey. Rates forBrown shale production from over 200 wells in Kentucky and West Vlrglnla (Columbla Gas Company, Ray Resources Corp, andConsolidated Gas Co).



Ch. Vi—Eco nom ics of Brow n Shale G as Produc t/ on . 51

natural gas well is compared with those of two tion profile has a weaker positive effect upon thetypical Brown shale wells. In the first 15 years of ATNPV of the prospect. This production profile,p roduc t ion, on l y 38 t o 54 pe rc en t o f t o t a l together with the relat ively smal l volume ofrecoverable shale gas reserves are produced, but reserves per unit of investment cost, has been theabout 85 percent of the reserves in the offshore principal reason that, until recently, Brown shalereservo ir a re p roduc ed. Produc t ion wh ich i s ga s p roduct ion has been eco nomica lly sub-

weighted toward the la ter years in the produc- marginal.

Cost and Technological Characteristics of

Brown Shale Production in Three Localities

Product ion data have been obtained from shot wells. These figures are the averages of ac-three gas-product ive lo c a t i o n s in t h e A p - tual production data for 13 wells in this field forpa lac hian Basin, These loca lities, in desce nding the 15-year period .order of general investment attractiveness, areCottagevil le, W.Va. (high quality); Clendenin,

In the medium-quality shale, data were availa-

W.Va. (medium quality); and Perry County, Ky.ble for both shot and hydrofractured wells, but

(lower quality). The quality designations reflect only for 5 years. The rest of the profiles were ex-trapolated using production decline curves forgeologic and economic characteristics of each

Brown shale wells developed for the region.14

reg ion and are no t i n tended to re f lec t anydi f ferences in the actual Btu content of the l qBagna l l and RYan, “The Geology, Reserves and Produc -natural gas in the fields. The 15-year production

tion Characteristics of the Devonian Shale in Southwesternpro f i les a re g iven in tab le 4 . I n t he h i gh -qua l i t y West Virgin ia,” figure 11, Devonia n Shale-Prod uc tion and

area, production data were available only from Potent ia / , ERDA, 1976.

Table 4

Production Statistics of Natural Gas From Brown Shale in Three Localities

(Mcf Per Year)

Locales: High Quality Med ium Qua lity Lo we r Qua lity

Good Bad

St im u la t io n: Sho t Frac * Shot Frac Shot Frac Shot

Year-1 . . . . . . . . . . . . . . . . . . . . . . .

2

3: : : : : : : : : : : : : : : : : : : : : : :4. .., . . . . . . . . . . . . . . . . . .5. ....., . . . . . . . . . . . . . . . .

36,318

29,490

23,883

20,071

17,439

15,980

14,879

13,464

12,772

12,498

11,661

11,30411,131

10,842

9,766

17,989

20,22717,97818,57017,00016,000

15,000

14,500

13,800

13,500

12,700

12,20011,700

11,300

10,800

17,858

16,05312,34211,00110,000

9,000

8,200

7,500

7,000

6,500

6,100

5,8005,500

5,200

5,000

21,250

20,85020,60017,70018,35017,29017,000

16,30015,600

15,00014,500

13,80013,30012,80012,300

18,750

15,88013,60011,4801-1,17011,080

10,000

9,300

8,700

8,200

7,800

7,5007,200

7,000

6,800

11,400

10,900

9,200

9,600

8,300

7,500

6,900

6,300

5,800

5,050

4,750

4,5004,250

4,050

3,850

6,800

5,000

5,600

5,100

5,400

5,300

5,000

4,950

4,900

4,800

4,700

4,6004,550

4,450

4,400

Source: Production and cost data on Brown shale operations are “Hyd rofrac turlng IS c o m m o n l y re f e r re d t o a s “ f r ac , ” wh ich WIII

averages f rom over 200 wells In Kentucky and Wes t Vlrglnla (Co- be used as an abbreviat ion in tables In this report,

Iumbla Gas Co., Ray Resources Corp., and Consolidated Gas).



52 . Ch. VI—Ec ono mic s of Brow n Shale Ga s Produc tion

Because of great, variability in the productionfrom the wells in the lower-quality location, thewells were separated into two groups-good andbad-based solely on their product ion rates.Shot and hydrofractured wel ls fel l into bothgroups. Fifty-nine percent of the wells in thislocality fell into the good group, while the re-

maining 41 percent were in the bad group. Onemight be misled by looking only at the goodgroups in this locality for comparison with thehigh- and medium-quality locality, because oneassumes a risk of having a bad well in this locality41 percent of the time. So, while one can get agood well from the lower-quality locality, the in--

vestment potential on average is less attractivethan in the other localities.

In judging the investment potential of thelocalit ies, there is concern regarding the costsassociated with the production: the initial costs

for drilling and stimulating the wells, the annualoperating costs, and the indirect cost from therisk of drilling a “dry hole. ” Table 5 shows theaverage of the direct initial costs for drilling and

Table 5

Direct investment Costs for ProducingWells in Brown Shale

(Dollars in thousands, 1976 constant)

Locality

High Quality . . . . . . .

Medium Quality . . . .

Lower Quality . . . . . . .

Stimulation

Technique

Shot

Frac

Shot

Frac

Shot

Locality

High Quality. . . . . . . . . .

Medium Quality . . . . . .

Lower Quality . . . . . . . .

Average Cost

I n t a n - T a n -g i b l e g i b l e

$ 80.5 $23.9

121.7 38.798.9 20.8

1 1 5 . 9 4 0 . 0

9 4 . 3 2 7 . 4

Total

$104.4

160.4119.7

155.9

121.7

stimulat ing w ells in the loca lities. The d ifferenc esin drilling costs reflect differences in depth of thewells in the various portions of the AppalachianBasin and in the drilling costs per foot, which area func t ion o f the geo log ic and topograph iccharacteristics of the localities. Detailed costfigures are presented in tables 13 through 17 at

the end of this chapter.

Drilling costs in the lower-quality locality weretaken to be about $10 per foot, whereas theywere about $9 per foot in the other localities. It isrecognized that in some other areas these costsmay be as low as $6.50 per foot, but these areasare readily accessible and have easily workedgeologic formations. In light of the potential fortechnological advances in the drilling process, alow estimate is given in table 6, approximatelyreflecting a 10-percent reduction in actual drillingcosts .15 The effect of lower drilling costs or of

cheaper stimulation techniques on the invest-ment decision in the localities can be examinedby comparing the reduction in average and lowest imates wi th the ATNPV for the d i f ferentscenarios as displayed in tables 8 through 11.

The effec t o f p rogress in drilling technology orof improvement in stimulation procedures, whichreduces the initial investment cost per unit ofreserves, wi l l be to extend the economical lyfeasible portion of the Devonian shale resource.A 10-percent decrease in real drilling costs, suchas that assumed for purposes of example in table6, would make some of the prospects in tables 8

I jsee, fo r exarrrple, Franklin M. Fisher, “Technological

C h a n g e a n d t h e D r i l l i n g C o s t - D e p t h R e l a t i o n s h i p ,1960 -66,” in E.W. Erickson and L. Waverman, editors, The

Energy Question, Vol. 2, North America, University of Toron-

to , 1974.

Table 6Effect of Reduction in Initial Investment Cost


StimulationTechnique

Change in ATNPVas a Result of

Average Cost Lo w Est ima te Reduced Costs*

Shot $104.4 $ 90.4 +$6.5

Frac

Shot

Frac

Shot

158.4 137,4 + 9 , 6

119.7 102.6 + 7 . 8

155.9 144.3 + 5 . 3120.5 110.8 + 4 . 4

q The only change In tax effect considered IS In the first-year writeoff of lntanglble~.



Ch. VI—Economics of Bown Shale Gas Prodcution . 53

through 11, which have small negative ATNPVvalues, economically attractive.16

The a verage c osts are sep arate d into intangibleand tangible items because of the impact of thedi f ferent tax t reatment as to expensing andcapital izing these costs. The intangible costs

were set to include a management fee of about15 percent and a contingency fee of 6 percent.While these figures may be high for some opera-tors at some locations, they are typical of currentcharges and are representative of anticipatedcosts if an extensive effort to develop the Brownshale should occur.

The a nnua l ope rating costs a re set a t $1,800per well. While some operators may use a sub-stantially cheaper well-tending service, this figureprovides a cushion for expenses resulting fromequipment repair.

An addit ional cost to be considered is thatassociated with the risk of a “dry hole. ” This riskis difficult to assess because of the difficulty indetermining which wells are in fact “dry holes.”Of course, the clearest case is the hole whichprod uce s no natural gas at all. The prob lem a riseswhen there is some gas but the flow is not suffi-

I b s e n - l e of th e wells w i t h n e g a t i v e ATNPV values in ta -

bles 8-11 would nevertheless be producers because drillingcosts are already committed and the returns on incrementalout-of-pocket completion, stimulation and production costsare adequate to induce production. But these wells would

not return 10 percent after taxes on total Investment.

cient to make the well profitable based on itsown operations. The decision to continue thefinal casing of the well would be based on theadditional cost of finishing the well rather thanthe amount already invested. However, it is com-plicated not only by the uncertainty of the priceto be received for the gas but also by its useful-ness to the investors as a tax shelter for other in-come. In addition, under syndication, not only domarginal tax rates vary among investors andoperators, but which costs are sunk and whichare incremental may be different to investors ando p e r a t o r s . H e n c e , w e l l s w h i c h w o u l d b eeconomically unattractive on a total basis may bebrought into production for personal f inancialreasons of a key decisionmaker. This effect mayalso work in the opposite direction. Since it isalmost impossible to determine the impact ofthese incentives on the number of “dry holes, ”and some external incentives are likely to con-tinue to affect the “produce or plug” decision,the number of dry holes is taken to be thosewhich presently are not in actual productionregardless of the basis for the decision.

A s e v i d e n t f r o m t a b l e 7 t h e r e i s g r e a tvariability among the localities in the share ofdry-hole c osts for ea c h p roduc ing we l l. Thisvariability does not arise solely from the actualcosts of a dry hole as shown in column 1, butrather in the ratio of number of dry holes to thenumber of producing wells in each locality. This

Table 7Effect of Dry Holes on the Cost of Producing Wells


Column 1

Cost of a

Locality Dry Hole

High Quality. . . . . . . . . . . . . $ 8 6 . 9

Medium Quali ty

Frac . . . . . . . . . . . . . . . . 97.9

Shot. . . . . . . . . . . . . . . 96.1

Lower Quality . . . . . . . . . . . 101.1

Column 2 I Column 3

ICost of Dry Hole- No. of

N et o f Ta x Writ e of f* D ry Ho le s

$34.7 15

29.6 1

38.4 1

40.4 I 49

Column 4 Column 5Share of After-TaxDry-Hole Cost for

No, of Each ProducingProducing Wells Wel l

72 $7.2

27 1. 5150 0. 3

24 1 8.2

q This ca l[ ulat lon I \ ba~ed on a 48 percent marginal Federal tax rate and a 12 percent average State tax rate. It also IS b a w d on the assump-

tion that the taxpayer has at least this much income which would otherwise be taxable at the~e rates. To the e xtent the ta xpa yer is not at the

marginal Federal and State tax rates, the average State tax rate IS less than 12 percent, or the taxpayer does not have Income which would

otherwls~’ be taxable, the after-tax co~t of dry holes Increases



—.

54 . Ch. VI—Economics of Brown Shale Ga s Produc tion

heterogeneity probably arises not just f rom resource poo l. The va lues of ta b le 7 a re inc ludedgeologic differences but also from the operators’ as neg at ive comp onents of the ATNPV ca lcula-aggressiveness in drilling to the boundaries of the tions reported in tables 8 through 11.

Analytical Results for After-Tax Net-Present Values

Under Alternative Price and Tax Assumptions

The basic analytical results are presented intables 8 through 11. In each table, the four alter-native price assumptions are the column head-ings. The resourc e q ua lity examples a re the rowheadings. For the medium-quality resource baseexample, two alternative stimulation techniquesare displayed. For the lower-quality resource baseexample, two stimulation techniques and two in-ternal quality distinctions are displayed. Each ta-ble refers to a specific tax case:

q Tab le 8; de pletion a llowance = zero,

investment tax credit = zero,

q Tab le 9; dep letion a llow anc e = 22 percent,investment tax credit = zero,

q Table 10; depletion allowance = zero,investment tax credit = 10 per-cent,

q Tab le 11; de p letion allow anc e = 22 pe r-cent,

investment tax credit = 10 per-cent.

The entries in the bodies of the tables are theafter-tax net-present values (ATNPV; in thou-

sands of dollars) based on the actual investmentand operating costs and production profi les inthe three localities under the assumed price andtax conditions and at a 10-percent discount fac-tor. if the entry is positive, the investment has aninternal rate of return in excess of 10 percent. Ifthe entry is negative, the investment has an inter-nal rate of return of less than 10 percent.

For example, in table 8 (depletion and invest-ment tax credit both equal to zero), only thehigh-quality resource has a calculated ATNPV per

well which is positive at an assumed price of$1.42 per Mcf. All the other situations have per-well ATNPVs which are negative. This may ap-pear anomalous because the actual localit iesupon which these illustrative ATNPV calculationsare based are a ll be ing d evelop ed . ” This continu-ing development is presumably based on privatebusiness decisions involving expectations ofpositive after-tax net present values. The fact that

1“It will be recalled that the high-quality case is based onoperating experience in the Cottageville, W. Va., area; the

medium-quali ty case on Clendenin, W. Va.; and the lower-quality case on Perry County, Ky.

Table 8After-Tax Net-Present Value of Brown Shale Natural

Gas Wells in Three Locations-Case A*

(Dollars in Thousands, 1976 constant)

Location I Stimulation

High Quality . . . . . . . . . . . . . . . . .

Medium Quality . . . . . . . . . . . . . .

Lower Quality . . . . . . . . . . . . . . . .

Good . . . . . . . . . . . . . . . . . . . .Good . . . . . . . . . . . . . . . . . . . .Bad . . . . . . . . . . . . . . . . . . . . .Bad . . . . . . . . . . . . . . . . . . . . .

Shot

Frac

Shot

Frac

ShotFra c

Shot

$1.42

+2 1

– 1 6

– 1 9

– 1 6 – 2 2

– 5 5 – 4 8

Wellhead Price per Mcf

$2.00

+ 5 7

+ 1 0 –1

+13

– 3

– 4 2 –40

‘$2.50

+ 8 4

+ 3 3

+ 1 3

+ 3 8+ 1 3 –31

– 3 2

$3.00

+114

+5 6

+2 8

+63

+2 8

–20

–25

“Assumptions:

Depletion Allowance o

Investment Tax Credit o



Ch. VI—Economics of Brown Shale Gas Production . 55

Table 9After-Tax Net-Present Value of Brown Shale Natural Gas Wells in Three Locations-Case B*


Location

High Quality . . . . . . . . . . . . . . . . .

Med ium Qua lity . . . . . . . . . . . .

Lower Quality

Good . . . . . . . . . . . . . . . . . . . .

Good . . . . . . . . . . . . . . . . . . . .Bad . . . . . . . . . . . . . . . . . . . . .Bad . . . . . . . . . . . . . . . . . . . . .

Stimulation

Shot

Frac

Shot

Frac

ShotFrac

Shot

$1.42

+43

+1

–8

+2

– l o

–50

–45


$2.00 I $2.50

+8 6

+3 4

+1 4

+ 3 9+ 1 4

–31

–33

+ 1 2 3

+63

+33

+7 0

+35

–17 –23

$ . 3 . 0 0

+160

+9 1

+5 1

+102

+52

–3

–13

q Asumptlons:Deple t ion A l lowance 220/ 0

Investment Tax Credi t o

Table 10After-Tax Net-Present Value of Brown Shale Natural Gas Wells in Three Locations-Case C*


Locations I Stimulation

High Quality . . . . . . . . .“. . . . . . . .

Medium Quality . . . . . . . . . . . . . .

Lower QualityGood. . . . . . . . . . . . . . . . . . . .

Good . . . . . . . . . . . . . . . . . . .Bad ., . . . . . . . . . . . . . . . . . . .Bad , . . . . . . . . . . . . . . . . . . . .

Shot

Frac

Shot

Frac

ShotFrac

Shot

$1.42

+23 “

– 1 3

– 1 7

– 1 3 –20 –52

–46


$2.00

+ 5 7

+ 1 3o

+1 6

– 1 – 3 9 – 3 8

$2.50 I $3.00

+ 8 6 + 1 1 6

+ 3 6 + 5 9+ 1 5 +3 0

+4 1 +6 6

+15 +32

–28 –17 –30 –23

“Assumption:

Depletion Allowance o

Investment Tax Credi t 10“ / 0



56 . Ch. VI—Ec ono mic s of Brown Shale Ga s Prod uc tion

Table 11

After-Tax Net-Present Value of Brown Shale Natural Gas’ Wells in Three Locations-Case D*

(Dollars in Thousands, 1976 constan t)

Location

High Quality ... . . . . . . . . . . . . .

Medium Quality . . . . . . . . . . . . . .

Lower Quality

Good . . . . . . . . . . . . . . . . . . .Good . . . . . . . . . . . . . . . . . . . .Bad . . . . . . . . . . . . . . . . . . . . .

Bad . . . . . . . . . . . . . . . . . . . .

q Assumption:

Stimulation

Shot

Frac

Shot

Frac

ShotFrac

Shot

Deple t ion A l lowance 220/ 0

Investment Tax Credi t 10“ / 0

the lowe r-limit base case has neg at ive ATNPVSfor most situations is attributable to a number offactors:

q

q

q

q

q

there is no Btu adjustment in the assumedprices;

some of the gas is sold in intrastate marketsat higher prices;

the assumed tax treatment is more severethan that actual ly experienced by manyoperators;

the assumptions concerning investment andop erat ing c osts and well Iives weregenerally slightly tilted in the direction ofadverse results; and

the poorer si tuat ions in the lower-qual i tyresource area are legitimate losers. “ “

The lower-limit base case for $1.42 per Mcf intable 8 reflects the conservative nature of theassumptions on which the ATNPV calculationsare based in all the price and tax cases analyzed.

The part icu lar ATNPV f igures reported intables 8 through 11 are all of interest,18 but what

Iq f economic incentives are such that there is substantial

Devonian shale development under condit ions of posit ive

ATNPV per well, it can be expected that royalty payments,lease bonuses, and lease rentals will absorb the major por-t i o n o f th e d i f fe re n ce b e twe e n p ro sp e c t i ve e xp e c te d

wellhead prices and costs.

$1 .42

+45

+4

–6

+6

–8

–46

–43


$2.00

+37

+37

+1 6

+42

+1 6

–28

–31

$2.50

+1 2 5

+ 6 6+ 3 4

+ 7 4+ 3 7 – 1 3 –21

$3.00

+162

+9 4

+5 3

+105

+5 8

+1

–11

is of special interest is the general pattern ofresults. As the wellhead price of gas increasesfrom $1.42 per Mcf to $2.00 per Mcf, it becomeseconomically feasible to produce shale gas fromsome of the medium- and lower-quality sites ofthe ga s-produc tive area. The pric e c hang e of$1.42 per Mcf to $2.00 per Mcf appears to have ag r e a t e r e f f e c t o n m a k i n g s h a l e l o c a t i o n seconomically feasible than does the change from$2.00 to $2.50 per Mcf, or a change from $2.50to $3.00 per Mcf.

For example, in table 8, under the most severetax assumptions, at an assumed price of $2.00 perMcf, the pattern of ATNPV results is such that thehigh-quality resource area is a prime candidatefor development, the medium-quality resourcearea is marginally attractive, and the best situa-t i o n i n t h e l o w e r - q u a l i t y r e s o u r c e a r e a i seconomically rewarding. At $2.50 per Mcf, bothsituations in the medium-quality area becomeeconomically attractive and the good locations inthe lower-quality area have a positive ATNPV.Because the areal extent of each of these gas-productive quality areas is not known, the actual

impact on potential production cannot be deter-mined.

It is instructive to compare table 8 with table11. Table 8 is the most severe tax case examined.Table 11 is the most l iberal (in terms of the




generosity with which income from gas produc-tion is treated) tax case examined. At $2.00 perMcf, two addit ional situations achieve posit iveATNPV values in table 11 which did not achievepositive ATNPV values in table 8. These are shotwells in the medium-quality resource area and

shot wells in the good area in the lower-qualityresource area. Note that the liberal tax treatmentdoes not increase the area of potential gas pro-duction, but does make shot wells economicallyfeasible in the medium- and lower-quality goodareas. A well head price of $2.50 per Mcf does notincrease the potentially productive area of theshale resource but it does increase the value ofthe wells and, like the $2.00 price, makes shotwells economically feasible. A wellhead price of$3.00 per Mcf under the most liberal tax treat-

ment makes shale gas production from all threelocalities in the gas-productive area economicallyfeasible.

A comparison of data in table 8 with that in ta-ble 9 shows that a 10-percent investment taxcredit would have little positive impact on shale

gas development. However, a comparison of datain table 8 with that in table 10 shows the positiveimpact of a 22-percent depletion allowance. At$1.42 per Mcf, in addition to increasing the valueof wells in the high-quality locations, a 22-per-cent depletion allowance makes hydrofracturedwells in the medium- and lower-quality goodareas economically feasible. Basically, the 22-per-cent depletion allowance has about the samepositive effect as a $.50 per Mcf increase inwellhead price.

Extent of the Economically Producible

As indicated in an earlier section, estimates ofthe natural gas in the Brown shale are subject togreat variability. The question involves not onlythe total resource present but also the portionthat can be economical ly produced. Unt i l theBrown shale resource of the Appalachian Basin ismore fully characterized, there will continue tobe great uncertainty in any attempt to estimatethe extent of the Appalachian Basin which mightsustain commercial development of shale gasproduction.

The ATNPV analyses indicate that under manyof the price and tax scenarios, drilling for andproducing shale gas from localities in the knownshale gas productive area is economically feasi-ble. However, it is unrealistic to assume that thecurrent gas-productive area is representative ofthe whole Appalachian Basin. A number ofgeneral observations about resource deposits arere levant . F i rst , the d ist r ibut ion of resourcedeposits in nature tend to be highly skewed, i.e.,

t here a re fewer very h igh-qua l i t y resourcedep osit s than med ium-qua lit y deposit s, andfewer medium-quality deposits than low-quality

deposits.19, 20 Sec ond ,

Area

the better-quality resourcestend to be developed f i rs t .21 There being nostrong e videnc e t o the c ontrary, OTA a ssumesthat these principles apply to gas-bearing shalesof the Appalachian Basin.

In a marginal resource base such as the Brownshale, the definition of “better-quality resource”includes, as a determinant, location relative to

existing production and pipelines. Until recently,the Brown shale have not b een a prima ry target o fdrilling except in the Big Sandy area. The currenta reas o f sha le deve lopment were in i t i a l l y

IYJ.W. McKie, “ Market Structure and Unce rtainty In Oil

and Gas Exploration, ” Qua rterly )ourna/ of Econom/cs, Vol.74, p p . 543-571, November, 1960.

20G. Kaufman, “Statistical Declslon and Related Tech-n iq u e s in O i l a n d Ga s E xp lo ra t io n , ’ P re n t i ce Ha l l ,Englewood Cliffs, N. J., 1973, and J. Altc hlson a nd J,A, C.Brown, “ The Lognormal Distribution, ” Cambridge university

Press, New York, N. Y., 1957.

ZIC. Kaufman, Y. Bulce r, and D. Kryt. “A Probabil is t icModel of Oil and Gas Discovery, ” Studies In CeOIOgy, VOI.

1, Amer ican Assoc ia t ion o f Petro leum Geologists , TUIM,

Okla, pp. 113-142, 1975.



.58 . Ch. VI—Eco nom ics of Brown Shale Ga s Prod uct ion

byproducts of other activity. While it might ap-pear that this fact would blunt the operation ofthe principle that the better prospects are drilledfirst, this is not the case. Even if the initialk now ledge o f B r own s ha le p r os pec ts wasdeveloped as a byproduct of other activity, thebetter Brown shale prospects (byproducts or not)are developed first. “Better” here, however, in-volves a strong element of location relative to ex-ist ing pipel ines. This is p a r t ic ular ly t rue forhistorical wellhead price levels. Evidence of thisis that much of the Brown shale production inWest Virginia is served by existing interstatepipelines.

All of this suggests that there may be otherareas which are geologically as promising as thethree localities examined here. These other areas,a l though more remote re la t ive to ex is t ingpipelines, may become economically feasible at

the $2.00 to $3.00 per Mcf price levels examinedin the sensitivity analysis reported herein.

There might b e a te mp tation to extrap olate theproduction results from the three sample loca-tions in the currently productive, area directly tothe entire Appalachian Basin. Results of such anextrapolation are not likely to be valid primarilybecause:

q the existing wells are not located randomlyin the Appalachian Basin, but rather areclustered in a known producing area;

q t he gas - p r oduc t i v e a r ea s am p led ( 98 .6square miles) is less than 0.06 percent of the163,000-square-mile Appalachian Basin;

q the 490 sample wells are but a very small (5percent) portion of the 10,000 producingwells in the Appalachian Basin, and do notrepresent a random sample; and

q average product ion data f rom producingwells are biased because dry holes andplugged and abandoned wells are not in-cluded in the “average production. ”

OTA a ssumed that the produc tion po tential inthe currently producing area is much higher thanis characteristic of the Appalachian Basin as awhole.

Based on the following informa tion, OTA e sti-mates that about 10 percent of the 163,000-square-mi le extent of the Appalachian Basinmight be of high enough quality to produce shalegas economically at a price of $2.00 to $3.00 perMcf .

1.

2.

3.

Production History. —The wells which havea potential of producing more than 240 to300 Mcf of shale gas over a 15- to 20-yearperiod tend to be clustered in a few loca-tions in the Appa lac hian Basin. This typ e o fdis t r ibut ion of commerc ial ly product ivewel ls indicates that not a l l of the Ap-palachian Basin is composed of the sameresource quality. No doubt additional loca-tions exist which have commercial poten-tial, but it is unlikely that these areas willcompr ise a s ign i f icant por t ion o f the163,000-square-m i le ex tent o f the Ap-

palachian Basin.

Sha le Dep th. —The Brown shale outcrops atthe surface in central Ohio and is 12,000feet below the surface in northeastern Penn-sylvania. Because drilling and stimulationcosts increase with depth, commercial pro-duction of shale gas in the volumes encoun-tered in the best wells to date is generallylimited to depths less than 5,000 feet. Aconsiderable extent of the Brown shale ofthe Appalachian Basin is deeper than 5,000feet and is therefore unlikely to sustain com-

merc ial shale gas product ion under theeconomic conditions and technology con-sidered in this assessment.

Sha le Thic kne ss. —The total thickness of thegas-productive Brown shale sequence in theDevonian rocks varies from less than 100feet to more than 1,000 feet across the Ap-palachian Basin (figure 3). It is not generallyeconomical to stimulate Brown shale layerswhich are less than 100 feet in thicknessunless multiple layers in one well can betrea ted. The Brow n sha le resource in a sig-

nificant portion of the Appalachian Basinconsists of thin layers of Brown shale whichmay not be amenable to modern hydrofrac-ture techniques.



Ch. VI—Ec ono mic s of Brown Shale Gas Production q 59

4 Fra c tu res.—The fracture system (number, 5

length, openness, and direction of fracturesor joints) in the Brown shale is not uniforma c ross the A pp ala c hian Basin. The m uc h-fractured areas of the Brown shale tend tobe more gas-productive than the less-frac-tured areas. Extensive areas of the Ap-pa lachian Basin have lim i t ed f rac t u resystems and therefore are potentially poorerareas for shale gas production even withmodern st imulat ion techniques than themuch-fractured areas.

Dril l ing Expe r i ence . -D r i l l i ng and p ro -duction records of independent operators inthe Appalachian Basin have reflected vasta r e a s w h e r e s h a l e g a s p r o d u c t i o n i suneconomic unless new stimulation tech-niques can more than double shale gas pro-duction rates without significant increasesin cost. Poor shale gas product ion ex-perience over extensive areas probably is aresult of a combination of the circumstancesoutlined above.

An Estimate of Readily Recoverable

The Ap pa lachian Basin has an area l extent ofabout 163,000 square miles. If 10 percent of thisarea is of high enough quality to be economically

attractive for shale gas production at prices of$2.00 to $3.00 per Mcf, it provides a potentialproduction area of 16,300 square miles. (Thepresent gas-productive area is less than 5 percentof the 163,000-square-mile area. ) With a spacingof 150 ac res pe r we ll, this area would supp ort ap -proximately 69,000 wells. Production data pre-sented in table 4 show that wells economicallyfeasible at $2.00 per Mcf wil l produce approx-imately 240 million cubic feet of shale gas perwell over a 15-year period, and about 290 millioncubic feet per wel l over 20 years.22 R e a d i l yrecoverab le reserves were de te rmined by

multiplying the number of potential wells by theaverage production per well as follows:

15-year readily recoverable reserve

69,000 wells x 240 MMcf/well = 16.6 Tcf

20-year readily recoverable reserve

69,000 wells x 290 MMcf/well = 20.0 Tcf

If the entire undeveloped gas-productive areawere a medium-quality resource and all wellswere shot treated, the 15-year readily recovera-ble reserve would be 9 Tcf; use of hydrofractur-ing rather than shot treatment would increase this

z~ln a Smllar analysis for a smaller producing area, IJlti -

mate recoverable reserves were used at levels o t 300, 350,

and 400 MMcf per well, P. J, Brown, “Energy From Shale—ALittle Used Natural Resource. ” Natural Gas From Unconven-

t ional Geo / o g / c Sou rc es, National Aca dem y of Science s,J 976.

figure to 15 Tcf.reserves would

Reserves

The 20-year read ily recove rab leap proxima te 11 and 19 Tc f,

respectively. If 10 percent of the 163,000-square-

mile (1 6,300 square miles) gas-productive areawere all high-quality resource and all wells wereshot treated, the readily recoverable reservewould b e abo ut 17 Tc f over a 15-year period andabout 20 Tcf over a 20-year period. Assumingthat hydrofracturing results in a 50-percent in-crease in shale gas production (as is suggested byproduction data in table 4), 69,000 hydrofrac-tured wells on high-quality Brown shale sitesmight p roduc e 26 Tc f of g as ove r a 15-yea rpe riod, and ap proxima tely 30 Tc f ove r a 20-yearperiod.

It is highly unlikely that all of the undeveloped

gas-productive Brown shale resource will be highquality, and also unlikely that all of it will bemedium or low quality. For this reason, a 15 to 25Tc t estimate of read ily reco verable shale g asreserves appears justified until the Brown shaleresource base is more thoroughly characterized.This range clearly indicates that the Brown shaledo in fac t have a pot ential for making a signific antcontribution to the U.S. natural gas supply.

Because of the great uncertainty in the qualitydistribution of the shale resource, no attempt wasmade to undertake price elasticity studies in this

assessme nt. The imp ac t of a spe c ific pric e c hang eon shale gas production will be impossible toassess accurately until extensive resource charac-terization studies are completed, This will requirea large amount of drilling throughout the region.



60 • Ch VI—Ec ono mic s of Brow n Shale Ga s Produc t ion

Some estimates of the total amount of gas-in-place in the Brown shale range in the hundreds ofTc f. 23 However, such estimates of the resourcebase should be distinguished from estimates ofreadily recoverable reserves, which represent thefraction of the total resource whose recovery isfeasible under reasonable assumptions about

c osts, taxes, and g eo logic forma tions. OTA’ s 15to 25 Tcf estimate of readily recoverable reservesis consistent with a total resource estimate ofhundreds of Tcf b ec ause of the fa ct that unde rpresent technology the average shale wel lrecovers only 3 to 8 percent of the calculated gasin place .24

General Observations and Findings

i t appears that under p lausib le economic,geologic, and technological assumptions, theBrown shale of the Appalachian Basin contain asmuch as 15 to 25 Tcf of readily25 r e c o v e r a b l ena tural ga s. This reserve w ould be prod uc ible in

the first 15 to 20 years of the production profile

of typical reservoirs. Because one of the charac-

teristics of Brown shale gas production is a slow

flow rate over a very long period of time, ulti-

mate recoverable reserves over the life of pro-duction would be greater. This 15 to 25 Tcf esti-mate critically depends on the price and costassumptions used, the total extent of the Brownshale resource, and the distributions of resourcequality.

The price assumptions ($2.00 to $3.00 perMcf) realistically reflect the current opportunityvalue of additions to the U.S. natural gas supplyand are consistent with general market condi-tions for both interstate and intrastate sales. Esti-

mates of drilling, well completion, stimulation,and production costs are based on actual operat-ing experience.

The est imate of 15 to 25 Tcf of readi lyrecoverable reserves is based on the assumptionthat about 10 percent of the 163,000-square-mileAppalachian Basin has Brown shale of h ighenough quality to permit the production of shalegas economically at prices of $2.00 to $3.00 perMcf.

~ ~~a~ura/ Ga s From Unc onve ntiona l Ge olog ic Sourc es, p .

113, National Academy of Sciences, 1976.

~qlbid., p , 86 .

Z5’’Readily recoverable reserves” is not a category in

e i ther the Amer ican Gas Assoc ia t ion or Un i ted S ta tesGeological Survey nomenclature. In the present context,“readily recoverable reserves” are resources which can beconverted to proved reserves and actually produced in a 15-

to 20-year time frame.

From table 12 one sees the important role thatthe Brown shale could play in national natural gassupply, If annual production were at 1.0 Tcf,26 t heregion would match some of the larger gas-pro-ducing States and make up almost 5 percent ofcurrent national production.

Table 12

Estimated Gross Production of Natural Gasof the five Largest Producing States, 1976

I Gross ProductionState (Tcf/ annum)

Texas ., ., . . . . . . . . . . . . . .

Louisiana . . . . . . . . . . . . . . .Oklahoma . . . . . . . . . . . . . .New Mexico . . . . . . . . . . . .Kansas . . . . . . . . . . . . . . . . .

Tot a l U.S. . . . . . . . . . .

7.77.1

1. 8

1.2

0.8

20.9

Source: Gas Facts 1976, American Gas Association (1977), p. 24.

T h e e s t i m a t e s p r e s e n t e d i n t h i s repo r t a rebased on the analysis of 490 producing wells inthree gas-productive localities. These 490 wellswere drilled by a large number of operators withd i f fe ren t f i nanc ia l s i t ua t ions and techn ica lc ap ab ilities. There are some d ata ava ilab le from asmaller number of wells drilled by a single opera-tor .27 If these single-operator data are, in fact,representative of the potential of the Brown shaleof the Appalachian Plateaus, this resource might

~bThe 1.() Tc f is a central estimate based on the 15 to 25

Tc f range; therefore, one should keep in mind the variabilityassociated with the point estimate.~TK.1. Brooks, R.M. Forrest, and W.1. Morse, 1974. “Gas

Reserves in the Devoniain Shale in the Appalachian Basinthe Op era t ing Terr ito ry o f the Co lumb ia G as System . ”

(Mimeographed Report in the files of Columbia Gas SystemService Corporation, Columbus, Ohio.)



Ch. VI—Ec ono mic s of Brown Shale Ga s Production q 6 1

ac co unt for more tha n 1.0 Tc f pe r yea r of ad di-tional U.S. supply in the next 20 years. This largerproduction could result from either or both (1)greater average productivity per well, or (2) alarger resource base which would permi t agreater number of wells of average productivity.However, even under an optimal combination ofcircumstances (1 5-percent higher average pro-duction per well and a 50-percent increase in theareal extent of the quality shale resource), onlyab out 30 to 35 Tc f o f read ily reco verab le reserveswould be producible over 15 to 20 years. For thereasons ci ted previously, however, OTA con-s iders such an op t ima l combina t ion to beunlikely.

The 1.0 Tcf figure is a judgmental estimatebased on the facts that: (1) much potential shalegas production is likelyarea without immediate

nections, and (2) a largequ i red t o gene ra t e IS

recoverable reserves.

to spread over a wideaccess to pipeline con-

amount of drilling is re-to 25 Tc f of rea d i ly

Based on product ion data f rom the threelocalities analyzed, creation of 15 to 25 Tcf ofreadily recoverable reserves will require drilling69,000 wells. In 1975, 38,498 wells were drilledin the United States.28 If drilling 69,000 wells withthe Appalachian Basin Brown shale as the targetpay zone were spread over 20 years, this numberof new wells would average 3,450 wells per year.This drilling alone would represent a 9-percent in-

crease in drilling activity over the total U.S. 1976level. The U.S. drilling industry has shown con-s i d e r a b l e a b i l i t y t o r e s p o n d t o i n c r e a s e deconomic incentives. Between 1971 and 1975,total wells drilled increased by 45 percent (9 per-cent per year), from 26,532 to 38,498. Between197I and 1975, total rotary-drilling rigs in opera-tion increased by 70 percent (15 percent peryear), from 976 to 1,660. Because Brown shaleproduct ion is re lat ive ly wel l - in tensive, andbecause it is likely to be scattered over extensiveareas, it is prudent to assume that shale gasdevelopment wi l l proceed at a gradual pace,

possibly spreading the required dri l l ing effortover 15 to 20 years.

~~Dri I I i ng sta ti s t i e s a r e f r o m t h e 0/ / a n d Ga s /ourna / ,

Review and Forecast Issues, 1972 and 1976, pp. 91 and 114.

The fac t tha t po tential shale ga s prod uc tion islikely to be scattered over extensive areas con-tributes to a relatively slow pace of developmentbecause of the requirement that natural gas beshipped by pipel ines. This suggests that theeconomical ly feasib le expansion of the gas-pipeline network required to serve new shaledevelopment and production will be on an incre-mental basis. This in turn suggests that locationrelative to potential pipeline connections (in ad-dition to geologic promise) will continue to beanimportant determinant of the economic qualityof shale drilling prospects. As a result, gradualdevelopment is a prudent assumption.

The magnitude of the required dri l l ing effortdo es, howeve r, have a n imp ortant a spe c t. Thedrilling of 3,450 wells per year in the AppalachianBasin would be a significant addition to total U.S.drilling activity. There has been an impressive

record of technological progress in the U.S. drill-ing industry.29 This progress has been associatedwith deeper target horizons in the gulf coast andthe Southwest. It is possible that a drilling effortof the magnitude required to develop Brownshale gas resources would sufficiently focus theattention of the drilling industry so that substan-tial technological progress in reducing shale drill-ing costs and improved del iverabi l i ty wouldresult. A comparison of table 6 with tables 8th rough 11 ind ica tes the po ten t ia l o f suchprogress to extend the margin of economicfeasibil i ty for Brown shale development. The

possibility of improved drilling and completiontechnology is not included in the 15 to 25 Tcfestimate.

The c om pa rison o f ta ble 6 with ta bles 8through 11 is relevant to any technological ad-vance which improves the ratio of productivecapacity to investment cost, All Brown shale gasproduct ion i s a r t i f i c ia l l y s t imu la ted th rougheither hydrofracturing or shooting.30 An improve-ment in stimulation technology would have aneffect similar to that of an improvement in drill-ing tec hnolog y. The p ossibility of a n improve -

ment in stimulation technology is not included inthe 15 to 25 Tcf estimate.

%ee FM. Fisher, o p c It.IO It i s n o t e w o r t h y t h a t hydrofracturlng i t s e l f w a s

developed in response to the post World War II Increase in

U.S. crude oil prices,



62 . Ch. VI—Economics of Brown Shale Gas Production

If improvements in drilling or stimulation tech-nology are developed by drilling or well-servicecontractors who can patent the techniques, it ispossible that the social ly opt imal amount ofe f f o r t t o deve l op such t echno l ogy w i l l beforthcoming. But it is likely that much drilling,well stimulation, and production will be done by

operators who do not have a very large share oftotal shale production. In addition, many techni-cal improvements may not be readily patentable.Under these circumstances, the Congress maywish to consider the desirability of some publiclysupported research and development act ivi tydirected toward improvements in shale drillingand stimulation technology.

The possible effect of either (1) dramaticallyimproved technology, or (2) improvements ineconomic incentives beyond those examinedhere, must be considered with caution. This is

because of the likelihood that the developmenteffort which such possibilities would encouragewou ld be work ing aga ins t an increas ing lymarginal resource base. If economic incentiveswere to be twice as good as those associatedwith current tax treatment and wellhead prices of$2.00 to $3.00 per Mcf; or, alternatively, if drill-ing and stimulation technology were to improveso that these operations cost only half as much asthey do now, it is unlikely that twice as great aquantity of reserves would become economicallyfeasible. This is because the additional develop-ment efforts which such economic or technologi-

cal improvements would induce would be press-ing further and further into the margin of poorerand poorer sites and geologic prospects. In addi-t ion, because poorer resource qual i ty in theBrown shale is very much associated with slowerf low rates per unit of ul t imately recoverablereserves, the contribution to yearly output wouldbe apt to increase relatively less than the increasein reserves. For example, on a purely illustrativebasis, if a doubling of economic incentives ortechnical productivity were to result in a 50-per-

cent increase in ultimate recovery, average out-put in the first 20 years might increase by only 25percent.

The 15 to 25 Tcf of readi ly recoverablereserves and approximately 1.0 Tcf of yearly pro-duction reported here are based on the following

assumptions:

q

q

q

q

q

It is

no significant changes in real drilling, wellstimulation, or production costs;

t he economi c and p roduc t i on cha rac -terist ics of the three local i t ies analyzedrepresent the more promising sources ofnatural gas from the Brown shale;

wellhead prices for natural gas in the $2.00to $3.00 per Mcf range;

continuation of current tax treatment of in-come from natural gas production; and

approximately 10 percent of total now un-developed Appalachian Basin Brown shaleresource is of high enough quality to permitcommercial development.

a well-known axiom that there is no sureproof of gas or oil production potential otherthan the dri l lbit. It is possible that all of theundri l led resource potent ial of the Devonianshale has economic and product ion charac-teristics similar to those of the bad situations inthe lower-quality resource area. In this case, there

would be no incremental Brown shale gas pro-duction which would be economically feasible,at wellhead prices in the range of $2.00 to $2.50pe r Mc f . T h i s appea rs un l i ke l y , g i ven t hegeographic dispersion of Brown shale resources.There ap pe ars to b e no p rac tica l wa y short ofcreating the economic incentives necessary to in-duce an extensive dri l l ing effort, to ascertainwhether the Appalachian Basin shale might ac-tually contribute more, or less, than 5 percent ofthe total U.S. natural gas supply.



Table 13Typical Well Costs (1976 Constant Dollars)

High-Quality Brown Shale Well

Cottageville Area, Jackson County, W.Va.

Total Depth-4,300 feet

Completion Method-Shooting 450 feet of Gross Pay Section

Intangible Costs:Title work . . . . . . . . . . . . . . . . . . .Stake Iocation. . . . . . . . . . . . . . . .

Drilling permit & bond . . . . . . . . .Other legal expenses. ... . . . . . .Right-of-way expenses. . . . . . . . . .

Road & location costs . . . . . . .Hauling (all except cement) . . . . .Well logs (open hole) . . . . . . . . . .

Centralizers & float equipment . .Cementing surface & conductor .Shooting 450 feet . . . . . . . . . . . .

Geologic & engineering service . .Drilling 4,200 feet @ $8/ft . . . . . .Rig charges . . . . . . . . . . . . . . . . . . .

Install 2,000 feet flow line . . . . . .Reclaim road & location ., . . . . . .

S u b t o t a l . . . .

Contingency (6% of intangibles) .

Management overhead (1 50/0 total

well costs excluding contingen-cy) . . . . . . . . . . . . . . . . . .

Total Intangibles ., . . . . . .Tangible Costs:Conductor casing:

30 feet of 13“@$l4.45/ft . .500 feet of 9-5/8 ’’@$9 .36/ft, .2,500 fee t o f 7“ @$5.96/f t. . . .

Christmas tree. . . . . . . . . . . . . . .Valves & fittings. . . . . . . . . . . . . . .

2,000’ of 2-3/8” flow line@$.91/ ft. . . . . . . . . . . . . . . . . . .

Total Tangibles . . . . . . . . . .

Total Well Costs . . . . . . . .

Producing

Wel l

$ 30 0

30 0

35 0

200

10 0

2,000

3,500

3,000

1,800

3,500

5,000

2,800

34,400

2,600

1,730

2,000

63,580

3,815

13,115

80,510

4 30

4,700

14,900

1,000

1,000

1,820

23,850

$104,360

Dry

Hole

$ 30030 0

35 0

20 0 —

2,000

3,500

3,000

1,800

3,500 —

1,40034,400

—

—

2,000

52,750

3,165

10,917

66,832

43 0

4,700

14,900 —

—

—

20,030

186,862

Ch VI—Economics of Brown Shale Gas Produc ation 63


Medium-Quality Brown Shale Well

Blue Creek Area, Kanawha Co., W.Va.

Tota l Dep th-500 feetCompletion Method-Hydrofracture (1,000 bbl)

Intangible Costs:Title work . . . . . . . . . . . . . . ., . .

Stake location. . . . . . . . . . . . . . . . .

Well permit & bond . . . . . . . . . . .

Other legal expenses. , . . . . . . . . .Right-of-way expenses, . . . . . . . . .

Road & location costs . . . . . . . . .

Hauling (all except cement &4-1/2” casing) . . . . . . . . . . .

Hauling 4-1 /2” casing & line . . . .

Well logs (open hole) . . . . . . . . . .Centralizers & float equipment . .

Cementing conductor & surface .Cementing 4-1 /2” casing . . . . . .Hydrofrac-1,000 bbl, 60,000# sd,

75,000 cu. ft. nitrogen . . . . . . . .

Perforate & CBL log . . . . . . . . . . .Tool and equipm ent rental . . . . . .

Frac tank rental (5 x 250-bbl@$l50/tank) . . . . . . . . . . . . . .

Pump or haul water @40/bbl x 1,000 . . . . . . . . . . . . . . . .

Completion rig 140 hrs@ $55/hr .Geologic & engineering service . .Drilling 5,000 feet @ $9/ft . . . . . .

Rig charges . . . . . . . . . . . . . . . . . . .Install 2,000 feet flow line . . . . . .

Reclaim road & location . . . . . . .Subtotal . . . . . . . . . . . . . .

Contingency (6°/ 0 of intangibles) .Management overhead (1 50/0 of

total well costs excluding con-tingencies) . . . . . . . . . . . . . . . . .

Total Intangibles . . . . . . . . .

Tangible Costs:Conductor casing:

30 feet of 13“ @ $14.45/ft, . .500 feet of 9-5/8” @ $9.36/ft2,000 feet of 7“ @ $5.96/ft . .

Production casing: 5000 feet of4-1 /2” @ $3.12/ft . . . . .

Christmas tree. . . . . . . . . . . . . . . . .

Valves & fittings. . . . . . . . . . . . . . .2,000 feet of 2-3/8” flow line

@$.91/ ’ ft . . . . . . . . . . . . . . . . . . . .Separator & tank ., . . . . . . . .Valves & fittings, drips . . . . . . . .

Total Tangibles . . . . . . . . .

To ta l L ine & Wel l Costs

ProducingWel l

$ 30 0

35 0

35 0

20 0

10 0

4,000

3,500

520

3,200

1,800

3,500

3,300

9,020,

2,000

500

75 0

400

7,700

3,000

45,000

2,600

1,730

2,00095,820

5,749

20,176

121,745

430

4,700

11,900

15,600

1,000

1,000

1,820

2,000

2 35

38,685

$160,430

DryHole

$ 300

35 0

35 0

20 0 —

4,000

3,500 —

3,200

1,800

.3,500 —

—

—

—

—

— —

5 00

45,000 —

—

2,00064,700

3,882

12,260

80,842

43 0

4,700

11,900

— —

—

— —

—

17,030

97,872



64 Ž Ch. VI—Economics of Brown Shale Ga s Produc tion

Table15Typical Well Costs (1976 Constant Dollars)

Medium-Quality Brown Shale Well

Blue Creek Area, Kanawha Co., W.Va.

Tot al Dep th-5,000 fee tCompletion Method-Shooting 1,000 feet of Gross Pay Sec-


Lower-Quality Brown Shale Well

Hazard Area, Perry County, Eastern Kentucky


Completion Method-Hydrofracture (1,000 bbl)

tion

Intangible Costs:Title work . . . . . . . . . . . . . . . . . . . .Stake location. . . . . . . . . . . . . . . . .Drilling permit & bond . . . . . . . . .Other legal expenses. . . . . . . . . . .Right-of-way expenses. . . . . . . . . .Road & location costs . . . . . . . . . .

Hauling (all except cement) . . . . .Well logs (open hole) . . . . . . . . . .

Centralizers & float equipment . .Cementing conductor & surface .

Shooting 1,000 feet . . . . . . . . . . . .Geologic & engineering service . .Drilling 5,000 feet @$9/ft. . . . . . .

Rig charges . . . . . . . . . . . . . . . . . . .Install 2,000 feet of flow line. . . .Reclaim road & location . . . . . . . .

Subtotal. . . . . . . . . . . . . .

Contingency (6°/ 0 of intangibles) .

Management overhead (1 5°/ 0 of

total well costs excluding con-tingency). . . . . . . . . . . . . . . . . . . .

Total Intangibles . . . . . . . . .

Tangibla Costs:Conductor casing:

30 feet o f 13“ @ $14.45/ft . . .

500 feet of 9-5/8 ’’@$9 .36/ft. .2,000 feet of 7“@$5.96/ft. . . .

Christmas tree. . . . . . . . . . . . . . . . .Valves & fittings. . . . . . . . . . . . . . .

2 ,000 fee t o f 2 -3 /8 ” f low l ine @

$.91/ft . . . . . . . . . . . . . . . . . . . . . .Total Tangibles . . . . . . . . . .

Total Well & Line Costs . . .

Producing

Wel l

$ 30 0

350 I350

20 0

100

4,000

3,500

1,500

1,000

3,500

10,0003,000

45,000

2,600

1,730

2,000

79,150

4,749

15,000

98.899

430

4,70011,900

1,000

1,000

1,820

20,850

$119,749

Dry

Hole

$ 3003 50

3 50

2 00 —

4,000

3,500

1,500

1,000

3,500

—1,500

45,000 — —

2,000

63,200

3,792

12 ,034

79.026

430

4,70011,900

—

—

—

17.030

$96,056

Intangible Costs:Title work ., . . . . . . . . . . . . . . ., . .Stake location. . . . . . . . . . . . . . . . .Well permit & bond . . . . . . . . . . .

Other legal expenses. . . . . . . . . . .Right-of -way,. . . . . . . . . . . . . . . . . .

Road & location costs . . . . . . . . . .Hauling (except 4-1 /2” cement) .Hauling 4-1 /2” & line pipe. ... , .Well logs (open hole) . . . . . . . . . .Centralizers & float equipment . .Cementing conductor & surface .

Cementing 4-1 /2” casing . . . . . . .Hydrofrac-1,000 bbl, 60,000# sd,

75,000 cu. ft. nitrogen ... , . . . . .Perforate & CBL log . . . . . . . . . . . .Too l and e quip me nt renta l . . . . . .Pump or haul 1,000 bbl water. . .

F r a c t a n k r e n t a l ( 5 x 2 5 0 -bbl@$150) . . . . . . . . . . . . . . . . . .

Completion rig 140 hrs @ $55/hrInstall 2,000 feet of flow line. . . .

Geologic & engineering service . .Drilling 3,900 feet @$ 10/ft. . . . . .

Rig charges . . . . . . . . . . . . . . . . . . .Reclaim road & location . . . . . . . .

Subtotal. . . . . . . . . . . . . .

Contingency (6°/ 0 of intangibles) .Management overhead (1 5°/ 0 of

total well & line costs excludingcontingencies. . . . . . . . . . . . . . .

Total Intangibles . . . . . . . . .Tangible Costs:Conductor casing:

30 feet of 13“@$l4.45/ft . . . .

500 feet of 9-5/8 ’’@$9 .36/ft. .

3,100 fee t o f 7“ @$5.96/ ft. ., .Production casing: 3,900 feet of

4-1/2’ ’ @$3.l2/ ft . . . . . . . . . . . . .

Christmas tree. . . . . . . . . . . . . . . . .Valves & fittings, drips . . . . . . . . .

Separator & tank . . . . . . . . . . . . . .

Total Tangibles ... , . . . . . .

Total Well & Line Costs . . .

ProducingWell ,

$ 4 00

35 0

350

3 00

100

5,500

3,500

500

3,000

1,800

3,500

3,000

9,020

2,000

500

400

750

7,700

1,730

2,800

39,000

2,600

2,000

90,800

5,448

19,621

115,869

430

4,700

18,476

12,168

1,000

1,235

2,000

40,009

$155,878

Dry

Hole

$ 40 0

35 0

35 0

30 0 —

5,500

3,500 —

3,000

1,800

3,500

—

— —

—

—

—

—

—

1,400

39,000 —

2,000

61,100

3,666

12,705

77,471

430

4,700

18,476

—

—

—

—

23,606

$101,077





Lower-Quality Brown Shale Well

Hazard Area, Perry County, Eastern Kentucky


Completion Method-Shooting 450 feet of Gross Pay Section

Intangible Costs:Title work . . . . . . . . . . . . . . . . . .

Well permit & bond . . . . . . . . . . .Stake location. . . . . . . . . . . . . . . .Other legal expenses. . . . . . . . . . .Right-of-way . . . . . . . . . . . . . . . . . .Road & location costs . . . . . . . . .Hauling (except 4-1/2” casing &

cement). . . . . . . . . . . . . . .Well logs (open hole) . . . . . . . . . .

Centra l izers & f loa t equ ipmentCementing conductor & surface .

Shooting 450 feet . . . . . . . . . . . . .install 2,000 feet of flow line. . . .

Geologic & engineering serviceDrilling 3,900 fee t @$10/ft . . . . . .

Rig charges . . . . . . . . . . . . . . . . . .Reclaim road & location . . . . . . . .

Subtotal. . . . . . . . . . . . . .

Contingency (6% of intangibles) .Management overhead (1 50/0 of

total well & line costs excludingcontingencies) . . . . . . . . . . . .

Total Intangibles . . . . . . . . .Tangible Costs:Conductor casing:

30 feet of 13“@$l4.45/ft ., . .

500 feet of 9-5/8 ’’@$9 .36/ft. .3,100 feet of 7“@$5.96/ft. . . .

Christmas tree. . . . . . . . . . . . . . . . .Valves & fittings. . . . . . . . . . . . . . .

2 ,0 0 0 fe e t o f 2 -3 /8 ” f l o w l i n e@$.91/ ft . . . . . . . . . . . . . . . . . . . .

Total Tangibles . . . . . . . . . .

Total Well & Line Costs .

ProducingWel l

$ 40 0

35 0

35 0

30 0

10 0

5,500

3,500

3,000

1,800

3,500

5,0001,730

2,800

39,000

5,200

2,000

74,530

4,472

15,293

94,295

430

4,70018,476

1,000

1,000

1,820

27,426

$121,721

DryHole

$ 40 0

35 0

35 0

30 0 —

5,500

3,500

3,000

1,800

3,500

— —

1,400

39,000 —

2,000

61,100

3,666

12,705

77.471

43 0

4,70018,476

—

—

—

23,606

$101,077



VII. Barriers toBrown Shale Gas Production



VIl. Barriers toBrown Shale Gas Production

Obstacles to gas production from the Brown reservoir analysis techniques, driIIingshale are of two types: (1) barriers to immediate method ology, and co mp let ion pract ices. Whilede velop me nt of Brown shale reserves using these two aspects are treated separately in thisavailable drilling and completion techniques; and assessment, they are interrelated.(2) barriers to future production using improved

Obstacles to Development Using Available Technology

The m a jor ba rrier to inc reasing prod uc t ionusing available technology is the present con-trolled level of the interstate wellhead price of

gas. Gas product ion is economical ly feasible(greater than a 10-percent rate of return on in-vestment) only in the very high-quality areas ofBrown shale under current controlled price levels.Current development of the Brown shale is,therefore, limited to seeking out the very high-quality areas of Brown shale. With this restriction,a s ign i f i can t expans ion o f exp lo ra t ion anddevelopment activity in the Appalachian Basin isunlikely.

Following a recent increase in prices for newinterstate gas ($.52 per Mcf to $1.42 per Mcf),

there was a noticeable increase in drilling activityin the higher-qual i ty Brown shale of the Ap-palachian Basin.

Development of the Brown shale using availa-ble technology is also hindered by problemsassoc i a t ed w i t h h i gh l oca l d r i l l i ng cos t s ,d i f f i cu l t i e s i n l ease acqu i s i t i on , and t i t l eclearance. Drilling costs are substantially higherin southwestern West Virginia and eastern Ken-tucky because of the rugged terrain and poorroads, w h i c h m a k e e q u i p m e n t m o v e m e n tdifficult and expensive and increase the costs of

installing gas gathering and distribution systems.Areas with multiple minable coal seams re-

quire additional casing for each coal seam which,in turn, increases drilling rates per foot and tangi-ble expenses for casing for wells that penetrate

coal seams. The problems associated with drillingthrough minable coal seams will increase in thefuture due to the increased value of coal, andmore intensive explorat ion and developmentefforts by coal operators. Additionally, leasingand purchasing of coal mining rights by investorsfar removed from the site will result in delays inacquiring approval to drill through coal seams. Togain approval to drill through a coal seam, a platof the drill-site location must be submitted to theoperator holding the mining rights on the poten-tial drill-site property. If a drill site is approved bythe coal operator, that operator must agree toleave a pillar of coal around the drill hole to pro-vide an unbroken well bore through the seam.This procedure results in a loss of recoverable

coal. If, in areas of low- to medium-quality Brownshale, minable coal seams are numerous and

thick, the amount of coal left as pillars around the

well bore may have a greater value than the po-

tential gas from the proposed well and, therefore,

the coal operator will refuse to permit a gas wellto be drilled through the coal seams.

Brown shale areas are notorious for propertyand title problems. For example, in eastern Ken-tucky tax maps are nonexistent, courthouserecords are poor, and many of the mountain peo-ple living on the land have no knowledge of themineral ownership. problems in leasing and title

clearance in such areas can be time consumingand expensive. I t is not unusual to invest 6months to 1 year to locate owners and clear thet i t le for a potent ial dri l l ing si te on the Ap-palachian Plateaus.

69



70 . Ch. VII—Barriers to Brown Shale Gas Production

Environmental constraints do not pose seriousdeterrents to Brown shale development. Fluidsproduced from wells must be contained by on-site tanks to prevent stream pollution, all pits arerequired to be closed, disturbed land must bereseeded, and surface erosion from access roadsand the d r i l l i ng s i te must be con t ro l led bydrainage ditches. Recent legislation imposingstringent controls on potential stream pollutionand land degradation has increased drilling costsby $2,000 to $5,000 per well. This increase inwell cost is minimal, representing between 1 and4 percent of the cost of drilling and completing atypical gas well in the Brown shale.

Shortages of drilling and well-completion rigscould pose a temporary constraint on develop-ment of gas production from the Brown shale ofthe Appalachian Basin, Currently, there are about

73 rigs in the Appalachian area capable of drillingshale wells. ’ After a well is dri l led, rigs areneeded to st imulate and clean out the shalewells; about 65 to 75 such completion rigs areavailable in the Appalachian Basin.2 A moderndrilling rig can drill about two shale wells perweek, and stimulation rigs can complete aboutone shale well every 10 days. Under favorableconditions, the 73 drillings rigs could drill about7,600 holes per year and about 2,400 to 2,700 ofthese could be brought into production by the 65to 75 completion rigs. Therefore, even if all of therigs currently in the Appalachian Basin were usedexclusively to drill and complete new shale wells,it would not be possible to develop enough wells(69,000) to produce 1.0 Tcf per year of shale gasover the next 20 years, Favorable economicscould possibly overcome the dri l l ing and com-pletion rig constraint over a 3 to 5 year period.

Obstacles to Advances in Shale Gas Technology

An important barrier to advances in Brownshale gas production technology is the lack ofresource characterization. Even though approx-imately 10,000 wells produce gas from the Brownshale, very few quantitative data are available toadequately characterize the resource. Only a fewof the 10,000 wells in the Brown shale have coresamples available for examination, and those that

do come from a relatively small portion of the163,000-square-mile extent of the AppalachianBasin. Until the Brown shale resource is adequate-ly characterized, focusing on specific targets fortechnology development is very difficult. Lack ofspecific research targets could result in haphazardhit-and-miss and trial-and-error experimentationwith only limited chance of significant success inthe near future. Detailed chemical-petrophysicaldata are needed for the Brown shale before sig-nificant progress can be expected in technologycapable of releasing gas from those shales. Addi-tionally, basic research is required to determine

the manner in which gas is held by the Brownshale, i.e., is it only in the fractures, in the pores,adsorbed on the shale surface, or contained with-in the matrix porosity?

Characterization of the Brown shale involvingshale petrography, core analysis work, geochemi-cal research, and other pertinent data collectionby different people in separate localit ies andagencies must be carefully coordinated to beeffective.

Resource characterization is the initial and

most pressing step for advancing technology forthe purpose of increasing gas production fromthe Brown shale. Without an intimate knowledgeof what the resource is, it is almost impossible to

l lnformation from: S.6. Plammer, Hughes Tools NE Area

Regional Manager Pittsburgh, Pa; Frank Whyte, Dri l l ing

Manager, Delta Drilling Company, Indiana, Pa; Jame s Willitt,

Vice President, S.W. jack Dril l ing Company, Buckhannon,

W.Va.; John Will iam, Vice President, Union Dri l l ing Co.,Buckhannon, W.Va.; John Foster, Production Eng, Columbia

Ca s T r a n s . C o , C h a r l e s t o n , W.Va.; j ames R a y , R a yResources, Inc, Charleston, W.Va,; Roy Hancock, PetroleumIn format ion , Char les ton , W.Va.; Jame s Burgin, PresidentGaspro Inc., Cambridge, Ohio; and Don Cayton, President,Central Well Service, Parkersburg, W.Va.Zbid.



Ch. V1l—Ba rriers to Brown Sha le Ga s Production . 71

program research efforts in st imulat ion tech- has been impossible to evaluate the effectivenessnology, logging methods, or any of the various of various techniques because basic reservoirsatellite research needs dependent on reservoir characteristics have not been adequately docu-characterization. mented. I f more than 15 to 25 Tcf of gas is to

become available from the Brown shale, -researchIn the past, efforts to produce gas from the

Brown sha le have used every conce ivab leprograms must be aggressive, coordinated, andinnovative.

stimulation method known to man; however, it



EncouragVIII. Policy Options

.- ,.

Toion



VIII. Policy Options ToEncourage Shale Gas Production

Policy options available to encourage produc- q tax policies,tion of gas from the Brown shale fall into fourgeneric categories. These categories are:

q research a nd d evelopme nt funding, and

information collection and d insemination.. price incentives,

q

Price Policies

Brown shale natural gas resource developmentis sensitive to price. The price of Brown shale gassold in interstate commerce is currently restricted

by Federal Power Commission (FPC) ceiling pricereg ulation. There a re three b asic p rice strateg ieswith respect to shale gas which could be pur-sued. These are:

q

q

q

A

exempt shale gas from FPC price control orestablish higher prices for gas from theBrown shale;

deregulate the wellhead price of all newnatural gas supplies; or

take no ac tion,

policy which permits higher prices or ex-empts Brown shale gas from FPC control wouldbe analogous to a proposed policy to permit afree-market price for oil produced with enhancedrecovery methods. The qualification for gas fromBrown shale might be based on (1) geologic iden-tification of the Brown shale as the source of gas,(2) regional specif ication, (3) production ratelimitations, or some combination of these fac-tors.

Brown shale gas product ion is of ten com-mingled with production from other geologiczones. Therefore, a precise identification of gas

production from the Brown shale could be ex-tremely difficult.

Because simi lar appearing gas-product iveshales extend throughout many portions of theUnited States in addit ion to the Appalachian

Basin, a regional specification restricted to theAppalachian Plateaus might omi t substant ia lshale gas resource potential. Production rate

limitations for eligibility for exemption from priceregulation might be more manageable, and alsowould apply to gas production from tight forma-tions in other parts of the country. Definition andadministration of a multitiered pricing system forgas f rom the Brown sha le p robab ly wou ldbecome arbitrary, complex, and cumbersome.

Deregulation of the wellhead price of all newgas supplies would include prospective additionsto the U.S. natural gas supply from the Brownshale of the Appalachian Basin. Such a strategywould create price incentives in the range ($2.00

to $3.00 per Mcf) on which the analyses pre-sented in this report are based. Such price incen-tives might provide the stimulus necessary for anextensive testing of the economic feasibil i ty ofBrown shale gas production. An expansion indrilling efforts could result in approximately 1.0Tcf per year of gas from the Brown shale of theAppalachian Basin.

For Congress to take no action on prices wouldmean that existing prices would be the only in-centive to encourage gas production from Brownshale. Current maximum interstate gas prices en-courage gas product ion f rom only the h igh-quality Brown shale areas. Therefore, continua-tion of present gas-pricing policy could result inforegoing substantial additions to the U.S. naturalgas supply which may be available from theBrown shale of the Appalachian Basin.

75



76 . Ch. VIII—Policy Op tions To Enco urage Shale Ga s Produc tion

Tax Policies

The tax policies available to Congress to en-courage Brown shale gas production include:

q

q

q

q

restoration of the general percentage deple-

tion allowances;

definition of Brown shale gas production asenhanced recovery so as to maintain thedepletion allowance for small producers;

retention of expensing of intangible drillingcosts as a tax option; and

creation of an investment tax credit for theBrown shale.

The analysis reported here indicates that a 10-percent investment tax credit has little effect onshale ga s production. Areas of lower resourcequality did not become economically feasible for

shale gas production when a 10-percent invest-m en t t ax c r ed i t was i nc o r po r a ted i n to t heanalysis. However, the addition of a 22-percentdepletion allowance increased the after-tax net-present value of shale wells and made shot-treated wells economically feasible in shales oflower quality. Basically, a 22-percent depletionallowance has about the same positive effect onthe economics of shale gas production as a $.50per Mcf increase in the wellhead price of shalegas.

Research and Development

There are several areas in which research anddevelopment with special relevance to the Brownshale of the Appalachian Basin might be fruitfullypursued. These include:

. defining resource characteristics;

q development of dr i l l ing techniques andequipment; and

q improvement of stimulation techniques.

Even though about 10,000 wells produce gasfrom the Brown shale of the Appalachian Basin,few quantitative data are available to character-ize adequately the resource potential of the163,000-square-mile Appalachian Plateaus. Untilthe Brown shale resource is adequately charac-terized, specific targets for technology develop-ment are not possible. A systematic, coordinatedinventory of the Brown shale should be one ofthe first steps in determining the gas potential ofthe Brown shale sequence.

The mo st c omm on te chnique s used to c harac -terize the Brown shale are those developed fortraditional oil and gas reservoirs. Development ofs pec ia l d r i l l i ng t ec hn iques and equ ipm en tspecifically for use in the Brown shale could ex-pedite the development of i ts gas potential.Because of the importance of well stimulation inthe production of gas from the Brown shale, im-provement in the effectiveness and reduction incost of stimulation techniques could make gas

production more economically attractive. Priceincentives can be expected to induce some pri-vate activity in these research and developmentareas. However, because much dri l l ing, wells t imulat ion, and product ion wi l l be done byoperators who do not control large shares ofBrown shale resources, it is unlikely that thoseoperators will invest large amounts in aggressiveresea rc h and d eve lopm ent p rog ram s. Therefore,it appears prudent to commit public funds forresearch and deve lopment ac t iv i ty d i rec tedspecifically toward improvements in shale drill-ing and stimulation technology.



Ch, VIIl—Policy O pt ions To Encou rage Shale Ga s Prod uc tion . 77

Information Collection and Dissemination

Although the Devonian shale is a geologic se-quence distributed over a wide geographic area,only a small portion of it, the Brown shale, ap-pe ars to ha ve p otential as a co mme rcial sourc e of

gas. If the gas potential of the Brown shale is ex-ploited, a large number of independent operatorsare likely to be drilling a large number of wells inmany di f ferent locat ions on the AppalachianPlateaus. Under these conditions, particularly inthe early years of the development effort, i tmight be desirable to provide public funding forthe collection, coordination, and disseminationof information and analyses detailing the resultsof a c tua l op erat ing expe rienc es. This ac tivity

should be undertaken by a creditable publicgroup so that the results are available to thepublic and private sectors alike, The informationcollection and dissemination efforts might in-

c lude publ ic funding for conferences whereresearch and development results and improvedd r i l l i ng and s t i mu l a t i on t echno l og i es a rereported. If the Brown shale has a potential toprod uce 1.0 Tc f of gas pe r yea r, and ec onomic in-centives are provided, it is likely that private en-terprise wil l assume necessary research anddevelopment efforts within a comparatively shortperiod of time.

Conclusion

There are a numb er of polic y op tions ava ilab le Mcf. Research and development programs whichwhich could encourage production of gas from characterize the Brown shale resource, decreasethe Brown shale of the Appalachian Basin. A sig- the cost of drilling and stimulation of wells, andnif ica nt and substantial policy op tion is to pe rmit increase the gas produc tion from wells could in-free market prices for gas from Brown shale se- crease the economic attractiveness of producingquences. Restoration of the 22-percent depletion gas from the Brown shale of the Appalachianallowance would have the same effect as increas- Basin.ing the wellhead price of shale gas by $.50 per



IX. Summary and Conclusions



IX. Summary and Conclusions

Dark-colored shales of Devonian age (termedBrown shale) which are present beneath the Ap-palachian Basin are known to conta in largeamounts of natural gas. Gas production from theshale is greatest from much-fractured zones; ini-t i a l p roduc t i on f r om Brown sha l e we l l s i srelat ively high, but whi le the rate decreasessteadily the life of production is normally 15 to50 years. Estimates of the total amount of gas inthe Brown shale of the Appalachian Basin rangeup to ma ny hundreds of Tc f.

It appears that gas production from Brownshale can be increased using existing technology.The recoverable gas potential of the Brown shaledepends on the (1) wellhead price and produc-tion costs and; (2) extent of the commerciallyproducible Brown shale resource. It is likely thatthe Brown shale of the Appalachian Basin con-tains as much as 15 to 25 Tcf of gas readilyrecoverable in 15 to 20 years at wellhead pricesof $2.00 to $3.00 per Mcf. Production of gas fromthe Brown shale will come from many wells pro-ducing at low rates scattered over extensive

areas, thus resulting in a relatively slow pace ofdevelopment, Construction of pipeline gatheringsystems coupled with the need to drill a greatnumber of wells in the Appalachian Basin willretard the rapid development of Brown shale gaseven if adequate economic incentives are madeavailable. It is prudent to expect that develop-ment o f a 1.0 Tcf per year produc tion p otentialwill require at least 15 to 20 years. Improvementsin d r i l l i ng and s t imu la t ion techno logy andeconomic incentives could reduce the timelag.

Available policies which could encourage the

development of shale gas production include:

1.

2.

3.

Price or tax incent ives for gas from theBrown shale;

Expanded research and development todefine the resource and, develop more effi-cient dri l l ing and stimulation technology;and,

Collection and dissemination of results ofresearch, development, and actual f ieldoperating experience.

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