economics and the 1995 national assessment of united states oil

Economics and the 1995 National Assessment of United States Oil and Gas Resources

By Emil D. Attanasi

A summary of the economic component of the 1995 National Assessmentof United States Oil and Gas Resources for onshore and State offshoreareas of the United States

U.S. GEOLOGICAL SURVEY CIRCULAR 1145

UNITED STATES GOVERNMENT PRINTING OFFICE, WASHINGTON : 1998

Free on application to U.S. Geological Survey, Information ServicesBox 25286, Federal Center

Denver, CO 80225

Any use of trade, product, or firm names in this publication is for descriptive purposes only anddoes not imply endorsement by the U.S. Government

Library of Congress Cataloging-in-Publication Data

U.S. DEPARTMENT OF THE INTERIOR

BRUCE BABBITT, Secretary

U.S. GEOLOGICAL SURVEY

Mark Shaefer, Acting Director

Attanasi, E.D.MMEconomics and the 1995 national assessment of United States oil and Mgas resources / by Emil D. AttanasiMMMM p.Mcm.—(U.S. Geological Survey circularM ;M1145)MM”A summary of the economic component of the 1995 NationalMAssessement of of United States Oil and Gas Resources for onshoreMand State offshore areas of the United States.”MMM Includes bibliographical references.MMM 1. Petroleum reserves—United States. 2. Natural gas reserves—MUnited States. 3. Petroleum engineering—United States—Costs.M4. Petroleum industry and trade—United States. I. Title. MII. Series.MTN872.A5A86 1997

338.2’78’0973—dc21 97–37291 CIP

III

CONTENTS

Summary......................................................................................................................... 1Introduction .................................................................................................................... 1Resources Assessed ........................................................................................................ 2Methodology................................................................................................................... 3

Undiscovered Conventional Oil and Gas Fields..................................................... 4Unconventional Resources ..................................................................................... 6Inferred Reserves.................................................................................................... 7

Assumptions ................................................................................................................... 7General Assumptions.............................................................................................. 7Specific Assumptions: Undiscovered Conventional Oil and Gas Plays................. 8Specific Assumptions Continuous-Type and Coal-Bed Gas Plays ........................ 8

Incremental Costs ........................................................................................................... 8Overview: Undiscovered Conventional Fields and Continuous-Type Accumulations........................................................................... 8Undiscovered Conventional Oil and Gas ............................................................... 13

Characteristics of Technically Recoverable Resources.................................. 13Incremental Costs of Oil and Gas from Undiscovered ConventionalOil and Gas Fields .......................................................................................... 14

Continuous-Type Accumulations and Coal-Bed Gas............................................. 15Characteristics of Technically Recoverable Resources.................................. 15Incremental Costs of Oil and Gas from Continuous-Type andCoal-Bed Gas Accumulations ........................................................................ 15

Inferred Reserve Estimates ............................................................................................. 17Field Growth: Origins and Qualifications .............................................................. 17Field Growth Through 2015: A Comparative Analysis ......................................... 18

Implications and Limitations .......................................................................................... 19References Cited............................................................................................................. 21Glossary of Selected Terms............................................................................................ 22Appendix A—Tables of Province-Level Conventional Undiscovered Resource Estimates......................................................................................................... 24Appendix B—Tables Showing Regions, Provinces, Province Numbers, and Play Numbers for Continuous-Type Plays and Coal-Bed Gas Plays ............................. 30Appendix C—Methodology ........................................................................................... 33

Undiscovered Conventional Oil and Gas Resources.............................................. 33Continuous-Type Accumulations in Sandstone, Shales, Chalks, and Coal............ 34

Appendix D—Assessed Technically Recoverable Resources, Proved Reserves, and Past Production ............................................................................................................... 35

FIGURES

[Figure number preceded by letter indicates figure is in Appendix with same letter designation]

1. Graphs showing incremental costs of finding, developing, and producing crude oil from undiscovered conventional oil fields and continuous-type oil accumulations and incremental costs of finding, developing, and producing undiscovered conventional non-associated gas in gas fields andunconventional non-associated gas (in continuous-type accumulations and coal-bed gas) in onshore and State offshore areas of the United States ................................................................................. 2

2. Charts showing estimated shares, as of January 1994, of crude oil and non-associated gas that could beavailable for production during the next 2 decades (through 2015)................................................................. 3

CONTENTSIV

3–5. Maps showing:3. Petroleum regions and provinces in onshore and State offshore areas in the

conterminous United States and Alaska ................................................................................................. 44. Assessed continuous-type gas plays and oil plays from the USGS 1995 National Assessment for

which the predominant reservoir rock is sandstone, siltstone, shale, or chalk ........................................ 55. Assessed coal-bed gas plays from the USGS 1995 National Assessment .............................................. 6

6. Schematic drawing of geologic setting of a continuous-type accumulation and discrete conventional accumulations in a structural trap and a stratigraphic trap................................................................................ 6

7–13. Graphs showing:7. Estimates of quantities of crude oil, by petroleum region, from undiscovered conventional oil fields

and from assessed continuous-type oil accumulations having incremental costs of$18 and $30 per barrel............................................................................................................................. 10

8. Estimates of quantities of non-associated gas, by petroleum region, from undiscovered conventionalgas fields and from assessed continuous-type gas accumulations having incremental costs of$2 and $3.34 per thousand cubic feet ...................................................................................................... 10

9. Incremental cost of finding, developing, and producing crude oil from undiscovered conventionaloil fields and crude oil from continuous-type oil accumulations in U.S. petroleum regions .................. 11

10. Incremental cost of finding, developing, and producing non-associated gas from undiscoveredconventional gas fields and unconventional gas from assessed continuous-type gas accumulations and coal-bed gas in U.S. petroleum regions.............................................................. 12

11. Field-size distribution of ultimate (discovered plus undiscovered) and undiscovered conventionaloil and gas fields in onshore and State offshore areas of the conterminous United States...................... 14

12. Estimates, as of January 1994, of proved crude oil reserves, projected crude oil reserve additions through 2015 for oil fields discovered before 1992, and the combined estimates of crude oil in undiscovered conventional oil fields and from continuous-type oil accumulations having incremental costs of $30 per barrel ......................................................................................................... 19

13. Estimates, as of January 1994, of proved non-associated gas reserves, projected non-associated gas reserve additions through 2015 for gas fields discovered before 1992, and the combined estimates ofnon-associated gas in undiscovered conventional gas fields and from continuous-typegas accumulations having incremental costs of $3.34 per thousand cubic feet ...................................... 19

D-1–D-2. Graphs showing:D-1. Estimates, as of January 1994, by petroleum region, of discovered crude oil (i.e., cumulative production

and proved reserves), inferred reserves, and the combined mean estimates of assessed technicallyrecoverable undeveloped crude oil in undiscovered conventional oil fields and crude oil incontinuous-type oil accumulations .......................................................................................................... 35

D-2. Estimates, as of January 1994, by petroleum region, of discovered gas (i.e., cumulative productionand proved reserves), inferred reserves, and the combined mean estimates of assessed technicallyrecoverable undeveloped gas in undiscovered conventional oil and gas fields, gas incontinuous-type oil and gas accumulations, and coal-bed gas ................................................................ 35

TABLES

[Table number preceded by letter indicates table is in Appendix with same letter designation]

1. Estimated economic oil, gas, and natural gas liquids in undiscovered conventional oil and gas fields and in unconventional oil and gas accumulations in onshore and State offshore areas of the United States as ofJanuary 1994...................................................................................................................................................... 9

2. Estimates of technically recoverable and economic oil, gas, and natural gas liquids in continuous-typeoil and gas accumulations in onshore areas of the conterminous United States as of January 1994................ 16

3. Estimates of technically recoverable and economic gas in assessed coal beds in onshore areas of theconterminous United States as of January 1994................................................................................................ 17

A-1. Mean values of undiscovered technically recoverable conventional oil, gas, and natural gas liquids inonshore and State offshore areas of U.S. oil and gas fields as of January 1994 ............................................... 24

VCONTENTS

A-2. Oil, gas, and natural gas liquids in undiscovered conventional oil and gas fields in onshore and State offshore areas of the United States with incremental costs of $18 per barrel oil and $2 per thousand cubic feet gas as of January 1994........................................................................................... 25

A-3. Oil, gas, and natural gas liquids in undiscovered conventional oil and gas fields in onshore and Stateoffshore areas of the United States with incremental costs of $30 per barrel oil and $3.34 per thousand cubic feet gas as of January 1994...................................................................................... 27

A-4. Conventional field-size class definitions .......................................................................................................... 29B-1. List of petroleum provinces of onshore and State offshore areas in the conterminous United States.............. 30B-2. Provinces, play numbers, and play names for continuous-type gas plays assessed in the 1995 USGS

National Oil and Gas Assessment..................................................................................................................... 31B-3. Provinces, play numbers, and play names for continuous-type oil plays assessed in the 1995 USGS

National Oil and Gas Assessment..................................................................................................................... 31B-4. Provinces, play numbers, and play names for coal-bed gas plays assessed in the 1995 USGS

National Oil and Gas Assessment..................................................................................................................... 32

1

Economics and the 1995 National Assessment of United States Oil and Gas Resources

By Emil D. Attanasi

SUMMARY

This report summarizes the economic component of theU.S. Geological Survey’s 1995 National Assessment of Oiland Gas Resources for U.S. onshore areas and State waters.This area accounts for 80 percent of U.S. hydrocarbonproduction and 85 percent of U.S. proved reserves. The Min-erals Management Service (1996) has released a parallelstudy for Federal offshore areas. Estimates are as of January1994. The economic evaluation uses mean values of thetechnically recoverable resources assessed by geologists.

Figures 1A and 1B summarize for all U.S. onshore andState offshore areas aggregate incremental costs of finding,developing, and producing oil and non-associated gas fromundiscovered conventional oil and gas fields and fromselected unconventional sources. In the figures, unconven-tional economic resources are depicted as the differencebetween the conventional undiscovered curve and the curvedesignated as total. At $18 per barrel and $2 per thousandcubic feet (mcf), 9.2 billion barrels oil (BBO), 15.8 trillioncubic feet associated gas, and 1.1 billion barrels (BBL) nat-ural gas liquids (NGL) from undiscovered conventional oilfields, and 61.7 trillion cubic feet of gas (TCFG) and 2.0BBL NGL from undiscovered conventional gas fields can befound, developed, and produced. At $30 per barrel and $3.34per mcf, estimates of economic oil increase by 85 percentand total conventional economic gas increases by 57 percent.In both cases, associated gas accounts for about one-fifth oftotal economic undiscovered conventional gas. Similarly,NGL from associated and non-associated gas accounts for 20to 25 percent of total liquid hydrocarbons (crude oil plusNGL). Regionally, Alaska and the Gulf Coast account for 40percent of the economic oil in future discoveries, and theGulf Coast accounts for 60 percent of the economic gas infuture gas discoveries.

Crude oil in unconventional (continuous-type) accumu-lations add less than 6 percent to economic crude oil, even at$30 per barrel. Unconventional gas accumulations add 35.6TCFG to economic gas resources at $2 per mcf, and, at $3.34per mcf, 72.1 TCFG is added. Total economic gas resources(undiscovered conventional and unconventional) availableat $2 per mcf are 113.4 TCFG and at $3.34 are 196.3 TCFG.Provinces of the Colorado Plateau Region and the Eastern

Region have the highest concentrations of economic uncon-ventional gas and are in strategic locations to supply WestCoast markets and the industrial Northeast.

Figures 2A and 2B show sources and amounts of oil andnon-associated gas that could be available for productionduring the next 2 decades through 2015. Figure 2A repre-sents 69 BBO, and figure 2B represents 381 TCFG. Amountsinclude economic quantities of undiscovered conventionaland unconventional oil and non-associated gas evaluated at$30 per barrel and $3.34 per mcf, proved reserves as of Jan-uary 1994, and projections of field growth (inferredreserves) from 1994 through 2015 for pre-1992 discoveries.In figure 2A, projected quantities of oil from field growthaccount for 44 percent, proved reserves 29 percent, andundiscovered conventional and unconventional oil accountfor 27 percent. For non-associated gas (figure 2B), fieldgrowth accounts for 26 percent, proved reserves 30 percent,undiscovered conventional gas 25 percent, and unconven-tional gas accumulations (continuous-type and coal-bed gas)19 percent. Even with these projected amounts from inferredreserves and real price increases to $30 per barrel ($3.34 permcf) that yield additional oil and gas from undiscovered con-ventional and unconventional accumulations, it will be pos-sible but very difficult to sustain production at levelscomparable to the 1994 level over this period withoutimprovements in exploration and production technology.

INTRODUCTION

The 1995 National Assessment of United States Oil andGas Resources by the U.S. Geological Survey (USGS) (U.S.Geological Survey National Oil and Gas Resource Assess-ment Team, 1995) posits a set of scientifically based esti-mates of recoverable quantities of oil and gas that could beadded to the measured (proved) reserves of the UnitedStates. The geologic component of the 1995 NationalAssessment (U.S. Geological Survey National Oil and GasResource Assessment Team, 1995) developed estimates ofhydrocarbons that are producible using current technologybut without reference to economic profitability, whereas theeconomic component (this report) presents costs of finding,developing, and producing the assessed resources. In partic-

ECONOMICS AND THE 1995 NATIONAL ASSESSMENT OF UNITED STATES OIL AND GAS RESOURCES2

0

10

20

30

40

50

DO

LLA

RS

PE

R B

AR

RE

L

0 5 10 15 20 25

BILLIONS OF BARRELS OF OILA

0

1

2

3

4

5

6

DO

LLA

RS

PE

R T

HO

US

AN

D C

UB

IC F

EE

T

0 50 100 150 200 250

TRILLIONS OF CUBIC FEET OF GASB

ular, this report presents estimates of costs of transformingtechnically recoverable resources assessed in undiscoveredconventional fields and unconventional oil and gas accumu-lations into producible proved reserves. The incrementalcost functions show costs as a function of the cumulativequantity of resources transformed. Costs include finding,development, production, and also a return on investment.The computation of the incremental cost functions requiresthat the “full cost” of the marginal unit of resources added toproducible reserves equal well-head price.1

Incremental cost functions show the quantity ofresources that the industry is capable of adding to proved

reserves or cumulative production rather than predictingwhat the industry will actually supply. Actual additions andmarket supply are the outcome of optimizations of numeroussupplier decisions over geographically diverse regions andhydrocarbon sources that assure market supply at lowestcosts. This report provides a base line to compare costs whenexamining alternative supply regions, alternative sources foroil and gas, and alternative technologies. Coal-bed gas andconventional gas, for example, have different productiontechnologies that characterize discovery, development, andproduction costs. These differences are taken into accountwhen economic quantities of the resources are put on a com-mon basis by incremental cost functions.

The economic analysis ties costs to the volumes ofhydrocarbons that are fully identified and where wells andproduction facilities are installed with the anticipation thatactual production will repay all operating costs, includingtaxes, all investment expenditures, and provide an after-taxrate of return of at least 12 percent on the investment. Thisspecification, which is equivalent to proved reserves, nar-rows the volume of hydrocarbons to a well-defined produc-ibility standard. Individual wells are physically limited by theamount of hydrocarbons that can be accessed at any giventime, and no more than 10 to 15 percent of the proved reservesof individual fields can be extracted annually without riskingreservoir damage and reducing ultimate field recovery. The“proven reserves” standard limits annual production to anamount well below absolute resource levels.

RESOURCES ASSESSED

Geologists assessed the numbers and size distribution ofundiscovered conventional oil and gas plays. They alsoassessed technically recoverable unconventional resources incontinuous-type oil and gas plays and coal-bed gas plays.Projections of future additions to proved reserves of discov-ered conventional fields (inferred reserves) were preparedusing statistical extrapolations of historical trends. Commod-ities assessed were crude oil, natural gas (associated and non-associated), and natural gas liquids from associated and non-associated gas. All gas quantities are expressed as dry gas,that is, gas that has been stripped of natural gas liquids. Gasdissolved in geopressured brines, oil in tar deposits, and oilshales are excluded from the analysis. Gas from low-perme-ability “tight” sandstone reservoirs, oil and gas from shalereservoirs, and coal-bed gas were specifically assessed.

The commercial value of a new conventional discoveryor a continuous-type accumulation depends on whether it is

1These functions are often referred to in the popular literature as mar-ginal cost or price-supply functions. However, they differ from the econo-mist’s marginal cost or supply functions in that resource quantities are notexpressed in terms of rate of resource supply, that is, the number of barrelsper year, but rather in terms of cumulative barrels added to reserves orproduction.

Figure 1. A, Incremental costs, in dollars per barrel, of finding, de-veloping, and producing crude oil from undiscovered conventionaloil fields and continuous-type oil accumulations in onshore andState offshore areas of the United States. Solid line represents un-discovered conventional oil, and dashed line represents total of un-discovered conventional oil and oil in continuous-type accum-ulations. B, Incremental costs, in dollars per thousand cubic feet, offinding, developing, and producing undiscovered conventional non-associated gas in gas fields and unconventional non-associated gas(in continuous-type accumulations and coal-bed gas) in onshore andState offshore areas of the United States. Solid line represents un-discovered conventional non-associated gas, and dashed line repre-sents total of undiscovered conventional and unconventional gas.

3METHODOLOGY

oil or gas, its depth, location, well production profiles, andby-products. Technology and costs associated with oil fieldsdiffer from gas fields so it was important to classify the sourceof hydrocarbons by type. Fields and accumulations having atleast 20,000 cubic feet of gas per barrel of crude oil were clas-sified as gas fields and accumulations; otherwise, they wereclassified as oil fields.

For the 1995 National Assessment, undiscovered tech-nically recoverable resources are defined as estimated quan-tities of resources hypothesized to exist on the basis ofgeologic knowledge, data on past discoveries, or the-ory—these resources are contained in undiscovered accumu-lations outside of known fields. Estimated resource quantitiesare producible using current recovery technology but withoutreference to economic viability. Posited undiscovered accu-mulation sizes include all components of field growth thatmight occur during field development and production. Con-ventional accumulations are oil and gas accumulations thatare typically bounded by a downdip water contact and from

which oil, gas, and natural gas liquids (NGL) can be extractedusing traditional development and production practices.Accumulations assessed by geologists as occurring outside ofexisting fields were considered for the purposes of the eco-nomic analysis as separate and discrete new fields. Onshoreand State offshore areas of the United States were dividedinto eight regions and further subdivided onto a total of 71provinces (fig. 3). For the 71 provinces, about 460 conven-tional plays were assessed. The economic analysis evaluatedundiscovered conventional resources at the province level.

Inferred reserves, more commonly called field growth,include resources expected to be added to reserves of discov-ered fields as a consequence of their extension, periodicrevisions of their reserve estimates, improvements in recov-ery technology, and additions of new pools. Forecasts ofreserve growth apply only to conventional fields discoveredbefore 1992 .

Continuous-type accumulations are hydrocarbon accu-mulations that are pervasive throughout a large area or regionand that do not owe their existence to the buoyancy of hydro-carbons in water as conventional accumulations do. Coal-bedgas was assessed separately, although it is also a form of con-tinuous-type accumulation. Figures 4A, 4B and 5 show loca-tions of assessed continuous-type gas and oil accumulationsand coal-bed gas accumulations, respectively. The figuresshow the areal extent of these accumulations to be regionalin nature and cover hundreds of square miles. Continuous-type accumulations have no downdip hydrocarbon-watercontact, whereas conventional accumulations have well-defined hydrocarbon-water contacts and seals that hold thehydrocarbons. Figure 6 shows conventional structural andstratigraphic deposits in relation to a “basin center” continu-ous-type accumulation. A dominant characteristic of the res-ervoir rock of a continuous-type accumulation is that it iseverywhere oil or gas charged. Other geologic characteristicsinclude positioning of the accumulation downdip from water-saturated rocks, low reservoir permeability, abnormal (highor low) pressures, and close association of the reservoir withsource rocks from which hydrocarbons were generated.These accumulations are contained in sandstone, siltstone,shale, chalk, or coal, but their areal extent and heterogeneityremain uncertain. Large portions remain undrilled. Conven-tional play assessment methods that typically rely on histor-ical discovery size distributions are not applicable. Newgeologic and economic assessment methods were devised forassessing technically and commercially recoverable oil andgas from continuous-type plays. Economic evaluations wereprepared at the play level.

METHODOLOGY

More detailed descriptions of methodologies applied toassessing the technically recoverable and economic undis-covered conventional resources and unconventional

Proved reserves (29.40 %)

Continuous accumulations (1.59 %)

Undiscovered (25.35 %) Mconventional

Growth through 2015 (43.66 %)

A

Proved reserves (29.63 %)

Coal-bed gas (7.06 %)Continuous (11.87 %)Maccumulations

Undiscovered (25.17 %)Mconventional

Growth through 2015 (26.27 %)

B

Figure 2. A, Estimated shares, as of January 1994, of crude oil thatcould be available for production during the next 2 decades(through 2015). Sources consist of proved crude oil reserves, pro-jected crude oil reserve additions through 2015 for fields discov-ered before 1992, estimates of economic crude oil in undiscoveredconventional oil fields, and economic crude oil from continuous-type oil accumulations. Estimates of economic oil assumed incre-mental costs of $30 per barrel. Total crude oil represented is 69 bil-lion barrels. B, Estimated shares, as of January 1994, of non-associated gas that could be available for production during the next2 decades (through 2015). Sources consist of proved non-associatedgas reserves, projected non-associated gas reserve additionsthrough 2015 for fields discovered before 1992, estimates of eco-nomic non-associated gas in undiscovered conventional gas fields,economic gas in continuous-type gas accumulations, and economiccoal-bed gas. Estimates of economic gas assumed incremental costsof $3.34 per thousand cubic feet. Total quantity of non-associatedgas represented is 381 trillion cubic feet.


PACIFIC COAST

COLORADO PLATEAU AND BASIN AND RANGE

ROCKY MOUNTAINS AND

NORTHERN GREAT PLAINSMIDCONTINENT

GULF COAST

WEST TEXASAND

EASTERN NEW MEXICO

EASTERN

50

70

4

5

186

7

10

9

8

11

12

13

14

15

16

17

19

27 28

24

21

25

37

29

34

35

20

36

22

26

44 45

47

48

58

43

41

39

33

31

53

32

38

40

2342

59

61

55

46

54

51

52

56

57

60

62

49

64

63

66 67

68

71 72

69

65

0 500 MILES

0 500 KILOMETERSA

Trans-AlaskaPipeline

PrudhoeBay

Valdez

Northern Alaska

Central Alaska

Southern Alaska200 MI0

0 300 KM

B

resources are provided in Appendix C. Complete explana-tions are provided in a series of USGS Open-File Reportsreferenced in those sections. Estimation of inferred reserves(field growth) is described in detail in Root and others (1996).

UNDISCOVERED CONVENTIONAL OIL AND GAS FIELDS

The geologic assessment posited undiscovered conven-tional oil and gas field size-frequency distributions fromwhich quantities of oil, associated gas, associated gas liq-uids, non-associated gas, and non-associated gas liquidswere computed. The incremental cost functions were pre-pared at the province level using the expected or mean valueof the assessed size-frequency distributions of undiscoveredaccumulations grouped by 5,000-ft depth interval. The sizefrequency distributions of new discoveries (by field type anddepth) were projected for successive increments of wildcatwells using a set of finding-rate functions and the geologicassessment. A standard application of discounted cash flow(DCF) analysis determined commercial developability ofnewly discovered fields. The net after-tax cash flow con-sisted of revenues from the production of oil and (or) gas lessthe operating costs, investment costs in the year incurred,and all taxes. All new discoveries of a particular size and

Figure 3. A, Petroleum regions and provinces in onshore and Stateoffshore areas in the conterminous United States. Heavy lines areregion boundaries; lighter lines are province boundaries. B, Petro-leum provinces of onshore and State offshore areas of Alaska. Re-gions and provinces are listed by name and number in table B-1,Appendix B.

5METHODOLOGY

503

3740, 3741, 3742,3743,3744

28122812

2810, 2811

2007, 2010

3906

202020182016

2015

2205,2209,2211

4923

6733, 6734,6735

3113

6407

6604

6728,6729,6730

6741

6740

6320

6319

6742

Play and number4923

0 500 MILES

0 500 KILOMETERS

A

Figure 4. Assessed continuous-type plays from the USGS 1995 National Assessment for which the predominant reservoir rock is sandstone,siltstone, shale, or chalk. A, gas plays; B, oil plays. Tables B-2 and B-3, Appendix B, list provinces and play names associated with play numbers.

3904

3920,3921

2804

2103

4748

4749

4747

2009

2208

3110

3112

3111

Play and number3904

0 500 MILES

0 500 KILOMETERS

B


depth class are assumed to be developed and added to pro-ducible reserves if the representative field is found to becommercially developable, that is, if it has an after-tax netpresent value greater than zero. The discount rate includedthe cost of capital and the industry’s required return.

Finding-rate functions predicted, for each increment ofwildcat drilling, a distribution of oil and gas discoveries.For successive discovery distributions, average discoveriesbecame smaller and (or) were found in deeper horizons,resulting in increasing finding costs. Increments of 50

wildcat wells (or 20 wildcat wells for State offshore areas)are assumed to be drilled until the exploration cost associ-ated with the wildcat well increment is equal to or greaterthan the after-tax net present value of the commerciallydeveloped fields discovered by that increment of wildcatwells. For each increment of wildcat drilling, the allocationor targeting of wildcat wells to specific depth intervals max-imized the after-tax net present value of the oil and gas dis-covered. As prices/incremental costs are allowed toincrease, additional increments of wildcat wells are eco-nomic to drill and the marginal economic field sizedeclines—this adds more commercially developable fields.Both effects add to producible reserves. The basis for theestimates of recoverable undiscovered petroleum as a func-tion of well-head price is that incremental units of explora-tion, development, and production effort will not take placeunless the revenues expected to be received from the even-tual production will cover the incremental costs, including anormal return on the incremental investment.

UNCONVENTIONAL RESOURCES

Geologic assessment of continuous-type plays andcoal-bed gas plays started with partitioning the postulatedplay area into equal-area cells. For continuous-type plays,cell spacing corresponded to the median drainage area of

6750

6751

6752

6553

65526550

6553

5650

6050

6450

22522253

2250 4150

4152

3350

3351

33503755

2052

2050

2051

2053

20562055

20572054

Stacked plays3750, 3751,3752,3753,3754,3755

450

451

452

6250

6251

4151

6551

EXPLANATION

Play and number4506250

0 500 MILES

0 500 KILOMETERS

Tens of miles (kilometers)

Discrete-type

Land surface

Continuous-typeaccumulation

Stratigraphicaccumulation

Structuralaccumulation

Figure 5. Assessed coal-bed gas plays from the USGS 1995 National Assessment. Table B-4, Appendix B, lists province and play namesand numbers.

Figure 6. Geologic setting of a continuous-type accumulation anddiscrete conventional accumulations in a structural trap and a strati-graphic trap (U.S. Geological Survey National Oil and Gas Re-source Assessment Team, 1995)

7ASSUMPTIONS

production wells in the play, and, for coal-bed gas plays, itcorresponded to well spacing set by the State regulatorycommission. Geologists interpreted past drilling results andproduction records to assess technically recoverableresources in remaining untested cells. The assessmentresults are expressed in terms of a size-frequency distribu-tion of productive untested cells, where “cell size” heremeans quantity of hydrocarbons recovered. For calculatingincremental costs, the geologic play assessment results weretransformed into the expected size-frequency distribution ofuntested (productive) cells computed in 5,000-ft depth inter-vals. To determine the part of the cell frequency-size distri-bution of each 5,000-ft depth interval within a play that iscommercially developable, a cash-flow analysis was appliedto each cell-size category. After evaluation of all the cell-size classes within a specific depth interval, if the computedafter-tax net present value of the aggregate developable cellsis sufficient to cover the costs of drilling all cells, that is, thecost of exploration, then the aggregate resources in the com-mercially developable wells are added to reserves. Other-wise, drilling is not justified and resources are not added toreserves. Calculations were repeated assuming progres-sively higher well-head prices, and results were aggregatedfrom depth intervals to the play level and then to the prov-ince level to arrive at incremental cost functions.

INFERRED RESERVES

Inferred reserves (or field growth) are those resourcesin identified fields over and above current proved (mea-sured) reserves. They are expected to be added to discoveredconventional fields through extensions, revisions, improvedefficiency, and the addition of new pools or reservoirs. In thediscussion of field growth, estimates of field size (or knownfield recovery) are computed as the sum of past cumulativefield production and the field’s proved reserves. When fieldsare grouped by their year of discovery, the sum of the esti-mates of known recovery for each group tends to increasesystematically over time or years of observations. Thisobserved systematic nature of the “field-growth phenome-non” suggested a modeling approach that was statisticalrather than geologic in nature. To model this process, cumu-lative growth functions were specified and calibrated.

Cumulative field-growth functions show the estimatedfield size at age n, that is, n years after discovery, as a multipleof the field’s initially estimated size. Cumulative growthfunctions were calibrated using yearly field-size estimatesfrom 1977 through 1991 of conventional fields (grouped bydiscovery year from 1901 to 1991) in the lower 48 States.2

The cumulative growth function was then applied to the 1991field-size estimates to project future annual reserve additionsfor pre-1992 discoveries for the next 80 years. Alaska’s oilfield growth was calculated using the lower-48-States growthfunction (U.S. Geological Survey National Oil and Gas

Resource Assessment Team, 1995). The form of the cumu-lative growth function assumed that the annual rate of growthof older fields will not exceed that of younger fields and thatfields continued to grow for as long as 90 years after their dis-covery. Also implicit in the application of the calibratedcumulative growth function is the assumption that the rate oftechnological improvement and economic conditions occur-ring during the observation period will prevail in the future.

Studies designed to tie estimated costs of drilling activ-ity to historical field growth for a sample of fields failed toyield a credible costing scheme that could be applied to esti-mate costs of future reserve additions from inferred reserves.The 60 BBO and 322 TCFG (U.S. Geological SurveyNational Oil and Gas Resource Assessment Team, 1995) ofestimated future reserve additions are expected to occur overan 80-year period to 2071. Only a small fraction of theseresources can be added to reserves annually (Root and others,1996). For purposes of comparison with the economic undis-covered conventional and unconventional resources,regional field-growth projections prepared for the periodfrom 1994 to 2015 are presented and discussed.

ASSUMPTIONS

GENERAL ASSUMPTIONS

1. The economic analysis uses the mean or expectedvalue of the assessed hydrocarbons.

2. Industry exhibits rational behavior, so that invest-ment will not be undertaken unless the full operatingcosts, investment costs, and the cost of capital can berecovered.

3. Industry was assumed to use a 12 percent after-taxrate of return as a hurdle rate or required rate of returnto undertake new investment. The cash-flow analysiswas specific to individual projects and ignored mini-mum income taxes and tax preference items thatmight be important from a corporate accountingstance. Cost levels prevailing in 1993 were assumed.

4. Federal taxes are based on the 1986 Tax Reform Actand the 1993 revision. State tax rates are as of 1993.

5. Royalty payment to the resource owner is 12.5 per-cent of gross revenues for onshore areas and 16.67percent of State offshore areas.

2Data used for calibrating cumulative growth functions typically con-sist of short time-series (6 to 15 years) of estimates of ultimate field recov-eries for sets of fields grouped by discovery year. For example, with such aseries, the expected percent field growth for a field going from age 19 to 20is computed using estimates of known recovery for all those fields thatpassed from age 19 to 20 during the sample period. An entirely different setof fields may be used in calculating expected field growth from age 4 to age5. Field-size estimates were from the Energy Information Administration’sproprietary Oil and Gas Integrated Field File (OGIFF), issued in 1993.


6. Dry gas (gas without natural gas liquids) prices wereassumed to be two-thirds the price of oil whenexpressed on an equivalent energy basis. For exam-ple, if oil prices are $18 per barrel, the implied priceof gas would be $2 per mcf. This relationshipbetween oil and gas prices corresponds roughly to thehistorical average. The analysis also focused onprices between $18 per barrel ($2 per mcf) and $30per barrel ($3.34 per mcf). Also, the well-head priceof natural gas liquids is assumed to be three-fourthsthe per-barrel price of crude oil.

7. By-product revenues from associated gas and naturalgas liquids are credited in the economic evaluation tothe primary products of either crude oil or non-asso-ciated natural gas in the calculation of the incremen-tal cost functions.

SPECIFIC ASSUMPTIONS: UNDISCOVERED CONVENTIONAL

OIL AND GAS PLAYS

1. Economic evaluation of undiscovered conventionaloil and gas fields were generally prepared at the prov-ince level and based on the assessed field-size distri-bution of undiscovered fields within 5,000-ft depthintervals.

2. Exploration continues until the expected net presentvalue of the commercially developable resources dis-covered by the last increment of wildcat drilling isinsufficient to pay for that increment of wildcatdrilling.

3. Except in the Northern Alaska province, oil and gasprices used in the economic evaluation were well-head prices. For the Northern Alaska province, theoil price used in the economic evaluation was thelower-48-States-West-Coast price, rather than thewell-head price, so incremental costs include trans-portation from the field to the lower 48 States WestCoast. Oil produced in Northern Alaska is trans-ported through the Trans-Alaska Pipeline System(TAPS).

4. Because of the absence of a market for the gasresources of Northern Alaska, non-associated gasfields were not evaluated and a zero price wasattached to the extracted associated gas from oilfields.

5. The oil and gas resources of the Central Alaska prov-ince and of the Southern Alaska province outside theCook Inlet were not evaluated by the economic anal-ysis because these areas have very limited potentialand expected discovery sizes are insufficient to offsetcost barriers imposed by the hostile climate, primi-tive infrastructure, and remoteness from markets.

6. Technically recoverable resources assigned to LakeMichigan and Lake Erie were not evaluated. Theseresources amounted to 0.67 BBO and 3.0 TCFG.

SPECIFIC ASSUMPTIONS:CONTINUOUS-TYPE ANDCOAL-BED GAS PLAYS

1. Economic evaluations of continuous-type accumula-tions and coal-bed gas were prepared at the play leveland based on the expected cell-size frequency distri-bution of untested cells for each 5,000-ft depth inter-val over which the play extends.

2. Each untested cell requires a new well; recompletionsto the target plays of producing wells were not con-sidered.

3. Within continuous-type or coal-bed gas plays, it isassumed there is no trend in the discovery rate or wellproductivities as drilling progresses. In particular, itis assumed that within a play, operators cannot high-grade areas except by restricting drilling to specificdepth intervals. To the extent possible, so-calledsweet spots should be separate plays.

INCREMENTAL COSTS

OVERVIEW: UNDISCOVERED CONVENTIONAL FIELDS

AND CONTINUOUS-TYPE ACCUMULATIONS

Table 1 shows regional estimates of economic quanti-ties of oil, gas, and natural gas liquids in conventional undis-covered oil and gas fields, continuous-type accumulationsand coal-bed gas accumulations having incremental costs of$18 per barrel or $2 per mcf and $30 per barrel or $3.34 permcf. Figures 7 and 8 depict estimates of oil in oil fields andaccumulations and gas in gas fields and accumulations.Figures 9 and 10 show regional incremental cost functionsfor of oil and non-associated gas, respectively.

At $18 per barrel and $2 per mcf, 9.2 BBO, 15.8 TCFassociated gas, and 1.1 BBL NGL from undiscovered oilfields and 61.7 TCFG and 2.0 BBL NGL from undiscoveredgas fields can be found, developed, and produced. Similarly,at $30 per barrel and $3.34 mcf, 17.4 BBO, 25.9 TCF associ-ated gas, and 1.6 BBL NGL in undiscovered oil fields and95.9 TCFG and 2.9 BBL NGL in undiscovered gas fields iseconomic. Associated gas represents 20 percent of the totalgas estimated at both cost levels. Additionally, NGL fromassociated and non-associated gas accounts for one-fifth toone-fourth of total economic hydrocarbon liquids (crude oilplus natural gas liquids).

Crude oil in continuous-type oil accumulations, even atthe high cost level, adds less than 6 percent to economiccrude oil. At $2 per mcf, continuous-type gas accumulations

9INCREMENTAL COSTS


add 35.9 TCFG to economic resources, and, at $3.34 per mcf,72 TCFG is added. Assessed NGL resources in unconven-tional gas were very small. Quantities of economicunconventional gas are significant, even at low incrementalcosts. Total economic gas resources at $2 per mcf are 113.4TCFG and, at $3.34, are 196.3 TCFG.

The economic analysis treated the Northern Alaskaprovince (Alaska, Region 1) at the play level (see Attanasiand Bird, 1996) because it is still a frontier area with littleinfrastructure and is remote from markets. Incremental costsfor this province included product transport costs from thefield to the lower 48 States West Coast. These costs rangedfrom $5.41 to $9.38 per barrel. Assessed non-associated gasfields in the Northern Alaska province were not evaluated bythe economic analysis because markets and a product trans-portation system for new gas appear at least 2 decades away(see Attanasi, 1994). There is at least 30 TCF associated gasalready discovered that can be produced cheaply if a marketshould develop. Although no commercial value was imputedto the associated gas in oil fields in the Northern Alaska prov-ince, by-product revenues for natural gas liquids were cred-ited. The Cook Inlet area has local oil and gas markets, sothat, for the marginal unit of resources added to reserves,incremental costs equaled well-head price. For the Alaska

Region, at $18 per barrel, 11 percent of the technically recov-erable oil is economic. Similarly at $30 per barrel, 45 percentof the assessed oil is economic.

Nearly all the economic oil shown in table 1 is in con-ventional undiscovered oil fields. For the lower 48 States,about 36 percent of the geologically assessed oil in undis-covered conventional fields and continuous-type oil accu-mulations can be found, developed, and produced at $18 perbarrel. As costs increase to $30 per barrel, 62 percent of thetechnically recoverable oil is economic.

Assessed coal-bed gas and gas in continuous-typeaccumulations (unconventional gas) amounted to more thanthree-fifths of the 507 TCF of technically recoverable non-associated gas assessed in conterminous U.S. onshore and

EASTERN

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BILLIONS OF BARRELS OF CRUDE OIL

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EXPLANATION

Figure 7. Estimates of quantities of crude oil, by petroleum region,from undiscovered conventional oil fields and from assessed con-tinuous-type oil accumulations having incremental costs of $18 and$30 per barrel, respectively.

EASTERN

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TRILLIONS OF CUBIC FEET OF GAS

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$2.00/mcf unconventional

$3.34/mcf conventional

$3.34/mcf unconventional

EXPLANATION

Figure 8. Estimates of quantities of non-associated gas, by petro-leum region, from undiscovered conventional gas fields and fromassessed continuous-type gas accumulations having incrementalcosts of $2 and $3.34 per thousand cubic feet, respectively.

Figure 9 (facing page). Incremental cost of finding, developing,and producing crude oil from undiscovered conventional oil fieldsand crude oil from continuous-type oil accumulations in U.S. petro-leum regions: A, Region 1 (Alaska); B, Region 2 (Pacific Coast); C,Region 3 (Colorado Plateau and Basin and Range); D, Region 4(Rocky Mountains and Northern Great Plains); E, Region 5 (WestTexas and Eastern New Mexico); F, Region 6 (Gulf Coast); G, Re-gion 7 (Midcontinent); H, Region 8 (Eastern). Solid line representsundiscovered conventional oil, and dashed line represents the totalof undiscovered conventional oil and oil in continuous-typeaccumulations.

11INCREMENTAL COSTS

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13INCREMENTAL COSTS

State offshore areas. Table 1 shows that, even at a cost of $2per mcf, the unconventional gas accounts for 36 percent ofthe economic non-associated gas. As prices increase, theproportion of economic gas coming from these accumula-tions increases because of the much larger quantity of tech-nically recoverable gas in unconventional accumulations.Regions where unconventional gas is expected to dominate,that is, Colorado Plateau (Region 3) and Rocky Mountain(Region 4), are strategically located to contribute to WestCoast gas supplies. Eastern Region (Region 8) gas fromAntrim Shales of the Michigan Basin and coal-bed gas inCentral Appalachia will also find a ready market in theindustrial Northeast. Moreover, locational advantages ofEastern Region gas permit higher well-head prices topartially offset typically higher costs of unconventional gas.By source, economic non-associated gas at $2 per mcfamounted to 39 percent of the assessed technically recover-able undiscovered conventional gas and 10 percent of theassessed technically recoverable unconventional gas.Similarly, at $3.34 per mcf, 61 percent of undiscoveredconventional and 20 percent of unconventional gas iseconomic.

UNDISCOVERED CONVENTIONALOIL AND GAS

CHARACTERISTICS OF TECHNICALLY RECOVERABLE RESOURCES

Characteristics of the geologic assessment importantfor understanding the economic analysis are highlightedhere. Table A-1, Appendix A, shows the combined meanvalues of assessed conventional undiscovered recoverableresources for U.S. onshore and State offshore areas. Federaloffshore areas are not included. Oil and gas estimates shownin the table are small revisions to the estimates presented inU.S. Geological Survey Circular 1118 (U.S. GeologicalSurvey National Oil and Gas Resource Assessment Team,1995). The technically recoverable natural gas liquidsestimates shown here, however, correct estimates presentedin Circular 1118. The estimates are presented by field-typebecause cost and technology for oil and gas field

development are different. Non-associated gas, that is gas ingas fields, accounts for more than four-fifths of totalundiscovered gas.

Region 1.—The Northern Alaska province wasassigned mean values of 7.40 BBO and 63.5 TCFG, theCentral Alaska province 0.06 BBO and 2.7 TCFG, and theSouthern Alaska province 1.0 BBO and 2.1 TCFG. To placethese estimates in perspective, through-1990 cumulative dis-coveries in the Northern Alaska province amount to morethan 14 BBO and 32 TCFG, and, in the Southern Alaskaprovince, discoveries amount to about 1.2 BBO and 6.8TCFG (NRG Associates, 1993, 1994). Alaska accounts forabout 30 percent of the assessed technically recoverableundiscovered oil and 26 percent of the undiscovered gasresources in the 1995 National Assessment. Plays in theCentral Alaska province and in the Southern Alaskaprovince (outside of the Cook Inlet area) have very limitedpotential, and expected discovery sizes are unlikely to belarge enough to offset cost barriers imposed by the hostileclimate, primitive infrastructure, and remoteness from mar-kets. Consequently, these plays were not further evaluatedby economic analysis.

At the mean value, the 1995 Northern Alaska provinceassessment of undiscovered oil of 7.40 BBO is a 41 percentreduction from the 12.6 BBO estimated in the 1989 assess-ment (see Mast and others, 1989). Assessed undiscoveredgas increased by about 10 percent over the 1989 analysis.This revision resulted from new drilling information and analternative interpretation of the thermal history of theprovince (U.S. Geological Survey National Oil and GasResource Assessment Team, 1995) that reduced the per-ceived maximum depths where oil was thought to occur. Forthe 1995 Assessment, more than three-fourths of the esti-mated undiscovered oil was assigned to depths shallowerthan 10,000 ft and only 2 percent was assigned to depthsgreater than 15,000 ft. A high degree of uncertainty wasattached to geologic estimates for both oil and gas in theNorthern Alaska province.

Regions 2, 3, 4, 5, 6, 7, and 8.—Table A-1, AppendixA, shows more than 21 billion barrels of oil and 190 trillioncubic feet of gas remain to be discovered in the onshore andState offshore areas in the conterminous United States. Forthis area, undiscovered resources amount to only 13 percentof the oil and 23 percent of the gas already discovered.Nearly all of these areas have been rather thoroughlyexplored for conventional resources. State offshore areasaccount for about 10 percent of the undiscovered resourcesin the lower 48 States. Of the 55 provinces listed for thelower 48 States, 45 percent of the oil is contained in just fourprovinces (Permian Basin (044), Western Gulf (047),Louisiana-Mississippi Salt Basins (049), and Powder River(033)) and more than half the non-associated gas iscontained in the Western Gulf (047) province and theLouisiana-Mississippi Salt Basins (049).

Figure 10 (facing page). Incremental cost of finding, developing,and producing non-associated gas from undiscovered conventionalgas fields and unconventional gas from assessed continuous-typegas accumulations and coal-bed gas in U.S. petroleum regions: A,Region 1 (Alaska); B, Region 2 (Pacific Coast); C, Region 3 (Col-orado Plateau and Basin and Range); D, Region 4 (Rocky Moun-tains and Northern Great Plains); E, Region 5 (West Texas andEastern New Mexico); F, Region 6 (Gulf Coast); G, Region 7 (Mid-continent); H, Region 8 (Eastern). Solid line represents undiscov-ered conventional non-associated gas, and dashed line representsthe total of undiscovered conventional non-associated gas, gas incontinuous-type gas accumulations, and coal-bed gas.


Figure 11A shows the mean field-size frequency distri-bution of the ultimate (discovered plus undiscovered) andundiscovered numbers of fields containing at least 1 millionbarrels of oil equivalent (1 MMBOE). Similarly, figure 11Bshows the frequencies for all field-size classes. Table A-4,Appendix A, provides size class definitions. Data in the fig-ures show future discoveries to be dominated by smallerfields. Though only 10 percent of hydrocarbons discovered inthe past were in fields of less than 8 MMBOE, half the undis-covered hydrocarbons were assigned to these size classes.Field-size classes smaller than 1 MMBOE (classes 1-5) con-tain less than 3 percent of discovered hydrocarbons butaccount for 23 percent of the undiscovered hydrocarbons.Because finding, development, and production costs typi-cally vary inversely with field size, data behind the figuresimply increases in costs are associated with future discoveres.

INCREMENTAL COSTS OF OIL AND GAS FROM UNDISCOVERED CONVENTIONAL

OIL AND GAS FIELDS

Computation of incremental cost functions started withthe economic evaluation of the assessed distribution ofundiscovered oil and gas fields: the economic target forexploration. Province-level finding-rate functions were usedto predict the ordering and arrival rate of discoveries. Foreach increment of wildcat wells, the finding-rate functiongenerates a distribution of discoveries by size and depth,some of which will be commercially developable and somenot. The computational algorithm assumes exploration con-tinues until the expected economic value of the resources dis-covered by the last increment of wildcat wells is insufficientto pay for that exploration increment. The targeting of wild-cat wells by depth interval for each well increment maxi-mized the expected after-tax net present value of oil and gasdiscovered. Successive increments of wildcat wells generatesmaller discoveries and (or) discoveries in deeper horizonsthat typically lead to increasing finding costs. All this impliesthat it is not valid to simply add a flat finding cost to devel-opment cost to arrive at the full incremental costs.

Tables A-2 and A-3, Appendix A, show province-levelestimates of economic resources by commodity. Table A-2shows that, at $18 per barrel ($2 per mcf), it will be economicto find, develop, and produce 9.2 BBO, 15.8 TCF associatedgas, and 1 BBL NGL from undiscovered conventional oilfields and 61.7 TCFG and 2 BBL NGL from undiscoveredconventional gas fields. Table A-3 shows estimates of eco-nomic oil increase by 85 percent and total economic gasincreases by 57 percent as incremental costs are allowed toincrease to $30 per barrel ($3.34 per mcf). Associated gasaccounts for about one-fifth of total economic undiscoveredconventional gas, and NGL from associated and non-associ-ated gas contributes 20 to 25 percent to total conventionalliquid hydrocarbons (crude oil plus NGL).

For the Northern Alaska province, at a lower-48-States-West-Coast price of $18 per barrel, only 8 percent of the tech-nically recoverable undiscovered oil is economic; at $30 perbarrel, about 43 percent is economic. For the lower 48 States,38 percent of the technically recoverable undiscovered oiland 39 percent of the technically recoverable undiscoverednon-associated gas can be found, developed, and produced atincremental costs of $18 per barrel ($2 per mcf). At an incre-mental cost of $30 per barrel ($3.34 per mcf), two-thirds ofthe technically recoverable oil and gas is economic.

The Alaska and Gulf Coast Regions have the largestquantities of economic undiscovered oil at $30 per barrel,followed by (1) the Rocky Mountain Region and (2) the WestTexas and Eastern New Mexico Region. Tables A-2 and A-3, Appendix A, show that, within most regions, one or twoprovinces dominate potential reserve additions. Based on the

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EXPLANATIONB

Figure 11. Field-size distribution of ultimate (discovered plusundiscovered) and undiscovered conventional oil and gas fields inonshore and State offshore areas of the conterminous United States.A, part of distribution for fields containing at least 1 million barrelsof oil equivalent. B, entire distribution. Size classes, in terms ofmillions of barrels of oil equivalent, are defined in table A-4,Appendix A.

15INCREMENTAL COSTS

incremental cost functions and the fraction of technicallyrecoverable oil that is economic to find, develop, and pro-duce at an incremental cost of $18 per barrel, the PermianBasin province (044) in the West Texas and Eastern NewMexico Region has the lowest cost oil, followed by theWestern Gulf province (047) in the Gulf Coast Region. TheNorthern Alaska province was assigned the largest quantityof oil of any U.S. province; however, transport of the productto market increases costs substantially.

For economic undiscovered non-associated gas, theGulf Coast Region is the dominant region, followed by theRocky Mountain, Midcontinent, and West Texas andEastern New Mexico Regions. The Western Gulf provinceof the Gulf Coast Region has lowest costs. Half of thetechnically recoverable gas in the Gulf Coast Region is eco-nomic to find, develop, and produce for $2 per mcf. Thatquantity of gas is more than all the other regions combinedat that cost level.

Even at low well-head prices, improvements inexploration technology are likely to occur during the next 2decades. Though undiscovered resources are unchanged,improvements in exploration efficiencies can increase thequantity of resources found and developed at nearly everycost level. If the analysis for the conterminous United Statesis repeated assuming exploration efficiency is doubled, thequantity of crude oil and non-associated gas that is economicat $18 per barrel ($2 per mcf) increases by more than one-third, so 54 percent of the technically recoverable resourcesare economic. At the $30 per barrel ($3.34 per mcf), almostthree-fourths of the assessed resources are economic.

CONTINUOUS-TYPE ACCUMULATIONS AND COAL-BED GAS

CHARACTERISTICS OF TECHNICALLY RECOVERABLE RESOURCES

Tables 2 and 3 show the expected values of the assessedtechnically recoverable oil and gas in continuous-type playsand in coal-bed gas plays, respectively. The 302 TCFassessed in sandstone/siltstone, shale, and chalk continuous-type plays and the 50 TCF in coal-bed gas together representmore than twice the estimated technically recoverable undis-covered conventional gas assessed in the lower 48 States.The 2 BBO assessed in continuous-type oil plays is smallcompared to oil in undiscovered conventional fields. Morethan half this oil was in the Austin Chalk plays of the West-ern Gulf province (047).

The geographical concentration of the resourcesassessed in continuous-type gas and in coal-bed gas plays isvery uneven. Three of the twelve provinces with assessedcontinuous-type gas accumulations accounted for two-thirdsof the gas. These dominant provinces include SouthwesternWyoming (037), Appalachian Basin (067), and Central

Montana (028). Similarly, of the 13 provinces with assessedcoal-bed gas plays, the Uinta-Piceance (020), the San Juan(022), and the Appalachian (067) Basins accounted two-thirds of the total gas.

With few exceptions the coal-bed gas assessed by geol-ogists was restricted to depths of 6,000 ft or less. One-thirdof the 302 TCF of technically recoverable gas assessed incontinuous-type plays is shallower than 5,000 ft and one-fifth is deeper than 15,000 ft. Coal-bed gas and shallow gasin continuous-type gas plays together account more than 150TCFG. The in-place volumes of hydrocarbons in unconven-tional plays are overwhelming. Some unconventional playswere not assessed because the geologic and production datawere simply not sufficient or because the inferior quality ofthe resources, in the assessor’s judgment, was outside thepractical limits of recovery technology.

INCREMENTAL COSTS OF OIL AND GAS FROM CONTINUOUS-TYPE AND COAL-BED GAS

ACCUMULATIONS

For unconventional resources, incremental costs repre-sent the full costs of exploring, developing, and producingthe commercially developable cells in a specific 5,000-ftdepth interval of a continuous-type or coal-bed gas play.Individual depth intervals of continuous-type or coal-bed gasplays will not be explored unless the aggregate expectedafter-tax net present value of the commercially developablecells is sufficient to cover costs of testing all cells in thedepth interval.

Gas resources in continuous-type gas accumulations aremassive, but are also dilute, as evidenced by typically lowwell productivities. Only 7 percent of the assessed techni-cally recoverable gas is economic to find, develop, and pro-duce at $2 per mcf. At $3.34 per mcf, 15 percent of theassessed gas is economic (see table 2). At $2 per mcf, playsin the San Juan Basin (022), the Louisiana-Mississippi SaltBasins (049), the Uinta-Piceance Basin (020), and the Cen-tral Montana (028) provinces account for 85 percent of theeconomic resources in continuous-type gas accumulations(see table 2). These provinces continue to dominate as costsincrease to $3.34 per mcf and plays from the Michigan (063),Appalachian (067), and Southwestern Wyoming (037) prov-inces are added. The lowest cost continuous-type gas playsevaluated were in the San Juan and Louisiana-MississippiSalt Basins, having costs of $1.10 per mcf.

The quantity of oil assessed in continuous-type oilaccumulations is small. For continuous-type oil accumula-tions at $18 per barrel and $30 per barrel, about 7 percent and50 percent, respectively, of the assessed technically recover-able oil is economic (see table 2).

Table 3 shows, at $2 per mcf, 30 percent of the assessedcoal-bed gas is economic. The San Juan (022), Uinta-Piceance (020), and Appalachian (067) Basins account for86 percent of the economic resources. As incremental costs

17INFERRED RESERVE ESTIMATES

increase to $3.34 per mcf, more than half of all the assessedcoal-bed gas becomes economic. The lowest cost plays (withcosts of $1 per mcf) were located in the San Juan Basin.

The regional distribution of economic gas in continu-ous-type gas accumulations and coal-bed gas is notable. TheSan Juan and the Uinta-Piceance Basins can supply WestCoast markets. Gas from the Michigan Basin Antrim Shaleand Central Appalachian coal-bed gas plays have readymarkets in the industrial Northeast. Economic undiscoveredconventional gas in these provinces is very modest.Locational advantages, particularly in the Eastern Region,permit higher well-head prices to offset the generally highercosts of developing these unconventional gas resources.

Assumptions applied in the economic evaluationassured conservative estimates of economic resources. Forexample, it was assumed that the industry could not selec-tively drill a continuous-type play. However, an individualfirm may have site-specific or specialized knowledge thatallows it to high-grade a play by identifying “sweet spots.”At the time of the 1995 National Assessment, the occurrenceand extent of these local sweet spots were not known with

sufficient detail to incorporate them. Selective drillingreduces costs by siting wells in high-productivity areas andavoiding noncommercial wells. For some plays, industryproduction experience gained since the 1995 NationalAssessment suggests more efficient well spacing (cell size)than assumed. Although it was assumed that new wells arerequired to test and produce each cell in a continuous-typeaccumulation, in practice, the industry has recompletedexisting wells to produce these resources.

INFERRED RESERVE ESTIMATES

FIELD GROWTH: ORIGINS AND QUALIFICATIONS

Field-growth projections are applied only to conven-tional pre-1992 discoveries. Inferred reserves (field growth)are recoverable resources in discovered fields beyond cur-rent proved reserves that are expected to be added in thefuture as proved reserves. Because proved reserves are


reported in financial statements, commercial transactions,legal contracts, and in response to regulatory mandates bygovernmental entities, traditionally its definition reflects thehighest degree of certainty about economically recoverablevolumes of the resource in identified fields. Although wordedslightly differently, standards of reporting proved reservespublished by the Securities and Exchange Commission(1981), the Society of Petroleum Engineers (1987), andEnergy Information Administration (1994) convey essen-tially the same narrow definition. The Energy InformationAdministration (1994) defines proved reserves as estimatedvolumes of the resource which geologic and engineering datademonstrate with reasonable certainty to be recoverable infuture years from known reservoirs under existing economic,operating and, regulatory conditions. Reservoirs are provedif commercial producibility is supported by actual produc-tion or conclusive formation tests (drill stem or wire line),core analysis, and (or) electric or other log interpretations.

Proved reserves increase with normal field developmentas boundaries of proved areas are extended by drilling; asnew pay zones, pools, or reservoirs are found and confirmedby drilling; as new infill wells (vertical and horizontal) orwell-stimulation procedures contact previously inaccessiblehydrocarbons; and with the introduction of water-flood orother fluid-injection programs. Data used in calibratingcumulative growth functions (see earlier discussion) and esti-mating field growth, however, do not allow identification ofthe source of reserve additions with level of effort expendedto increase reserves. Hence, costs were not definitively tiedto either past or projected field growth.

Field-growth projections are also not very robust tochanges in assumptions implicit in the calibration and appli-cation of the cumulative field growth function. The 1995National Assessment, for example, assigned three times asmuch oil and gas to inferred reserves than the 1989 USGSAssessment (Mast and others, 1989). Part of the reason forthis increase is that newly available data from the 1977-1991period show some fields continuing to grow 90 years afterdiscovery—well beyond the 60-year cutoff used in 1989 (seefootnote 2). In fact, if a 60-year field-growth cutoff isimposed on these data, the inferred oil estimate is about one-third of 1995 estimate and the gas estimate is one-half of the1995 estimate. The shape of the cumulative growth functionis also sensitive to the sample period used in calibration(National Petroleum Council, 1992, p. 45–46).

Fields are not well-defined entities and, as a fundamen-tal unit of observation, are frequently defined in an ad hocmanner for the convenience of regulatory agencies or ofoperators, or they are simply artifacts of the historicaldiscovery process. If the unit of observation is narrowed tothe level of the pool, as it is in Canada, reserve growth islimited to extensions, infill drilling, well stimulation, andefforts to enhance recovery. On average, pools reach fulldevelopment earlier than fields. Cumulative growth func-tions calibrated with Canadian data on pools show gas pools

reached 85 percent of full size 7 years after discovery and oilpools reached 85 percent of full size 27 years after discovery(K. Drummond, National Energy Board of Canada, writtencommun., 1996). In contrast, U.S. gas fields did not attain 85percent of their 90-year size until 61 years, and oil fields didnot attain 85 percent of their 90-year size until 66 years afterdiscovery. Growth is sustained over a longer time period inoil accumulations than in gas accumulations. The low initialrecovery of oil, typically less than 35 percent of in situhydrocarbons rather than the 70 to 80 percent for gas fields,makes the remaining oil an attractive target for progressivelymore intensive development efforts, particularly for verylarge fields.

The unknown effects of model specification and errorsin the data have not been sufficiently formalized to quantifythe uncertainty in projected field-growth estimates. Costswere not estimated because past or projected future fieldgrowth could not be related to specific development efforts.3

However, within a province, continuing simultaneous newfield exploration, field development, and investment in pre-1992 discoveries indicates costs associated with the marginalquantities of oil and gas produced in each project arecomparable. In order to study potential reserves that might beavailable for production during the next 2 decades, inferredreserve projections from 1994 through 2015 were calculated.Projected field-growth reserve additions through 2015amount to about one-half the total oil and gas projectedthrough 2071 (see U.S. Geological Survey National Oil andGas Resource Assessment Team, 1995).

FIELD GROWTH THROUGH 2015:A COMPARATIVE ANALYSIS

Figure 12 shows regional estimates of proved reserves,projected oil growth though 2015, and estimated oil fromundiscovered conventional oil fields and continuous-typeaccumulations with incremental costs of $30 per barrel($3.34 per mcf). Figure 13 is similar but shows amounts ofnon-associated gas. Only the non-associated gas growth inthe Cook Inlet area was projected for Alaska because gas isnot under development in the Northern Alaska province.Proved reserve estimates, prepared by the Energy Informa-tion Administration (1994), are as of January 1994 andinclude proved reserves of oil and gas from conventionalfields, continuous-type accumulations, and coal-bed gas.Field-growth projections from pre-1992 discoveries started

3Investments in field development and enhanced recovery are site spe-cific, so the technical characteristics of the discovered pools or fields mustbe known in some detail to choose among alternative technologies. One ap-proach is to develop a series of sceening criteria and engineering cost modelsto apply to candidate fields to a priori estimate costs of future growth in re-serves. Such an approach was used by Bowers and Drummond (1994) andthe National Petroleum Council (1984).

19IMPLICATIONS AND LIMITATIONS

in 1994. Figures 12 and 13 are useful because they showquantities and sources of oil and gas that could be availablefor production during the next 2 decades through 2015.

Overall, projected growth (of pre-1992 oil discoveries)through 2015 accounts for about 44 percent of the 69 BB ofthe crude oil represented by regions and sources shown infigure 12. Proved reserves account for 29 percent, and eco-nomic oil discoveries and continuous-type accumulationsaccounted for the rest. Regional shares of oil growth in thelower 48 States mimic the pattern observed during the 1977to 1991 data period. The Alaska, Pacific Coast, and WestTexas and Eastern New Mexico Regions account for almostthree-fourths of projected oil growth. The Gulf Coast Regionhas almost 30 percent of the oil discovered to date butaccounts for only 5 percent of the projected growth (see fig.D-1, Appendix D). Its disproportionately low oil growth mayresult because the region has higher initial recovery of the in-place oil, leaving less oil for enhanced recovery.

Projected field growth (of pre-1992 gas discoveries)through 2015 accounts for about a quarter of the 381 TCF ofnon-associated gas represented in figure 13. Proved reservesaccount for 30 percent, and economic gas from new gasdiscoveries, continuous-type accumulations, and coal-bedgas account for 44 percent. In the lower 48 States, projectedregional shares of growth almost duplicates the patternobserved for growth of non-associated gas during the 1977to 1991 period. The Gulf Coast and Midcontinent Regionsaccount for 80 percent of non-associated gas growththrough 2015. In summary, quantities of oil and gas from field growth

could account for 44 percent of the oil and a quarter of thenon-associated gas available for production during the next2 decades. Estimated quantities of oil are large but the deliv-erability or flow rates of the resource from enhanced recov-ery projects are typically inferior to flow rates that can beachieved in newly discovered conventional fields of compa-rable size. In comparison to assessed quantities of economicundiscovered oil resources, break-throughs in improvementsin recovery efficiency of oil-in-place would make old fieldsinto even more important sources of future domestic suppliesthan suggested above.

IMPLICATIONS AND LIMITATIONS

Several findings are worth further elaboration. The 1994proved reserves of oil, non-associated gas, and total gasamount to roughly 10 times their 1994 production, respec-tively. Assuming this reserves-to-production ratio is sus-tained in the future, then, in order to maintain 1994 productionthrough 2015 (that is, 22 years), additions to oil and gasreserves from field growth and economic undiscovered con-ventional and unconventional resources must amount to 42.8BBO and 259.5 TCF non-associated gas (or 298.2 TCF totalnon-associated and associated gas). Even if the quantities pro-jected from field growth are added to reserves during this

Figure 12. Estimates, as of January 1994, of proved crude oil re-serves, projected crude oil reserve additions through 2015 for oilfields discovered before 1992, and the combined estimates of crudeoil in undiscovered conventional oil fields and from continuous-type oil accumulations having incremental costs of $30 per barrel.

EASTERN

MIDCONTINENT

GULF COAST

W. TX & E. NM

ROCKY MT.

CO PLATEAU

PACIFIC COAST

ALASKA

0 10 20 30 40 50 60 70

GAS, IN TRILLIONS OF CUBIC FEET

Proved reserves Growth through 2015

Conventional undiscovered and MMunconventional at $3.34/mcf

EXPLANATION

Figure 13. Estimates, as of January 1994, of proved non-associatedgas reserves, projected non-associated gas reserve additionsthrough 2015 for gas fields discovered before 1992, and the com-bined estimates of non-associated gas in undiscovered conventionalgas fields and from continuous-type gas accumulations having in-cremental costs of $3.34 per thousand cubic feet.

EASTERN

MIDCONTINENT

GULF COAST

W. TX & E. NM

ROCKY MT.

CO PLATEAU

PACIFIC COAST

ALASKA

0 2 4 6 8 10 12

OIL, IN BILLIONS OF BARRELS

Growth through 2015 Proved reserves

Conventional undiscovered and MMunconventional at $30/bbl

EXPLANATION


time, expected total additions from economic undiscoveredconventional and unconventional oil and gas at $18 per barrel($2 per mcf) would not be enough to maintain 1994 produc-tion. When prices are $30 per barrel ($3.34 per mcf), projectedgrowth and total reserve additions from economic oil and gasbarely meet these requirements. Moreover, the developmentof newly discovered conventional fields would not likely addtheir entire ultimate recovery to proved reserves during thistime period without greatly accelerated development. Pro-jected reserve additions from pre-1992 discoveries (fieldgrowth) may also be optimistic—half of the hydrocarbonsfrom field growth expected during the next 80 years were pro-jected in the period to 2015. In summary, even though itappears possible with increases in real prices to $30 per barrel($3.34 per mcf) to maintain production at levels comparableto that of 1994 production, this production level will be verydifficult to achieve without significant improvements inexploration and production technology.

Analysis shows that gas from continuous-type accumu-lations and coal-bed gas can make significant contributions tosupply and identifies provinces where this gas is currentlyproduced at competitive costs. By virtue of the large quantityof technically recoverable unconventional gas assessed, itsshare of total gas supplies is expected to increase as pricesincrease. These accumulations are generally large, disperse,hydrocarbon resources. Extraction costs for unconventionalgas are typically higher than costs for conventional accumu-lations; however, improvements in well-stimulation technol-ogy and practices could significantly increase the volume ofresources that can be accessed by an individual well, and thusreduce unit costs.

The abundance of oil and gas produced from conven-tional fields at high flow rates in the early years of the twen-tieth century permitted the U.S. economy to move from coalto petroleum fuels as its basic energy source. However, the1995 National Assessment showed that oil field growth andunconventional gas account for the largest quantities of esti-mated technically recoverable crude oil and gas resources.While there are some exceptions, reserve additions fromthese sources are not characterized by high deliverability. Thecharacteristic of deliverability bridges the gap between eco-nomic reserves and actual production. Generally, lower qual-ity resources require much larger amounts of capital toproduce at the same level as high-flow-rate conventionalresources. In particular, because their production characteris-tics are typically inferior to conventional accumulations ofsimilar size, they require larger amounts of proved reservesper unit of daily production. Consequently, even though theseresources meet the standards of economic reserves, theyprobably will not be produced rapidly.

Estimates of economic oil and gas from conventionalundiscovered fields and unconventional plays were based onthe mean or expected value reported in the geologic assess-ment. It is appropriate to use this point estimate in the com-putations and for ease of communicating results; however, it

tends to convey a mistaken sense of precision in the results.The economic analysis could also have been prepared usingdistributions associated with the 5th or 95th fractiles of theassessment. Indeed, there is also uncertainty in the costs andtechnical relationships used in the economic analysis, as wellas the field-growth analysis that is yet to be quantified.

Economic models are also limited in that they areabstractions designed to characterize a real economic system,but they are typically detailed enough to only roughly approx-imate the outcomes of interactions between economic agents.Only the general direction and the approximate magnitude ofthe reaction of the system to change can be modeled. Incre-mental cost functions are time independent and should not beconfused with the firm supply functions that relate marginalcost to production per unit time period. Because of the time-independent nature of the incremental cost functions and theabsence of market-demand conditions in the analysis, usercosts or the opportunity costs of future resource use are notcomputed. However, the incremental cost functions and thedata that underlie the functions can provide the basis for mar-ket-supply models.

For a national perspective, the resources estimated bythe Minerals Management Service (1996) in undiscoveredconventional oil and gas for the Federal Outer ContinentalShelf (OCS) should be added to the estimates presented here.At $18 per barrel ($2 per mcf dry gas) the Minerals Manage-ment Service assessed a total of 14.4 BBO and 72.5 TCFG forthe U.S. OCS. At $30 per barrel ($3.34 per mcf dry gas), eco-nomic resources were estimated at about 21 BBO and 100TCFG. Alaska’s OCS was assigned 3.8 BBO at $18 per barreland about 6.6 BBO at $30 per barrel. Amounts of economicgas assigned to Alaska were very small. Based on the analysispresented here, for onshore and State water areas at the $18per barrel ($2 per mcf) level, total economic oil and gasassessed in undiscovered conventional and unconventionalaccumulations was 9.3 BBO and 113 TCFG, respectively. Atthe higher price level, economic oil is estimated at 18.5 BBOand total gas is 196.3 TCFG.

Acknowledgments.—The report represents a revision ofresults, summary, synthesis, and interpretation of the eco-nomic analysis cited in the four earlier Open-File Reports onthe economics of various components of the 1995 USGSNational Assessment of Oil and Gas Resources listed in thereference list. The geologic assessment project was under thedirection of D. Gautier. Province geologists responsible forassessing the conventional undiscovered resources were M.Ball, C. Barker, K. Bird. L. Beyer, T. Bruns, W. Butler, R.Charpentier, G. Dolton, T. Dyman, T. Fouch, J. Fox, J. Grow,J. Hatch, T. Hester, D. Higley, M. Henry, A.C. Huffman, Jr.,S. Johnson, C.W. Keighin, M. Keller, B. Law, D. Macke, L.Magoon, R. Milici, C. Molenaar, J. Palacas, W. Perry, Jr., J.Peterson, R. Pollastro, R. Powers, R. Ryder, C. Schenk, C.Spencer, R. Stanley, M. Tennyson, and C. Wandrey. D.H.Root was responsible for aggregation of play-level geologicassessments and prepared computations of province-level

21REFERENCES CITED

expected frequency-size distributions of undiscovered con-ventional fields by depth intervals. Province geologists whoassessed the continuous-type accumulations were G. Dolton,T. Dyman, T. Fouch, J. Hatch, D. Higley, A.C. Huffman, Jr.,B. Law, R. Milici, W. Perry, R. Pollastro, R. Ryder, C.Schenk, J. Schmoker, and C. Spencer. R. Crovelli and R.Balay prepared the original computations of the expected val-ues of the technically recoverable resources. J. Quinn wasresponsible for development of empirical EUR distributionsand well-production characteristics of continuous-typeaccumulations. D. Rice prepared the geologic assessment ofcoal-bed gas. Advance Resources, Inc., prepared coal-bedgas well-production characteristics. Field-growth projectionsfor the original assessment and subsequent regional projec-tions were prepared by D.H. Root. I am also grateful to G.L.Dolton and R.F. Mast for manuscript review.

REFERENCES CITED

Attanasi, E.D., 1994, U.S. North Slope gas and Asian LNG mar-kets: Resources Policy, v. 20, no. 4, p. 247–255.

Attanasi, E.D., and Bird, K.J., 1996, Economics and undiscoveredconventional oil and gas accumulations in the 1995 NationalAssessment of U.S. oil and gas resources: Alaska: U.S. Geo-logical Survey Open-File Report 95-75J, 48 p.

Attanasi, E.D., Gautier, D.L., and Root D.H., 1996, Economics andundiscovered conventional oil and gas accumulations in the1995 National Assessment of oil and gas resources: Contermi-nous United States: U.S. Geological Survey Open-File Report95-75H, 50 p.

Attanasi, E.D., and Rice, D.D., 1995, Economics and coalbed gasin the 1995 National Assessment of oil and gas resources: U.S.Geological Survey Open-File Report 95-75A, 22 p.

Attanasi, E.D., Schmoker, J.W., and Quinn, J.C., 1995, Economicsand continuous-type oil and gas accumulations in the 1995National Assessment of U.S. oil and gas resources: U.S. Geo-logical Survey Open-File Report 95-75F, 33 p.

Bowers, B., and Drummond, K., 1994, Conventional crude oilresources of the Western Canadian Sedimentary Basin:Petroleum Society of CIM & AOSTRA Paper No. 94-71,June, 1994.

Energy Information Administration, 1994, U.S. crude oil, naturalgas, and natural gas liquids reserves: Washington, D.C., 1993Annual Report, 155 p.

———1995, U.S. crude oil, natural gas, and natural gas liquidsreserves: Washington, D.C., 1994 Annual Report, 153 p.

Gautier, D.L., and Dolton, G.L., 1995, Methodology for assess-ment of undiscovered conventional accumulations in, Gautier,D.L., Dolton, G.L., Takahashi, K.I., and Varnes, K.L., eds.,1995 National Assessment of United States Oil and GasResources—Results, Methodology, and Supporting Data:U.S. Geological Survey Digital Data Series DDS-30, release2, 1 CD-ROM.

Gautier, D.L., Dolton, G.L., Takahashi, K.I., and Varnes, K.L.,eds., 1995, 1995 National Assessment of United States Oiland Gas Resources—Results, Methodology, and SupportingData: U.S. Geological Survey Digital Data Series DDS-30,release 2, 1 CD-ROM.

Houghton, J.C., Dolton, G.L., Mast, R.F., Masters, C.D., and Root,D.H., 1993, U.S. Geological Survey estimation procedure foraccumulation size distribution by play: Bulletin of theAmerican Association of Petroleum Geologists, v. 77., no. 3,p. 454–466.

Mast, R.F., Dolton, G.L., Crovelli, R.A., Root, D.H., Attanasi,E.D., Martin, P.E., Cook, L.W., Carpenter, G.B., Pecora, W.C.,and Rose, M.B., 1989, Estimates of undiscovered conventionaloil and gas resources in the United States; A summary: U.S.Geological Survey/Minerals Management Service SpecialPublication, 56 p.

Minerals Management Service, 1996, An Assessment of the undis-covered hydrocarbon potential of the Nation’s outer continen-tal shelf: Washington D.C., 50 p.

National Petroleum Council, 1984, Enhanced oil recovery: Wash-ington, D.C., 289 p.

———1992, The potential for natural gas in the U.S.—Source andsupply: Washington, D.C., v. 2, 400 p.

NRG Associates, 1993 and 1994, The significant oil and gas fieldsof the United States: Colorado Springs, Colo., NRGAssociates, Inc. [includes data current as of December 31,1992, and December 31, 1993, respectively—database avail-able from NRG Associates, Inc., P.O. Box 1655, ColoradoSprings, CO 80901].

Rice, D.D., Young, G.B., and Paul, G.W., 1995, Methodology forassessment of technically recoverable resources of coalbedgas, in Gautier, D.L., Dolton, G.L., Takahashi, K.I., and Var-nes, K.L., eds., 1995 National Assessment of United States Oiland Gas Resources—Results, Methodology, and SupportingData: U.S. Geological Survey Digital Data Series 30, release 2,1 CD-ROM.

Root, D.H., and Attanasi, E.D., 1993, Small fields in the NationalOil and Gas Assessment: Bulletin of the American Associationof Petroleum Geologists, v. 77, no. 3, p. 485–490.

Root, D.H., Attanasi, E.D., Mast, R.F., and Gautier, D.L., 1996,Estimates of inferred reserves for the 1995 USGS National Oiland Gas Resource Assessment, U.S. Geological Survey Open-File Report 95-75-L, 29 p.

Schmoker, J.W., 1995, Method for assessing continuous-type(unconventional) hydrocarbon accumulations, in Gautier,D.L., Dolton, G.L., Takahashi, K.I., and Varnes, K.L., eds.,1995 National Assessment of United States Oil and GasResources—Results, Methodology, and Supporting Data:U.S. Geological Survey Digital Data Series 30, release 2, 1CD-ROM.

Securities and Exchange Commission, 1981, Securities andExchange Commission reserves definitions: Regulation S-X,Rule 40-10; Financial accounting and reporting oil and gasproducing activities: New York, Brown and Co.

Society of Petroleum Engineers, 1987, Reserves definitionsapproved: Journal of Petroleum Technology, no. 576, p. 576.

U.S. Geological Survey National Oil and Gas Resource Assess-ment Team, 1995, 1995 National Assessment of United StatesOil and Gas Resources: U.S. Geological Survey Circular1118, 20 p.


GLOSSARY OF SELECTED TERMS

barrels of oil equivalent (BOE).—gas volume and NGL vol-ume that is expressed in terms of its energy equiva-lent in barrels of crude oil. For this assessment, 6,000cubic feet of gas equals 1 barrel of crude oil, and 1barrel of NGL equal 0.667 barrels of crude oil.

cell.—a subdivision of a continuous-type oil or gas play, thearea of which is equivalent to the median drainagearea of wells producing from the play. A productivecell has at least one well with reported production. Anonproductive cell is a cell that was evaluated withdrilling but where none of the wells have reportedproduction. An untested cell is one that has not beenevaluated by a well. The number of cells in a play isequal to the area of the play divided by the cell area.

conditional estimates.—sizes, numbers, or volumes of oil ornatural gas that are estimated to exist in an area,assuming that at least some oil and gas is present.Conditional estimates do not incorporate the risk thatthe area may be devoid of oil or natural gas.

continuous-type accumulation.—a hydrocarbon accumula-tion that is pervasive throughout a large area, that isnot significantly affected by hydrodynamic influ-ences, and for which the standard methodology forassessment of sizes and numbers of discrete accumu-lations is not appropriate.

conventional accumulations.—discrete deposits having awell-defined downdip oil or gas water contact, fromwhich oil, gas, or NGL can be extracted using tradi-tional development practices.

crude oil.—a mixture of hydrocarbons that exist in the liquidphase in underground reservoirs and remain liquid atatmospheric pressure after passing through surfaceseparating facilities.

estimated ultimate recovery (EUR) probability distribu-tion.—a probability distribution of ultimate recover-ies of oil or gas that characterizes the distribution ofgas recoveries in productive cells within a play. Anempirical EUR distribution is based on the estimatedultimate recoveries of wells thought to be representa-tive of the play’s range of recoveries. The reportedEUR distribution for untested cells is assigned by thegeologist to represent the distribution of recoveriesfrom potentially productive, but as of yet untested,cells within the play.

field.—an individual producing unit consisting of a singlepool or multiple pools of hydrocarbons grouped on, orrelated to, a single structural or stratigraphic feature.

crude oil fields.—fields where the ratio of natural gas tocrude oil is less than 20 thousand cubic feet of gasper barrel of crude oil.

non-associated gas fields.—fields where the ratio of nat-ural gas to crude oil is at least 20 thousand cubicfeet of gas per barrel of crude oil.

field growth (inferred reserves).–that part of identified con-ventional resources over and above proved (mea-sured) reserves, expected to be added to existingconventional fields through extension, revision,improved efficiency, and addition of new pools orreservoirs.

gas-oil ratio (GOR).—average ratio of associated-dissolvedgas to oil.

growth function.—cumulative growth function relates a mul-tiple of a field’s initially estimated size to the numberof years after discovery. A field age of zero isassigned to the year of discovery. If the cumulativegrowth function has the property that older fieldsexperience a smaller percentage of growth thanyounger fields, then the cumulative growth functionis monotonic. An “annual growth function” expressesannual percentage field growth as a function of theestimated field size at the end of the previous year.

NGL to non-associated gas ratio.—volume of natural gasliquids (NGL), in barrels, contained in 1 millioncubic feet of wet gas in a known or postulated gasaccumulation.

NGL to associated-dissolved gas ratio.—volume of naturalgas liquids, in barrels, in 1 million cubic feet ofassociated-dissolved wet gas in a known or postu-lated oil accumulation.

natural gas.—a mixture of hydrocarbon compounds andsmall quantities of non-hydrocarbons existing in gas-eous phase or in solution with crude oil in naturalunderground reservoirs at reservoir conditions. Theprincipal hydrocarbons normally contained in themixture are methane, ethane, propane, butane, andpentanes.

natural gas liquids (NGL).—those hydrocarbons in naturalgas that are separated from the gas through theprocesses of absorption, condensation, adsorption, orother methods in gas processing or cycling plants.Generally, such liquids consist of propane andheavier hydrocarbons and are commonly referred toas natural gasoline or liquefied petroleum gases.After separation of natural gas liquids from the gas,the gas is called “dry.”

play.—set of known or postulated oil and (or) gas accumula-tions sharing similar geologic, geographic, andtemporal properties, such as source rock, migrationpatterns, timing, trapping mechanism, and hydrocar-bon type.

confirmed plays.—plays where one or more accumula-tions of minimum size (1 million barrels of oil or6 billion cubic feet of gas) have been discoveredin the play.

hypothetical plays.—plays identified and defined basedon geologic information but for which no accu-mulations at minimum size (1 MMBO or 6BCFG) have, as yet, been discovered.

23GLOSSARY OF SELECTED TERMS

play attributes.—geologic characteristics thought to charac-terize the principal elements necessary for occur-rence of oil and (or) gas accumulations of someminimum size. Attributes used in this assessment(charge, reservoir, and trap) are defined as:

charge.—occurrence of conditions of hydrocarbon gen-eration and migration adequate to cause an accu-mulation of the minimum size. Subsidiaryelements of charge are source rocks with suffi-cient organic matter, temperature, and duration ofheating for expulsion of sufficient quantities ofoil and (or) gas and timing of expulsion of hydro-carbons to available traps.

reservoir.—occurrence of reservoir rocks of sufficientquantity and quality to permit containment of oiland (or) gas in volumes sufficient for an accumu-lation of the minimum size.

trap.—occurrence of those structures, pinch-outs, per-meability changes, and similar features necessaryfor the entrapment and sealing of hydrocarbonsin at least one accumulation of the minimum size.

play probability.—for recoverable resources, represents thelikelihood that technically recoverable quantities ofoil or natural gas exist in at least one undiscoveredaccumulation of the minimum size (1 MMBO or 6BCFG) in the play being assessed.

proved (measured) reserves.—estimated quantities of crudeoil, natural gas, or natural gas liquids which geologi-cal and engineering data demonstrate with reason-able certainty to be recoverable in future years fromknown reservoirs under existing economic and oper-ating conditions. Reserves are proved if economicproductivity is supported by actual production orconclusive formation tests (drill stem or wireline), or

if economic producibility is supported by core analy-ses and (or) electric or other log interpretations.

reservoir.—a porous and permeable underground formationcontaining an individual and separate accumulationof producible hydrocarbons that is confined byimpermeable rock or water barriers and is character-ized by a single natural pressure system.

risked (unconditional) estimates.—resources estimated toexist, including the possibility that the area of theplay may be devoid of oil or natural gas. For exam-ple, the risked mean may be determined by multipli-cation of the mean of a conditional distribution by therelated probability of occurrence. Resource estimatespresented in this report are risked estimates.

technically recoverable.—estimated to be producible usingcurrent technology but without reference toeconomic profitability.

ultimate field size (known recovery).—the sum of cumula-tive past production and estimated current reserves.

unconventional oil and gas accumulations.—a broad class ofhydrocarbon deposits of a type that traditionally havenot been produced using standard development prac-tices. Unconventional deposits include continuous-type oil and gas accumulations and coal-bed gas.Standard definitions of unconventional oil and gasaccumulations often hinge on gravity of oil or thepermeability of the oil and gas reservoir rock. Eventhough most continuous-type accumulations arecharacterized by poor reservoir permeability, not alllow-permeability deposits are continuous-typeaccumulations.

undiscovered resources.—resources postulated from geo-logic information and theory to exist outside ofknown oil and (or) gas fields.

Published in the Central Region, Denver ColoradoManuscript approved for publication August 11, 1997Edited by Richard W. Scott, Jr.Graphics preparation and photocomposition by

William E. Sowers; use made of author-drafted material


APPENDIX A—TABLES OF PROVINCE-LEVEL CONVENTIONALUNDISCOVERED RESOURCE ESTIMATES

Table A-1 (1/2)

6a(1/2)

25appendix a—tables of province-level conventional undiscovered resource estimatesAPPENDIX A


APPENDIX B—TABLES SHOWING REGIONS, PROVINCES, PROVINCENUMBERS, AND PLAY NUMBERS FOR CONTINUOUS-TYPE PLAYS AND

COAL-BED GAS PLAYS

31Appendix b—Tables showing regions, provinces, province numbers, and play numbers for continuous-type plays and coal-APPENDIX B

33APPENDIX C—METHODOLOGY

Geologists assessed conventional undiscovered accu-mulations having technically recoverable hydrocarbons of atleast 1 million barrels of oil (MMBO) or 6 billion cubic feetof gas (BCFG) at the play level (see Gautier and Dolton,1995, for more detail). Initial play definitions were based onthe assessor’s interpretations of the geology and hydrocar-bon generation, past discovery information, and past drillinginformation. Each play definition included a description ofthe geographic location and geologic characteristics of theplay (see Gautier and others, 1995, for play descriptions). Inthe case of confirmed plays, that is plays already having dis-coveries of at least 1 MMBO or 6 BCFG, the geologistreviewed drilling penetration maps and historical discoverydata. For confirmed plays, a play probability of 1.0 wasassigned. In cases where the geologist posited a hypotheticalplay, the play probability was computed as the product of theoccurrence probabilities of the three play attributes ofcharge, reservoir, and trap. The play probability is multi-plied by conditional resource estimates, which assumed theoccurrence of the threshold quantity of oil or gas remained.

The size distribution of undiscovered accumulations foreach play was modeled with a Truncated Shifted Pareto(TSP) distribution (Houghton and others, 1993). The geolo-gist chose a median and shape class for the TSP distributionalong with the minimum (95 percent), median (50 percent),and largest (5 percent) numbers of undiscovered accumula-tions. The assessor also chose a minimum, median, and max-imum depth for remaining resources in the play. Simulationswere used to combine distributions of size and numbers ofundiscovered accumulations to generate field size-frequencydistributions and to estimate the fractiles of the quantities ofoil, associated gas, associated gas liquids, non-associatedgas, and non-associated gas liquids. For an individual prov-ince, dependencies among plays were characterized by pair-wise correlations. Simulations were used to aggregate playsto the province level.

At the province level, the size-frequency distribution ofundiscovered “small fields,” that is fields smaller than 1MMBO (or 6 BCFG), was derived with a statistical extrapo-lation procedure described by Root and Attanasi (1993). Theunderlying assumption is the province size-frequency distri-bution of small fields can be described with a log-geometricsize distribution. The minimum estimated field size of thesmallest field-size class for which numbers of fields wereestimated was 32,000 barrels oil or 192,000 cubic feet gas.

The economic analysis of province assessments usedthe discrete size-frequency distributions of expected (mean)numbers of undiscovered oil and gas fields classified by5,000-ft depth intervals. Table A-4, Appendix A, shows fieldsize classification for undiscovered conventional oil and gas

fields. Province-specific data, such as gas-to-oil ratios andnatural-gas-liquids-to-natural-gas ratios and expected sulfurlevels, were derived from data provided by the geologic playassessments. Field size, depth, regional costs, and co-prod-uct ratios as well as well-head prices and hurdle rate of returndetermine whether a new discovery will be commerciallydevelopable.

The incremental cost algorithm used a finding-ratemodel to predict, for successive increments of wildcat wells,the size distribution and depths of new oil and gas field dis-coveries at the province level. Economic analysis of thenewly discovered fields of specific size and depth categoriesis a standard application of discounted cash flow (DCF)analysis. The net after-tax cash flow consists of revenuesfrom the production of oil and (or) gas less the operatingcosts, capital costs in the year incurred, and all taxes. All newdiscoveries of a particular size and depth class are assumedto be developed if the representative field is found to be com-mercially developable, that is, if it has an after-tax netpresent value greater than zero, where the discount rateincludes a hurdle rate representing the cost of capital and theindustry’s required return. When field-production declinecauses operator income to decline to the sum of direct oper-ating costs and the operator’s production-related taxes, theeconomic limit rate is reached and field production stops.Newly discovered commercially developable fields areaggregated to provide an estimate of potential reserves fromundiscovered fields at a given price and required rate ofreturn. Additional increments of, for example, 100 wildcatwells are assumed to be drilled until the costs of drillingwildcat wells are equal to or greater than the after-tax netpresent value of the commercially developed fields discov-ered by that increment of wildcat wells.

The basis for the estimates of recoverable undiscoveredpetroleum as a function of price is that incremental units ofexploration, development, and production effort will nottake place unless the revenues expected to be received fromthe eventual production will cover the incremental costs,including a normal return on the incremental investment.Also, for the last increment of oil and gas produced from afield, operating costs (including production-related taxes)per barrel of oil equivalent are equal to price. These twoassumptions together imply that, for the commercially devel-opable resources discovered by the last economic incrementof wildcat wells, the sum of finding costs and developmentand production costs per barrel (that is, the “incremental costof the barrel”) is equal to the well-head price. Alternatively,these costs are sometimes called the marginal finding costsand the marginal development and production costs. Mar-ginal finding costs are calculated by dividing the cost of the

APPENDIX C—METHODOLOGY

UNDISCOVERED CONVENTIONAL OIL AND GAS RESOURCES

APPENDIX C


last increment of wildcat wells (which is approximatelyequal to the sum of the after-tax net present value of all com-mercially developable fields discovered in that last incre-ment of exploration) by the amount of economic resourcesdiscovered by the last increment of exploration. Marginaldevelopment and production cost per barrel (for the eco-nomic resources discovered in that last increment of explora-tion) are calculated by subtracting the incremental findingcosts from the well-head price.

Finding-rate functions were calibrated for each prov-ince (see Attanasi, Gautier, and Root, 1996, for details ofthese models). Because the size, depth, and number of undis-covered fields were calculated from the geologic assessmentdata, the finding-rate functions determined the ordering ofnew discoveries as well as the rate at which these fieldswould be found as a function of cumulative wildcats drilledin a particular depth interval. The allocations of wildcat wellsby depth interval was made in such a way that, for each incre-ment of wildcat wells evaluated, the after-tax net presentvalue of the oil and gas fields discovered was maximized.

CONTINUOUS-TYPE ACCUMULATIONS IN SANDSTONE, SHALES, CHALKS, AND COAL

Geologic assessment of technically recoverableresources required partitioning the continuous-type play intoequal-area cells equivalent either to the median drainage areaof productive wells in the play or the well spacing imposedby the State regulatory authority. Data on results of past drill-ing and estimated recoveries of wells producing from theplay were assembled, interpreted, and used to calculate theempirical drilling success ratio and the fractiles of the empir-ical distribution of estimated ultimate recoveries (EUR) ofproductive cells. With these data as a guide, the geologistsubjectively estimated a drilling success ratio for undrilledcells and assigned values to fractiles of distributions repre-senting numbers of undrilled cells, the EUR distribution ofundrilled cells expected to be productive, and depths of

undrilled cells. Estimates and distributions describing theundrilled cells were used to generate an expected discrete fre-quency-size (where size is hydrocarbon recovery) distribu-tion of productive undrilled cells for the play at 5,000-ftdepth intervals. For each play, production flow rates of wellshaving recoveries corresponding to the fractiles of the EURdistribution were modeled using historical production data,or the results of a reservoir-simulation model were calibratedby matching well histories.

The procedure for calculating incremental costs reliedon results of a discounted cash flow analysis applied to wellscorresponding to the expected or mean cell frequency-sizedistribution of undrilled cells. For a specific well-head oiland gas price and required rate of return, the after-tax netpresent value of commercially developable cells was calcu-lated. Exploration of a play at a particular depth interval isassumed to be economic if the expected aggregate after-taxnet present value of the developable cells would at least payfor the cost of exploration, that is, the cost of drilling non-commercial cells in that depth interval. If the aggregate after-tax net present value of the commercially developable cellswas sufficient to cover such costs, the aggregate resources inthe commercially developable cells would be added to theincremental cost function. Calculations were repeatedassuming progressively higher prices and aggregated bydepth intervals across plays to arrive at province incrementalcost functions. Industry, as a whole, has not generally beensuccessful in drilling the more productive cells in preferenceto the less productive cells within an individual play, so, withthe exception of target depth, no high-grading or selectivedrilling of cells within plays was assumed. The computa-tional algorithm assumed that, for the last increment ofhydrocarbons added to reserves, the sum of marginal finding,development, and production costs were approximatelyequal to the assumed well-head price. For details of the geo-logic and economic assessment methods for coal-bed gas seeRice and others (1995) and Attanasi and Rice (1995); forother continuous-type plays see Schmoker (1995) andAttanasi, Schmoker, and Quinn (1995).

35APPENDIX D—ASSESSED TECHNICALLY RECOVERABLE RESOURCES, PROVED RESERVES, AND PAST

Figures D-1 and D-2 place the quantities of assessedtechnically recoverable resources in perspective by compar-ing them to past cumulative production by USGS petroleumregion. From the bottom to the top of each bar, the figuresshow cumulative production, proved reserves, inferredreserves, and assessed technically recoverable oil and totalgas (associated and non-associated). Cumulative productionand proved reserves include conventional and assessedunconventional sources of oil and gas. Inferred reserves rep-resent the amounts of oil and gas expected to be added toreserves in pre-1992 conventional discoveries during the 80years following 1991. Items below the “zero” horizontal lineare identified technically recoverable oil and gas resources.

The assessed mean value of technically recoverable resourcesin conventional undiscovered fields and in continuous-typeaccumulations are represented by bars above the “zero” hor-izontal line.

For all regions combined, cumulative past oil produc-tion accounts for 58 percent of the total oil depicted in figureD-1 (62 pecent in regions in the lower 48 States). The areaabove the “zero” horizontal line accounts for only 12 percentof the oil, leaving 30 percent in proved reserves and projectedfield growth. For all regions combined, cumulative past gasproduction accounts for 40 percent of the gas shown in figureD-2. The area above the “zero” horizontal line accounts for35 percent of the total gas, leaving 25 percent assigned toproved reserves and field growth.

APPENDIX D—ASSESSED TECHNICALLY RECOVERABLE RESOURCES, PROVED RESERVES, AND PAST PRODUCTION

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Assessed technically recoverableundiscovered conventional and assessed unconventional oil

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Figure D-1. Estimates, as of January 1994, by petroleum region,of discovered crude oil (i.e., cumulative production and provedreserves), inferred reserves, and the combined mean estimates ofassessed technically recoverable undeveloped crude oil in undis-covered conventional oil fields and crude oil in continuous-typeoil accumulations. Bars representing discovered crude oil andinferred reserves are below the “zero” horizontal line; bars repre-senting assessed technically recoverable undeveloped crude oil inundiscovered conventional oil fields and crude oil in continuous-type oil accumulations are above the “zero” horizontal line.Petroleum regions are identified by number and name in table B-1,Appendix B.

Figure D-2. Estimates, as of January 1994, by petroleum region,of discovered gas (i.e., cumulative production and proved reserves),inferred reserves, and the combined mean estimates of assessedtechnically recoverable undeveloped gas in undiscovered conven-tional oil and gas fields, gas in continuous-type oil and gas accumu-lations, and coal-bed gas. Bars representing discovered gas andinferred reserves are below the “zero” horizontal line; bars repre-senting assessed technically recoverable undeveloped gas in undis-covered conventional oil and gas fields, gas in continuous-type oiland gas accumulations, and coal-bed gas are above the “zero” hor-izontal line. Gas does not include natural gas liquids. Petroleum re-gions are identified by number and name in table B-1, Appendix B.Inferred reserves of Region 1 include some gas discovered in theNorthern Alaska province not counted as proved reserves.

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Cumulative production

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Assessed technically recoverable undiscovered conventional andassessed unconventional gas�

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APPENDIX D

economics and the 1995 national assessment of united states oil

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