Future Supply of Oil and Gas from the 

Permian Basin of West Texas and 

Southeastern New Mexico · 

Future Supply of Oil and Gas from the 

Permian Basin of West Texas and 

Southeastern Ne\N Mexico 

A report of the Interagency Oil and Gas Supply Proiect, 

U.S. Department of the Interior and U.S. Department of Energy 

GEOLOGICAL SURVEY CIRCULAR 828 

1980 
United States Department of the Interior 

CECIL D. ANDRUS, Secretary 

Geological Survey 

H. William Menard, Director 

Library of Congress in Publication Data 

United States. Interagency Oil and Gas Supply Project. 

Future supply of oil and gas from the Permian Basin of west 

Texas and southeastern New Mexico. 

(Geological Survey circular ; 828) 

Bibliography: p. 

Supt. of Docs. no.: I 19.4/2:828) 

1. Petroleum-Texas. 2. Gas, Natural-Texas. 3. Petroleum-New Mexico. 4. Gas, Natural-New Mexico. 

I. Title. II. Series: United States. Geological Survey. Circular; 828. 

QE75.C5 no. 828 [TN872.T4] 557.3s 553.2'8'097648 

80-607115 

Free on application to Branch of Distribution, U.S. Geological Survey 

604 South Pickett Street, Alexandria, VA 22304 
PREFACE 

In 1975, the U.S. Geological Survey issued its Circular 725, entitled 

"Geological Estimates of Undiscovered Recoverable Oil and Gas Resources in 

the United States." Using advanced resource-appraisal techniques, the authors 

of that document presented new data on these resources. The results were 

essentially geological, and the economics of oil and gas recovery were not analyzed; instead, the analyses assumed the continuation of price/cost relationships 

and technological trends that prevailed before 1974. The study was not intended 

to produce schedules describing future oil and gas supply at different price levels 

and rates of return. Finally, the study specifically excluded shale oil, tar sands, 

heavy crude oil, gas from tight sandstone formations not already being produced, and oil and gas below waters that were more than 200 m deep. 

Recognizing the need to add more of an economic perspective to the estimates, 

the Interagency Oil and Gas Supply Project was established in mid-1976 to: 

evaluate any changes in resource estimates that might result from the post-197 4 

price levels; incorporate subsequent geological and geophysical information; 

prepare basin-level marginal cost schedules reflecting both conventional and 

"enhanced'' oil and gas recovery; and estimate costs for unconventional oil and 

gas sources. 

The interagency agreement (p. 56) was prepared and signed in early 1977 by 

the Department of the Interior, which included the Office of Minerals Policy and 

Research Analysis (OMPRA), the Bureau of Mines (BOM), and U.S. Geological 

Survey (USGS), as lead agency; the Federal Energy Administration (FEA); the 

Federal Power Commission (FPC); and the Energy Research and Development 

Administration (ERDA). Subsequently, the involved offices in the BOM, the 

FEA, the FPC, and ERDA became part of the Department of Energy. 

When the project was sta,:rted, no up-to-date model was available that showed 

marginal-cost schedules of the full spectrum of possible sources on a disaggregated basis. Those who prepared such schedules had difficulties in separating 

oil and gas components and in dealing with inadequate data, and the biases introduced into historical data covering price-regulated commodities. 

In spite of these difficulties, a rational effort has been made to estimate 

ultimate recovery and the associated costs. The project studies will contain 

estimates of ultimate recovery at various costs but will not contain predictions of 

the time of arrival of the supplies, because timing is determined by industry. 

With respect to timing, additional recovery becomes progressively more costly 

as the size of newly discovered fields diminishes, as they become less accessible 

geographically, and as recovery requires more advanced technology. For the 

same reasons, progressively greater effort will be required for a given level of 

production, regardless of the volume of remaining resources. Ultimately, production must decline. 

Although the areas were not defined in the agreement, the project leaders 

decided to limit the study to three areas: the Permian Basin (a mature producing 

area), the Gulf of Mexico offshore area (a partially developed area), and the 

Baltimore Canyon Basin (a frontier area). This report covers only the research 

on the Permian Basin. 

Ill 

CONTENTS 

Page 

Preface ---------------------------------------------------------------------- iii 

Executive summary ------------------------------------------------------------ 1 

Permian Basin history and characteristics ------------------------~-------------- 1 

Original oil and gas in place --------------------------------------------------- 1 

Future field-size distribution -------------------------------------------------'-- 2 

Supply from newly discovered fields -------------------------------------------- 4 

Additional supply from existing fields ------------------------------------------- 4 

Permian Basin supply-retrospect and prospect ---------------------------------- 6 

Comparison with earlier assessments ------------------------------------------- 6 

Introduction ------------------------------------------------------------------ 9 

Abbreviations and definitions ------------------------------------------------- 9 

Resource classification ------------------------------------------------------- 9 

Explanatory note----------------------------------------------------------- 10 

Sensitivity to prices and costs ------------------------------------------------- 11 

The Permian Basin pilot area ------------------------------------------------- 12 

Approach and general methodology -------------------------------------------- 12 

Undiscovered resource appraisal ---------------------------------------------- 12 

Discovery-process model ----------------------------------------------------- 13 

Engineering and cost analysis for future fields ----------------------------------- 13 

The integrating economic model_______________________________________________ 13 

Additional oil from known fields ----------------------------------------------- 13 

Indicated and inferred reserves ----------------------------------------------- 13 

Enhanced oil and gas recovery ------------------------------------------------ 13 

Other occurrences ---------------------------------------------------------- 14 

Future production of undiscovered oil and gas from tHe Permian Basin------------------- 14 

Permian Basin resource appraisal ---------------------------------------------- 14 

Geology --------------------------------------------------------------- 14 

Analysis and assessment-------------------------------------------------- 15 

Geologic analyses -------------------------------------------------------- 17 

Statistical analysis ------------------------------------------------------- 18 

Subjective probability procedures ------------------------------------------ 18 

Methods for pool-size assessment ------------------------------------------- 18 

Summary results-------------------------------------------------------- 19 

The discovery-process model -------------------------------------------------- 20 

Expressing the data in depth intervals--------------------------------------- 21 

Form of the model ------------------------------------------------------- 22 

Forecasting future rates of recovery ---------------------------------------- 25 

Conclusions ------------------------------------------------------------ 26 

Engineering and cost analysis for future fields----------------------------------- 28 

Exploration costs -------------------------------------------------------- 29 

Field design and investment costs ------------------------------------------ 29 

Production schedules and production costs ----------------------------------- 33 

Assumptions for present value calculations ----------------------------------- 36 

Estimated marginal cost functions for undiscovered recoverable oil and gas resources 

in the Permian Basin ------------------------------------------------------- 3 7 

Methodology ----------------------------------------------------------- 39 

Summary of results------------------------------------------------------ 41 

Conclusion ------------------------------------------------------------- 44 

Additional supplies from known fields ---------------------------------------------- 44 

Estimates of indicated and inferred reserves------------------------------------- 44 

Indicated reserves ------------------------------------------------------- 46 

Inferredreserves________________________________________________________ 46 

General outline of data and methods ---------------------------------------- 4 7 

Method of analysis ------------------------------------------------------- 48 

A variation on the method of analysis ---------------------------------------- 50 

Summary -------------------------------------------------------------- 50 

v 
Page 

Enhanced oil and gas recovery---------------------------------------------------- 50 

Enhanced oil recovery------------------------------------------------------- 50 ~ethodology_______________________________________________________________ 51 

Enhanced gas recovery------------------------------------------------------ 52 

Expanded production from known fields: an appraisal of results------------------------- 53 

Notes on methodology ----------------------------------------------------------- 54 

Interagency agreement for an oil and gas supply project------------------------------- 56 

Participants in the project------------------------------------------------------- 57 

References cited --------------------------------------------------------------- 58 

ILLUSTRATIONS 

FIGURE 1. ~ap showing oil and gas fields in the Permian Basin ------------------------------------------------- 2-6. Graphs showing: 

2. Original oil and natural gas in place in the Permian Basin-----------------------------------------

3. Undiscovered oil and natural gas in place in the Permian Basin ------------------------------------

4. Fuel supply from future discoveries in the Permian Basin----------------------------------------

5. Fuel supply from future discoveries in the Permian Basin by commodity----------------------------

6. Potential new supplies of oil and gas in the Permian Basin ----------------------------------------

7. Resource classification diagram, total resources ----------------------------------------------------

8. Map showing structural elements in the Permian Basin ---------------------------------------------- 9-32. Graphs showing: 

9. Historic finding rate for oil, 1920-74, Permian Basin--------------------------------------------

10. Historic finding rate for nonassociated natural gas, 1920-7 4, Permian Basin -------------------------

11. Probability distribution of the total Paleozoic undiscovered oil in place, aggregated for depths of0-20,000feet _______________________________________________________________________ _ 

12. Probability distribution of total Paleozoic undiscovered dissolved and associated gas in place, aggregated fordepthsof0-20,000feet ______________________________________________________________ _ 

13. Probability distribution of total Paleozoic undiscovered nonassociated gas in place, aggregated for depths 

of 0-30,000 feet------------------------------------------------------------------------

14. Probability distribution of total Paleozoic undiscovered gas (dissolved, associated, nonassocizted) in place, 

aggregated for depths of 0-30,000 feet-----------------------------------------------------

15. Lognormal-probability size distribution of undiscovered Permian oil pools in depths of 0-10,000 and 

10,000-20,000 feet --------------------------------------------------------------------- 16. Lognormal-probability size distribution of undiscovered Carboniferous oil pools in depths of 0-10,000 and 

10,000-20,000 and 10,000-20,000 feet-----------------------------------------------------

17. Lognormal-probability size distribution of undiscovered nonassociated Carboniferous gas po'lls in depths 

of 0-10,000, 10,000-20,000, and deeper than 20,000 feet---------------------------------------

18. Average depth of exploratory wells as a function of cumulative exploratory wells drilled in the Permian 

Basin -------------------------------------------------------------------------------- 19. Exploratory well drilling and equipping costs as a function of well depth in the Permian Basin in 1975 ___ _ 

20. Total exploration cost per exploratory well (minus cost of acquiring undeveloped acreage) as a function of 

drilling cost per well in 1977 --------------------------------------------------------------

21. Drilling and equipping cost per development well versus depth in the Permian Basin in 1975------------

22. Cost of development of dry hole versus depth in the Permian Basin in 1975 --------------------------

23. Lease equipment cost per well versus depth for primary oil production in the Permian Basin in 1976 ____ _ 

24. Oil-production-decline curves for primary recovery at 7,200 feet in the Permian Basin-----------------

25. Percent of expected ultimate gas recovery as a function of percent of expected ultimate oil recovery in the 

Permian Basin ------------------------------------------------------------------------- 26. Nonassociated gas-well-production curve for a class 13 field in the depth bracket of 0-5,000 feet in the 

Permian Basin ------------------.... ------------------------------------------------------ 27. Annual direct operating cost per producing oil well versus depth for primary recovery in th~ Permian 

Basin in 1976-------------------.... ------------------------------------------------------ 28. Annual direct operating cost per producing oil well versus depth for secondary recovery in the Permian 

Basin in 1976--------------------------------------------------------------------------

29. Exploratory wells projected to be drilled in the Permian Basin as a function of price of oil anct gas and rate 

ofreturnoninvestment ________________________________________________________________ _ 

30. Marginal cost of recoverable oil and gas resources from undiscovered deposits in the Permian Basin- 5 

percent discounted cash-flow rate of return-------------------------------------------------

31. Marginal cost of recoverable oil and gas resources from undiscovered deposits in the Permian Basin -15 

percent discounted cash-flow rate of return-------------------------------------------------

32. Marginal cost of recoverable oil and gas resources from undiscovered deposits in the Permian Basin- 25 

.Percent discounted cash-flow rate of return -------------------------------------------------

VI 

Page 

3 

4 

6 

7 

8 

10 

16 

18 

19 

21 

22 

23 

24 

25 

25 

26 

29 

30 

31 

34 

36 

37 

38 

39 

40 

41 

42 

44 

45 

46 

47 
Page 

FIGURE 33. Diagram of production, reserves, and residual oil in place in the Permian Basin, exclusive of "Spraberry'' TT~end, 

December 31, 1977 ------------------------------------------------------------------------ 51 

34. Map showing areas of the Permian Basin for enhanced gas recovery------------------------------------ 53 

TABLES 

Page 

TABLE 1. Future exploration drilling and supply from undiscovered recoverable oil and gas resources in the Permir'l 

Basin ----------------------------------------------------------------------------------- 5 

2. Potential for enhanced recovery in the Permian Basin ----------------------------------------------- 5 

3. Potential new recoverable supplies of oil and gas from the Permian Basin-------------------------------- 7 

4. Discovered oil and gas in place, Permian Basin (1921-December 31, 1974) ------------------------------- 15 

5-7. Estimates of: 

5. Total undiscovered hydrocarbons in place ----------------------------------------------------- 20 

6. Undiscovered hydrocarbons in place by depth interval___________________________________________ 20 

7. Mean depths of occurrence of undiscovered hydrocarbons in place- all Paleozoic systems --------------- 20 

8. Field-size classes ----------------------------------------------------------------------------- 22 

9. Comparison of the numbers of discoveries through 1974 with the number forecast, keyed on the pre-1961 discovery and exploratory drilling data in the 0-5,000-foot depth interval--------------------------·---- 24 

10-13. Expected ultimate number of fields remaining to be discovered after 1974: 

10. In the 0-5,000-foot depth interval___________________________________________________________ 27 

11. In the 5,000-10,000-foot depth interval_______________________________________________________ 27 

12. In the 10,000-15,000-foot depth interval______________________________________________________ 27 

13. In the 15,000-20,000-foot depth interval ------------------------------------------------------ 28 

14. Number of discoveries expected to be made in each size class with the first increment of 1,000 exploratory holes 

drilled in the Permian Basin after 1974-------------------------------------------------------- 28 

15. Ratio of oil fields to total fields in the Permian Basin------------------------------------------------- 30 

16. Expected ultimate oil recovery per field in the Permian Basin----------------------------------------- 30 

17. Expected ultimate oil recovery per well from primary oil fields in the Permian Basin----------------------- 31 

18. Expected ultimate associated-dissolved gas recovery per oil well from primary fields in the Permian Basin_____ 31 

19. Expected ultimate oil recovery per well from secondary and pressure maintenance fields in the Permian Basin_ 32 

20. Expected ultimate gas recovery per oil well from secondary and pressure maintenance fields in the Permb.n 

Basin ----------------------------------------------------------------------------------- 32 

21. Expected ultimate nonassociated gas recovery per field in the Permian Basin---------------------------- 32 

22. Expected ultimate nonassociated gas recovery per well in the Permian Basin----------------------------- 32 

23. Ratio of primary oil fields to total oil fields in the Permian Basin --------------------------------------- 32 

24. Cost of lease equipment per nonassociated gas development well in the Permian Basin in 1977 dollars--------- 33 

25. Exponential oil-well decline rates per year in the Permian Basin-------------------------------------- 34 

26. Annual direct operating expenses for nonassociated gas wells in the Permian Basin in 1977 dollars----------- 36 

27. Potential recoverable oil and gas resources from future discoveries in the Permian Basin as a function of output 

price, marginal finding cost, marginal production cost, exploratory wells, and return on investment _______ 43 

28. Growth in estimates of original oil in place for the Permian Basin -------------------------------------- 48 

29. Growth in estimates of recoverable natural gas for the Permian Basin---------------------------------- 49 

30. Classification of sample reservoirs selected for enhanced oil recovery in the Permian Basin----------------- 52 

31. Enhanced oil recovery potential of the Permian Basin------------------------------------------------ 52 

32. Enhanced gas recovery potential of the Permian Basin----------------------------------------------- 53 

vii 

FUTURE SUPPLY OF OIL AND GAS FROM THE PERMIAN BASIN OF 

WEST TEXAS AND SOUTHEASTERN NEW MEXICO 

A REPORT OF THE INTERAGENCY OIL AND GAS SUPPLY PROJECT, 

U.S. DEPARTMENT OF THE INTERIOR AND U.S. DEPARTMENT OF ENERGY 

EXECUTIVE SUMMARY 

In mid-1976, the Interagency Oil and Gas Supply Project was 

established, by agreement among several Federal agencies to 

estimate how much oil and gas might be made available in the 

future at various price levels from all potential sources in the 

United States. The scope of investigation includes supplies of oil 

and gas from presently known fields through additional drilling 

and enhanced-recovery methods, from fields not yet discovered, 

and from a variety of sources categorized as "unconventional" 

(such as oil shale, tar sands, and gas from coal beds and 

geopressured brines). Liquid and gaseous fuels synthesized 

from coal or other substances are not considered. 

The project, with the U.S. Geological Survey as lead agency, 

is designed to extend the analysis described in U.S. Geological 

Survey Circular 725 (Miller and others, 1975) by incorporating 

new geological and geophysical data, by supplying an economic 

perspective, and by addressing the outlook for enhanced 

recovery and unconventional sources not treated in the earlier 

study. As a prelude to a nationwide assessment, three areas 

were selected for study on a test basis: the Permian Basin of 

west Texas and southeastern New Mexico (a mature producing 

area), the Gulf of Mexico offshore (a partly developed basin), and 

the Baltimore Canyon Basin of the Atlantic Outer Continental 

Shelf (a frontier area). This report analyzes the oil and gas prospects of the Permian Basin. The basin is shown in figure 1 in 

relation to western Texas and eastern New Mexico, Region 5 in 

Circular 725. The Permian Basin covers roughly 50 percent of 

the 173,000 square-mile total area of Region 5. 

The report begins with a survey of known resources of oil and 

gas in the Permian Basin1 from which an estimate is made of the 

tptal amount of oil and gas discovered by the end of December 

1974. Next, estimates are made of the amounts of undiscovered 

oil and gas thought to exist at various levels of probability; these 

data include the number of reservoirs estimated to exist in each 

of 20 size classes and in three successive depth intervals of 

10,000 feet each. After this appraisal of the basin's original endowment of oil and gas, both discovered and undiscovered, a 

projection is made of the most likely sequence in which the undiscovered reservoirs may be found and the amount of exploratory drilling that will be required to find them. Exploration, development, and production costs are then introduced 

and are used to obtain estimates of the volumes of undiscovered 

oil and gas that will actually be found and produced at different 

assumed price levels and rates of return. 

In addition to supply from new discoveries, relatively large 

amounts of oil and gas are expected to be produced from 

presently known fields, either through drilling that extends field 

limits or penetrates new pools within the field, or from new 

technologies that enable recovery of a greater fraction of the 

original oil or gas in the field than that which can now be 

1 The Permian Basin corresponds closely, but not exactly, to the area designated by 

the Texas Railroad Commission as Districts 7C, 8, and 8A, plus that designated as 

southeast New Mexico by the American Petroleum Institute and the American Gas 

Association. As a matter of convenience in this report, it is considered identical with 

these districts, unless otherwise specified. 

1 

recovered through conventional techniques. The volume of 

hydrocarbons obtained from such enhanced-recovery measures 

is estimated for different price levels and rates of re';urn in the 

same manner that volumes of undiscovered oil ard gas are 

estimated. 

PERMIAN BASIN HISTORY AND CHARACTE.RISTICS 

The Permian Basin is a mature petroleum-producing province 

extending over about 80,000 square miles of west Texas and 

southeastern New Mexico; its sedimentary rocks are more than 

25,000 feet thick in its deepest parts. The basin is chrracterized 

by arches, platforms, basins, and shelves formed during the 

later Paleozoic periods; the Midland, Delaware, and Val Verde 

Basins and the Central Basin Platform are of particular interest. 

The Permian Basin has been a prolific source of petroleum 

hydrocarbons since the initial discoveries were made in 1921. 

Production to the end of 1976 amounted to 18.6 billior barrels of 

crude oil and 55.8 trillion cubic feet of natural gas; 5.5 billion 

barrels and 18.2 trillion cubic feet remained as proved reserves 

on that date. Virtually all the petroleum was found ir Paleozoic 

sediments, most (71 percent) of the oil being in the relatively 

shallow Permian rocks and most of the nonassociated gas, in 

deeper strata of Devonian age and older. Oil has been produced 

from wells that are deeper than 14,000 feet, and ga~ has been 

produced from depths of more than 21,000 feet. Although carbonate reservoirs predominate in this province, large quantities 

of both oil and gas have been found in sandstone formations. 

Distribution of hydrocarbons is roughly equal in structural and 

in stratigraphic traps. 

The oil and gas resources of the Permian Basin are for all 

practical purposes confined to those occurring as co"1ventional 

accumulations, including those amounts requirir~ special 

recovery techniques to produce. Present data indicate that little, if any, oil and gas are available from oil shale, brown or 

black shale, rich in organic matter, tar sand, asphalt, heavy oil, 

and no methane is available in brines or hydrates; no supply 

from such sources is expected in the foreseeable future. 

ORIGINAL OIL AND GAS IN PLACE 

Discovered deposits as of December 31, 1974, were estimated 

to be 92 billion barrels of oil and 108 trillion cubic feet of natural 

gas, distributed as shown in figure 2. Of these volumef',. about 26 

percent of the oil and 75 percent of the gas are expected to be 

recovered under present economics and technology. Although 

these percentages may increase somewhat as anticipated improvements in recovery techniques are made, most of the oil 

and some of the gas will always be too difficult or too costly to 

produce and cannot be considered recoverable resources. 

The amount of oil and gas remaining to be discovered in the 

Permian Basin has been appraised on the basis of (1) an intensive review of basin geology, (2) a statistical analysis of 

discovery experience, and (3) the application of professional 

judgment to obtain estimates of oil and gas in place at each of 

various levels of probability (95, 75, 25, and 5 perce:-1t), plus a 
101° 100° ggo 98~ 

50 100 MILES 

0 50 100 KILOMETERS 

~ Study area -.-- Boundary, USGS Region 5 -lfiJ Oil/gas field 

FIGURE 1. -Oil and gas fields in the Permian Basin. 

modal estimate and a calculated statistical mean for each of 

three successive depth intervals of 10,000 feet. These estimates 

were then aggregated by means of Monte Carlo techniques into 

totals for the basin by depth interval. The mean values for each 

depth interval, plus the values estimated for the 95- and 

5-percent probability levels are shown graphically in figure 3. A 

comparison of the mean values of undiscovered oil and gas with 

the discovered amounts (see fig. 2) suggests that almost 95 percent of the oil and 83 percent of the gas originally contained in 

the Permian Basin may already have been found. 

2 

FUTURE FIELD-SIZE DISTRIBUTION 

The Permian Basin has long been the focm of an intensive 

search, which has resulted in the discovery of 4,036 oil and gas 

fields by 30,340 exploratory wells drilled from 1921 through 

1974. The province shows a typical distribution pattern of fields 

by size and number. A very few very large fields are at one end 

of a spectrum that trends toward successively greater numbers 

of smaller and smaller fields, so that most of the basin's oil and 

gas is concentrated in a relatively few large fie1

ris. For example, 
100 100 

91.6 

Iw 

80 w 80 u.. 

~ (/) CD ....J 

w :::> 

u a: 

a: u.. <t 60.8 0 CD 60 60 PERMIAN (/) u.. z 0 0 (/) 47.6 ::::i 

z ....J 

0 a: ::::i I-

::::! 

CD 40 40 ~ 

z u) 

<t ....J- (.!) 

0 ....J 

<t 

CARBONIFEROUS a: 20 20 :::> 

I-

<t 

z 

OLDER 

PALEOZOIC 

0 0 OIL ASSOCIATED I NONASSOCIATED 

DISSOLVED 

NATURAL GAS 

FIGURE 2.-0riginal oil and natural gas in place in the Permian Basin. 

59 percent of the recoverable crude oil discovered in the Permian Basin has been found in 97 major fields. 

This distribution, which is assumed to be characteristic of the 

total petroleum content of the basin, permits a calculation, by 

size class, of the number of fields that remain to be discovered. 

These forecasts are made by means of a method proposed by 

Arps and Roberts (1958), which assumes that the probability of 

the next exploratory well finding a field of a given size is proportional to the ratio of the area of the field to the area of the basin. 

This assumes that the discovery of the larger fields will be made 

early in the search, so that as exploration proceeds, the average 

size of newly discovered fields diminishes. The Arps-Roberts 

model was modified to accommodate the features peculiar to the 

Permian Basin and was applied to estimate the number of remaining undiscovered fields in 20 size classes ranging from 

fields containing less than 6,000 barrels of oil equivalent (BOE) 2 

to those containing from 1.6 to 3.1 billion BOE. Four successive 

5,000-foot depth intervals from the surface down to 20,000 feet 

were considered. 

When applied to the Permian Basin, this discovery-process 

model predicted that some 34,000 oil and gas fields remain to be 

discovered at depths of less than 20,000 feet, 98 percent of 

which are expected to cont<tin less than 1.52 million recoverable 

BOE per field. Six-hundred eighty-two fields are expected to 

range in size from 1.52 to 12.14 million BOE, preponderantly at 

depths of less than 10,000 feet. Twenty-one fields ranging from 

12.14 to 48.6 million BOE in size are thought to be distributed 

2 Includes crude oil, natural gas, or any combination of the two, counting wet 

natural gas and its entrained liquids; natural gas being assumed to contain 1.1 million 

Btu per l ,000 cubic feet and crude oil, 5.8 million Btu per barrel. 

3 

fairly evenly among the three deeper intervals (5,000-20,000 

ft), and seven fields of more than 48.6 million BOE in size are 

predicted to be almost entirely in the 15,000- 20,000-foot depth 

interval. In fact, no fields of as much as 100 million BOE are expected to be found at depths of less than 15,000 feet. 

The model was also used to predict the number of fields by 

size class and depth interval that would be discovered by each of 

20 successive drilling increments of 1,000 exploratory wells. In 

general, the discovery results confirmed the field-size distribution computed by means of the model in the earlier exercise: in 

the first 1,000-well drilling increment, no fields larger than 

12.14 million BOE were expected to be found in the highly explored 0-5,000-foot interval; in the second and third intervals, 

fields to a maximum of 97.2 million BOE were expected to be 

found, and in the deepest (15,000-20,000-ft) interval, fields 

ranging in size classes from 97.2 to 388.6 million BOE were expected to be found. Analysis of the 19 other increments revealed 

similar patterns. Moreover, the total number of discoveries per 

increment was observed to decline, and larger discoveries 

became less frequent. Thus, both success ratio and average size 

of discoveries were projected to decline with each successive 

1,000-well increment of exploratory drilling. 

The results just described are the product of a purely 

statistical exercise to ascertain the numbers and sizes of fields 

that a 20,000-well exploratory drilling program could 

theoretically be expected to find among the remaining undiscovered oil and gas accumulations in the Permian Basin. Considered together with appropriate economic and engineering 

factors, these results can be useful in projecting how much oil 

and gas are likely to be found as the result of industry decisions 

to drill and produce. 
OIL 

10 

5% 

(/) EXPLANATION ...J 

NATURAL GAS 

ASSOCIATED 

AND 

DISSOLVED 

NONASSOCIATED 25 

20 

1-

w 

15 w 

u. 

~ 

al 

::J 

u w 5%, 95%=Volumes estimated at 5 percent a: z a: M and 95 percent probability M 0 <( M Statistical mean value ::::i al 5 10 ...J 

z a: 0 1-

::::i 

...J 

al 5% 

5 

0 

CHO 1Q-20 

DEPTH, IN THOUSANDS OF FEET DEPTH, IN THOUSANDS OF FEET 

FIGURE 3.- Undiscovered oil and natural gas in place in the Permian Basin. 

SUPPLY FROM NEWLY DISCOVERED FIELDS 

Translating estimates of undiscovered oil and gas into producible reserves requires the introduction of economic considerations that determine whether the capital needed to bring 

those resources to market will, in fact, be invested. In the study, 

this was done in two steps. In the first step, field development 

and production costs were estimated. Then, in the second step, a 

discounted cash-flow analysis was used to estimate the amounts 

of undiscovered oil and gas that the oil industry would find and 

produce at different market prices and rates of return that were 

based on development and production costs. The results of the 

analysis are summarized in table 1 in terms of exploratory wells 

drilled and economically producible hydrocarbons discovered at 

each price level and rate of return. 

The data presented in the tables indicate the mature stage of 

exploration in the Permian Basin and the response of supply, 

both to exploration effort and to price. The 30,000 exploratory 

wells projected to be drilled at $40 per BOE under a 25 percent 

rate of return are predicted to result in the discovery of 3.85 

billion BOE, an amount approximately one-tenth of the volume 

of oil and gas found by the first 30,000 exploratory holes drilled 

in the basin. Table 1 also shows that, at all rates of return, 

discovery response to price diminishes sharply at prices greater 

than $25 per BOE. For example, in figure 4, which shows 

discoveries at a 15 percent rate of return, the first $15 increment above the base of $10 elicits a 185-percent increase in supply; the second increment of $15 yields an increase of less than 

25 percent. 

4 

Another notable feature is the preponderance of natural gas, 

which constitutes approximately two-thirds of the energy value 

of the hydrocarbons projected to be discovered (see fig. 5). This 

distribution is almost the reverse of that shown by discovery experience through 1974, when crude oil constituted two-thirds of 

the total hydrocarbons found. 

ADDITIONAL SUPPLY FROM EXISTING FIELDS 

In addition to the oil and gas from future discoveries, substantial amounts of both are expected to be produced from already 

discovered fields, in addition to the amounts presently 

estimated to be recoverable. These "bonus" amounts result from 

(1) tlw fact that the larger oil and gas fields routinely "grow" 

from year to year as field limits are extended by drilling, new 

pools are found within fields, and additinal information about 

the field permits the upward revision of previous estimates; 3 

and (2) technological improvements in recovery operations that 

permit a larger fraction of the total resources in the ground to 

be produced than that previously expected. 

The fact has long been accepted that many fields are actually 

bigger than estimates have indicated. Accounting for proved 

reserves-oil and gas that can definitely be produced from a 

field on the basis of existing economics and technology- is 

necessarily conservative and includes only resources under 

acreage that can be drained by existing wells and in the 

3 However, such additional data may also result in a downward revision of previous 

estimates. 
TABLE 1.-Future exploration drilling and supply from undiscovered recoverable oil and gas resources in the Permian 

Basin 

[BOE, barrels of oil equivalent] 

Output Wells Wells Wells 

price drilled BOE drilled BOE drilled BOE ($/BOE) (thou- (billions) (thou- (billions) (thou- (billions) 

sands) sands) sands) 

5 percent rate of 15 percent rate of 25 percent rate of return return return 

10 ------------ 10 2.04 5 1.20 2 0.54 15 ------------ 19 3.03 12 2.32 8 1.77 20 ------------ 26 3.57 18 2.95 12 2.33 25 ------------ 33 4.00 24 3.44 17 2.87 30 ------------ 38 4.27 29 3.77 22 3.30 35 ------------ 43 4.50 34 4.08 26 3.60 40 ------------ 48 4.71 38 4.28 30 3.85 

immediately adjoining undrilled parts that are judged to be productive on the basis of geologic and engineering data. In 1966, 

for example, the American Petroleum Institute (1967) 

estimated that the total amount of oil that might be recovered 

from all fields discovered by that date was 112 billion barrels. 

By 1976, the estimate for these fields had been raised to 129 

billion barrels- a "growth" of 17 billion barrels that resulted 

chiefly from field extension and development over the intervening decade. 

This "growth" phenomenon has resulted in efforts to predict 

the amounts of oil and gas that eventually may be found and 

produced from existing fields, beyond the proved reserves 

credited to them at any given date. These incremental amounts 

of oil and gas that are expected to become proved reserves at 

some future time are categorized as being either "indicated" or 

"inferred" reserves, depending largely upon the means by which 

they are expected to be converted into proved reserves. 

Indicated reserves are those volumes of oil that are expected 

to be economically recoverable by means of improved conventional recovery techniques, such as fluid injection, where (1) an 

improved technique has been installed but its effect cannot yet 

be fully evaluated, or (2) an improved technique has not been installed but enough is known about its probably success to justify 

estimates of the volume of oil that might be made available by 

such means. According to the American Petroleum Institute 

(American Gas Associates and others, 1977, table 1), these "in-· 

dicated additional" reserves in the four districts approximating 

the Permian Basin amounted to 1.6 billion barrels of 

recoverable crude oil as of December 31, 1976. 

Inferred reserves are those that accrue through additional 

drilling and upward revisions of previous estimates justified by 

additional knowledge about existing fields. The process for 

estimating inferred reserves is more reliable for large areas 

such as the United States as a whole than for smaller, specific 

regions such as the Permian Basin. Nevertheless, estimates for 

inferred reserves, which were based on two separate approaches, suggest that an additional 7.1 trillion cubic feet of 

recoverable gas (1.35 billion BOE) and an additional 4.9 billion 

barrels of crude oil in place exist as inferred reserves in the Permian Basin. At the current recovery rate of 26 percent, an additional 1.3 billion barrels of recoverable oil may be derived from 

this source. This means that 2.65 billion BOE of petroleum 

hydrocarbons, which include the gas reserves, are estimated to 

exist as inferred reserves in the Permian Basin. 

Enhanced recovery (that is, recovery techniques going beyond 

the conventional methods now in use) represents the other major opportunity for additional supply from existing fields. 

Enhanced Oil Recovery (EOR) has already resulted in some 300 

million barrels that have been produced or proven in a few large 

5 

reservoirs in the Permian Basin (such as the Scurry Area 

Canyon Reef Operators Committee (SACROC) carbon dioxide 

project in the Kelly-Snyder field). If, for example, the anticipated recoverable fraction of the Permian Basin's 92 billion 

barrels of original oil in place could be increased from the current average of 26 percent to 31 percent, an additional 4.6 

billion barrels of oil would become available. Production of this 

oil will be neither easy nor cheap because many institutional, 

technical, and economic difficulties bar the way. Still, the oil is 

known to exist, most of the infrastructure needed to bring it to 

market is already in place, and sizeable commitments have been 

made by both the public and the private sectors toward the goal 

of moving it into the proved reserves category. 

This study assumes that satisfactory solutions will eventually 

be found for the problems that presently beset the prospects for 

EOR. Estimates, therefore, were made of the amounts of oil 

that might become available, mainly through carbon dioxide 

flooding, at different price levels and rates of return, from 96 

major reservoirs thought to be technically and economically 

amenable to EOR techniques. The results were extrapolated to 

obtain values for the total basin and are presented in table 2. 

For both the 15- and 25-percent rates of the return, supply 

response to price diminishes sharply when prices are more than 

$25 a barrel. 

TABLE 2.-Potential for enhanced recovery in the 

Permian Basin 

1977 price 

t$180E) 

10---------------

15---------------

20 ---------------

25 ---------------

30 ---------------

35 ---------------

40 ---------------

[BOE, barrels of oil equivalent] 

Oil Gas 

(billion barrels) (trillion cubic feet) 

15 percent 25 percent 15 percent 25 percent 

rate of rate of rate of rate of 

return return return return 

0.0 0.0 8.9 7.4 

1.43 0.20 13.7 13.7 

2.93 1.30 13.7 13.7 

4.31 2.58 13.7 13.7 

4.70 3.65 13.7 13.7 

5.08 4.11 13.7 13.7 

5.11 4.56 13.7 13.7 

The prospects for enhanced gas recovery (EGR) offer the 

possibility for a significant contribution to future gas supply 

from the Permian Basin. The target is previously discovered 

nonassociated gas accumulations in rocks of low permeability 

that have thus far defied economic production by traditional 

methods. Rising gas prices and recent improvements in production technology may provide the means to convert part of these 

known but presently subeconomic resources into proved 

reserves. 

The geographic focus for EGR in the Permian Basin is in its 

southeastern corner in three Texas counties. Within this area lie 

known gas accumulations that can be considered candidates for 

massive hydraulic fracturing (MHF), in which pressure is as 

much as 10 times greater than that used in conventional 

hydraulic fracturing that has long been used to introduce cracks 

in reservoir rock to facilitate the flow of oil and gas to the well 

bore. 

Data were analyzed to ascertain the amounts of gas that these 

prospective gas fields might be expected to yield under MHF at 

two rates of return and several price levels (see table 2). The exercise shows that at a price of $15 or more per BOE, as much as 

13.7 trillion cubic feet of gas might become available under currently available MHF technology. 
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10 15 20 25 

PRICE, IN DOLLARS PER BARREL OF OIL EQUIVALENT 

FIGURE 4.- Fuel supply from future discoveries in the Permian Basin. 

PERMIAN BASIN SUPPLY-RETROSPECT 

AND PROSPECT 

As the result of 6 decades of exploration and development, 24 

billion barrels of recoverable crude oil and 7 4 trillion cubic feet 

of recoverable natural gas had been found in the Permian Basin 

as of December 31, 1974. By comparison, the analysis of data 

from this project indicates a potential future supply of 3 billion 

to 9 billion barrels of crude oil and 20 trillion to 37 trillion cubic 

feet of natural gas from all sources, a 15-percent rate of return 

and at a price range of $10 to $40 per BOE. At a 5-percent rate 

of return, these amounts would be somewhat higher, and at a 25-

percent rate, somewhat lower. Supply responsiveness falls off 

quickly when prices are more than $25 per BOE for both oil and 

gas. Table 3 recapitulates the supply of oil and gas available 

from each source at prices of $10, $15, $25, and $40 per BOE at 

a 15-percent rate of return. Figure 6 represents these values 

graphically. 

The prospect for additional oil from new discoveries is limited. 

Even at $40 a barrel, no more than 1.3 billion barrels is projected-about 17 percent of the amount expected to be 

6 

recovered from existing fields and barely 5 percent of the 24 

billion barrels discovered previously. By far, the greater part of 

future oil supply from the Permian Basin is expected to co~e 

from already discovered fields, primarily from indicated and ~~­

ferred reserves at the lower price ranges, and from enhanced 01! 

recovery at prices of $25 or more per BOE. 

The outlook for new discoveries of natural gas is better than 

that for oil at all price levels, mainly because of the greater· 

probabilities of finding large accumulations in those stra~ 

where gas is likely to be found, that is, below 15,000 feet m 

depth. Even so, however, new discoveries are expected to account for less than half the future supply of gas from the Permian Basin. Slightly more than 7 trillion cubic feet is expected 

from inferred reserves, and as much as almost 14 trillion cubic 

feet is optimistically projected from enhanced-gas-recovery 

projects in the tight sands of the basin at prices of $15 and more 

per BOE. 

COMPARISON WITH EARLIER ASSESSMENTS 

The results of the Permian Basin study cannot be directly 

compared with those of other assessments of the petroleum 

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PRICE, IN DOLLARS PER BARREL OF OIL EQUIVALENT 

FIGURE 5.-Fuel supply from future discoveries in the Permian Basin by commomty. 

potential of this general region because the areas considered are 

not identical. Nevertheless, the expectations from the current 

study are drastically lower than those indicated by previous 

estimates. Specifically, the estimate given in U.S. Geological 

Survey Circular 725 for Region 5's inferred and indicated 

reserves, plus the statistical mean for undiscovered recoverable 

resources is roughly five times the amount estimated in this 

study to be available from the Permian Basin at $25 per BOE 

and a 15-percent assumed rate of return. Although the Permian 

Basin constitutes only about half the area of Region 5, it has 

accounted for approximately 80 percent of all oil and gas 

discovered in that region to date. Therefore, only a small part of 

the large discrepancy between the two estimates can be attributed to geography; most of it has to be reckoned as a 

downward revision of resources ascribed to the Permian Basin 

in Circular 725. 

The reasons for the differences are mostly due to the use of 

different data, different assessment methodologies, and a more 

thorough assessment of petroleum-exploration possibilities. In 

the Circular 725 assessment, only volumetric-yield or areal-yield 

TABLE 3. - Potential new recoverable supplies of oil and gas from the Permian Basin 

1977 price ($/BOE) 

10 ------------

15 ------------

25 ------------

40 -------- ----

[At a 15 percent rate of return; BOE, barrels of oil equivalent; EOR, enhanced oil recovery; EGR, enhanced gas recovery] 

Crude oil Natural gas Total 

(billion barrels) (trillion cubic feet) (billion BOE) 

Indicated Inferred New Inferred New Indicated Inferred EOR plus New reserves reserves EOR discoveries Total reserves EGR discoveries Total reserves reserves EGR discoveries 

1.6 1.1 0.0 0.26 2.96 7.1 8.9 4.98 20.08 1.6 2.5 1.69 1.20 

1.6 1.1 1.34 .58 4.62 7.1 13.7 9.17 29.97 1.6 2.5 3.94 2.32 

1.6 1.1 4.31 .97 7.98 7.1 13.7 13.02 33.82 1.6 2.5 6.91 3.44 

1.6 1.1 5.11 1.28 9.09 7.1 13.7 15.81 36.61 1.6 2.5 7.71 4.28 

7 

Total 

6.99 

10.36 

14.45 

16.09 
25 

20 

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CRUDE OIL 

NATURAL GAS 

NEW 

DISCOVERIES 

ENHANCED OIL 

RECOVERY 

O ___.____._~ T--'-'-'-----'"' 1 0 

PRODUCTION FUTURE SUPPLY BASED ON PRICE PER BARREL 

AND PROVED OF OIL EQUIVALENT (1977 DOLLARS) RESERVES 

1921-74 

FIGUI{E 6.- Potential new supplies of oil and gas in the Permian Basin 

8 
analytical techniques were used. In the more recent assessment 

made here, a comprehensive field and pool data file was used, 

and abundant drilling and finding-rate studies were conducted 

along with a thorough review of the geology by stratigraphic 

units. The net result was a sharper perspective on the 

petroleum potential of this mature province and, possibly, a 

inore reliable estimate. As has been illustrated by the 

differences between this study and Circular 725, reassessments 

can be expected to change over time as significant new data are 

acquired and new methods are used. These innovations, 

however, will not necessarily result in decreased assessments. 

Accordingly, to extrapolate a reduced expectation nationwide 

from the reduced assessment of the Permian Basin is not appropriate. The planned future assessments for other areas may 

be more optimistic than those offered previously as a result of 

new information or the application of different methodologies. 

INTRODUCTION 

This report is divided into two main parts to 

clearly distinguish between the methods used and 

the precision of the results attained. The first part 

deals exclusively with undiscovered oil and gas in 

conventional oil and gas reservoirs. Such 

petroleum, if found, is recoverable through 

primary- and secondary-recovery techniques. The 

second part assesses additional amounts of oil and 

gas that might be obtained from existing fields, 

either through enhanced-recovery techniques or 

additional drilling. 

ABBREVIATIONS AND DEFINITIONS 

The relationships between various resource 

terms defined below are illustrated in figure 7. Certain conventions used throughout the report are: 

Barrel. Standard barrel of 42 U.S. gallons, used as 

an oil measure; abbreviated either as Bbl or B. 

Basin. A large, bowl-shaped subsurface geologic 

feature formed by downwarping of the underlying basement rock and filled with sedimentary 

rocks. Large basins such as the Permian Basin 

may be divided after initial formation by uplifts 

and platforms, which in effect create other basins 

(such as the Midland and Delaware Basins) 

within the original structure. 

BOE. Barrels of oil equivalent, that is, crude oil 

plus natural gas converted to crude oil equivalency on the basis of heat content measured in 

British thermal units (Btu). One barrel of crude 

oil is assumed to contain 5.8 million Btu, and 1 

Mcf of natural gas (wet, that is, rich in condensate) is assumed to contain 1.1 million Btu (5.27 

Mcf= 1 BOE). 

MCF. 1,000 standard cubic feet of natural gas. 

Oil or gas field. Any area underlain by one or 

more oil and (or) gas pools (reservoirs) that are 

recognized as being part of a common geologic or 

9 

production unit. Where only one reservoir is 

present, the terms "field" and "pool" (or "reservoir") may be used interchangeably to de;;:ignate 

the same unit. 

Oil or gas in-place. The total amount of oil or gas 

contained in a reservoir, part of which will remain in the reservoir upon abandonment for 

economic or technological reasons. 

Oil or gas pool (reservoir). A discrete unit of 

porous permeable rock containing oil and (or) gas 

and distinguished by a single pressure system, so 

that withdrawal of fluids from any part of the 

reservoir affects the pressure in all other parts. 

The terms "reservoir" and "pool" are 

synonymous and are used interchangeably. 

Oil or gas supply. The quantity of oil or gas deliverable to market. 

Province. A rather loosely defined term implying a 

region of common geologic character th::tt contains one or more basins. 

Tcf. 1 trillion standard cubic feet of naturd gas. 

Ultimate recovery. The total of cumulati1re past 

production plus proved reserves on a specific 

date (for example, ultimate recovery as 

estimated in 1976). 

RESOURCE CLASSIFICATION 

The principles set forth by the U.S. Bureau of 

Mines and the U.S. Geological Survey (1981) have 

been incorporated into a classification inten1ed for 

oil and gas (U.S. Federal Power Commission, 

1976). A modification of these two classifications is 

shown in figure 7 and is explained by the ac~ompanying definitions. 

Resource. A concentration of naturally occurring 

solid or liquid petroleum or petrolenmlike 

material, or natural gas, in or on the Earth's 

crust, in such form that economic extraction is 

currently or potentially feasible. The resource includes all the material in place in a depofit. 

Identified (Discovered) resources. Resr)urces, 

and reasonable extensions thereof, whoFe location, quality, and quantity are known from drilling and geologic evidence, supported by 

engineering measurements. 

Undiscovered resources-Resources surmised to 

exist on the basis of broad geologic knowledge 

and theory. 

Reserve. That portion of the resource bas~ from 

which a usable mineral and energy commodity 

can be economically extracted at the time of 

estimation. Such commodities include but are not 

necessarily restricted to petroleum, condensate, 
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DISCOVERED 

UNDISCOVERED 

PROVED IINDICATEDIINFERRED 

RESERVES 

-

RESOURCES 

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INCREASING DEGREE 

OF GEOLOGIC ASSURANCE 

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FIGURE 7.-Resource classification diagram, total resources. 

natural gas, tar sands, and naturally occurring 

asphalt, without regard to mode of occurrence. 

Proved reserves. Material for which estimates of 

the quality and quantity have been computed 

from analyses and measurements of closely 

spaced and geologically well-known sample sites. 

Indicated reserves. Material that probably will be 

added in future years to proved reserves in 

discovered fields because of improved completion 

methods and increased recovery efficiency by 

secondary or enhanced methods. The American 

Petroleum Institute (American Gas Association 

and others, 1977, p. 14) category of "indicated 

additional reserves" is a part of indicated 

reserves; these are defined as "known productive 

reservoirs in existing fields expected to respond 

to improved recovery techniques such as fluid injection where (a) an improved recovery technique 

has been installed but its effect cannot yet be 

fully evaluated; or (b) an improved technique has 

not been installed but knowledge of reservoir 

characteristics and the results of a known technique installed in a similar situation are available 

for use in the estimating procedure." 

Inferred reserves. Material that probably will be 

added in future years to proved reserves in 

discovered fields, estimated partly from drilling 

~nd production data and partly from extrapolation of geologic and engineering evidence over a 

reasonable area. This includes additions 

resulting from extension of producing areas and 

new reservoirs within known fields. Some shut-in 

10 

or behind-the-pipe reservoirs not presently 

credited to proved reserves by some estimators 

are included in this category. 

Discovered subeconomic resorrces. Known 

resources not economically proiucible on the 

date of estimation. Such resources include those 

that are too small or too remote; at depths too 

great, or under water depths too great to be 

economic; or those for which kn')wn producing 

technologies are not presently ec~momic. 

Hypothetical resources. Undiscouered material 

that may reasonably be expectei to exist in a 

known producing basin under l<nown geologic 

conditions. Exploration that cc11firms its existence and reveals the quantity and quality of 

this material will permit its reclassification to a 

discovered-resource category. This category is 

sometimes used to divide the "undiscovered" part 

of the resource diagram into "hypothetical" on 

the left and "speculative" on the right. 

Speculative resources. Undiscovered material 

that reasonably may be expected to exist in 

presently nonproductive basins. Exploration 

that confirms its existence and rE.veals the quantity and quality of this mater:al permits its 

reclassification to a discovered-resource 

category. This category is less geologically 

assured than hypothetical resources and, like 

that category, is infrequently used. 

Undiscovered subeconomic rePources. That 

material in hypothetical and spec'llative deposits 

which, if found, would not be economic to produce on the basis of existing technology at the 

time of estimation. 

Other occurrences. Material not expected to 

become producible within a foreseeable period of 

time. For working purposes, thiE period may be 

defined as 25 years from the data of estimation. 

Among these materials are part or all of such unconventional deposits as gas occluded in coal, 

dissolved in water in geopressurei reservoirs, or 

free in fractured shales; and oil ir oil shale or tar 

sands. 

EXPLANATORY NOTE. 

In the United States, data on currulative production of crude oil are reasonably accr1rate, although 

no one pretends that every barrel has been 

counted. With respect to natural gas and naturalgas liquids (NGL), the story is oth~rwise. During 

most of the early oil-production years, the dissolved gas was vented to the atmosphere as an 

undesirable and dangerous annoyance. Only later 

was its importance recognized. Data on natural-
gas liquids are nearly impossible to obtain, so most 

of the quantities are estimated in barrels obtained 

for each million cubic feet of gas produced. 

Likewise, quantities of gas produced in the past 

are commonly estimated by means of ratios to 

crude-oil production. Current gas production, 

where the gas is not associated with crude oil, is 

usually gauged accurately. 

SENSITIVITY TO PRICES AND COSTS 

As noted in U.S. Geological Circular 725, 

estimates of recoverable resources can be sensitive 

to assumptions about the future price of crude oil 

and the probable costs of finding and producing 

such oil. High prices relative to costs encourage 

the recovery of a greater proportion of the oil and 

gas in_ place and, thus, tend to raise estimates of 

recoverable resources; low prices discourage production and force estimates of recoverable 

resources down. 

This study does not examine the timing of the 

discovery and development of resources as market 

conditions change. The actual effects of different 

price/cost levels on the timing of recovery can be 

complex. If producers believe that higher prices 

are likely to be short term, they may restrict their 

efforts to drilling and production on the intensive 

margin (that is, from already identified resources). 

For example, the price deregulation of crude production from stripper wells (those producing less 

than 10 barrels a day) increased the price of such 

oil from $5 per barrel to the current world price; 

this increase extended the productive lives of these 

wells. In this example, the higher price level moved 

identified subeconomic resources into the proved, 

indicated, and inferred catagories during this 

period. Estimates of identified recoverable 

resources would change rather than the estimates 

of undiscovered recoverable resources, which take 

longer to develop. 

If producers expect prices to stabilize at a higher 

level relative to costs for a long period, they may 

accept the greater risk of drilling and producing on 

the extensive margin (that is, from presently undiscovered resources) as well as drill and produce 

on the intensive margin. Consequently, the higher 

price level would tend to increase any estimates of 

undiscovered recoverable resources until higher 

costs per barrel, owing to lower resource quality, 

reach the higher price level. Higher prices over the 

long run make economically feasible the use of 

enhanced recovery techniques. Consequently, such 

price increases have tended to increase activity on 

11 

the intensive margin even more than perceived 

short-run price rises. 

The events of the last 10 years have caused considerable uncertainty about the price and C1

1St relationships likely to prevail in the future. This, in 

turn, has caused difficulties in assessing tl'~ effect 

of prices or costs in terms of future production on 

either the intensive or the extensive margin, over 

time. 

Events have indicated the possibility th~.t longterm changes in prices and costs may b€ taking 

place. From 1960 to 1970, the cost index maintained by the Independent Petroleum Ass1ciation 

of America (IP AA) indicated a drop in the ratio of 

prices to costs. Such a trend might reduce 

estimates of ultimately recoverable rerources. 

However, this trend was reversed after H70. 

Since 1970, the trend toward higher prices for 

new oil in nominal dollar terms has been clear. Until 1973, prices were relatively constant in nominal 

dollars, or declining in real dollars (that is, after 

the effects of inflation were removed). In 1974, the 

U.S. price of new oil averaged $10.13 per btrrel in 

nominal dollars, and by 1977, the averag€ uppertier oil price was $11.32 per barrel. Since then, 

prices have risen still further in nominal dollars. 

Currently, although the real-dollar price of uppertier oil is falling, it is still above 1973 pricef., Longterm higher prices have encouraged producers to 

expand exploratory drilling on the extensive 

margin, and ultimately they will make the r~~covery 

of a greater portion of presently undiscovered 

resources economically feasible. 

Costs of oil production (in nominal dollars) more 

than doubled from 1970 to 1977 for an oil field at a 

depth of 4,000 feet in the Permian Ba.sin. In 

general, during this period, direct operating costs 

increased 104 percent; lease equipment costs, 169 

percent; and drilling and equipment costs, 107 percent. If such trends continue, the effects of higher 

prices could be offset solely by the increased costs 

of doing business. 

To avoid the problem of forecasting inflation 

rates, for this analysis, we held costs at 1977levels 

(in real-dollar terms) and considered a range of 

prices (in real-dollar terms) from $5 per barrel to 

$40 per barrel. In this way, we have tried to indicate the sensitivity of the estimates of undiscovered recoverable resources to d:fferent 

price/cost levels. Although the price responsiveness of inferred reserves was not explored, the 

effect of higher prices on extending the lives of 

wells in new fields is incorporated. Because the 

Permian Basin has been extensively explored, 
exploration has covered the area to such an extent 

that it has no true extensive margin; it has only an 

intensive margin. 

THE PERMIAN BASIN PILOT AREA 

Accomplishing the project's objectives required 

new analytical techniques and a considerable expenditure of time, money, and labor. Prudence dictated a development and testing period to perfect 

the new methods. 

The Permian Basin was selected for a variety of 

reasons, two of which were paramount. First, the 

basin has a long history of development for which 

good historical records exist. It has been a productive source of oil and gas since 1921. Second, the 

production in the basin is from geologically varied 

sources: from reservoirs at depths as great as 

22,000 feet, from stratigraphic as well as structural traps, from both carbonate and clastic rocks, 

and from rocks as old as Cambrian and as young as 

Cretaceous. 

Consequently, the Permian Basin presented an 

ideal pilot area for the study of a "mature" basin. 

Large in areal extent and having a thick sedimentary section, the basin has been explored exhaustively and is not likely to yield major surprises 

in terms of future discoveries or production. Most 

of the known fields have been fully drilled, many 

secondary-recovery projects have been installed, 

and the best prospects for additional future 

recovery of petroleum appear to be in the realm of 

enhanced recovery. An example of enhanced oil 

recovery is the major carbon dioxide injection program at the SACROC unit in the Kelly-Snyder reef 

field. 

In choosing the Permian Basin, we recognized 

that this first project report would not be of interest to those eager to learn of opportunities for 

major new discoveries. Such opportunities are not 

present in a basin as "mature" as the Permian 

Basin. A mature basin does, however, provide a 

proper setting to devise and evaluate 

methodologies. It provides the opportunity: 

(1) To evaluate the basic methodological approaches before proceeding to study a partly developed basin; 

(2) To gain more understanding of the relationship of oil- and gas-resource availability to 

cost of finding and developing it in a typical 

basin; and 

(3) To estimate the cost of analysis versus the 

value of the knowledge to be gained. 

12 

APPROACH AND GENERAL METI'ODOLOGY 

At the outset, the work was divided into tasks, 

only some of which required new methodologies. 

These tasks concerned geologic app:':'aisal, exploration productivity, growth of known reserves after 

discovery, future improved recover-r from known 

fields, unconventional occurrences of oil and gas, 

and the estimated marginal costs of the additional 

reserves to be obtained from these various 

categories of effort. 

This project differs from other published oil and 

gas appraisals in that the analysis of conventional 

oil and gas is based upon individual fields or pools, 

rather than upon broad regional aggregations. 

Therefore, both the number and the size of expected discoveries are significant in the analyses. 

In addition, oil and gas resources from extension 

drilling, secondary and enhanced recovery, and unconventional sources-all of which have been excluded previously- are included in these appraisals. 

UNDISCOVERED RESOURCE APPRAISAL 

The first task was to establish a framework for 

classifying all known occurrences of conventional 

oil and gas in the basin according to the size 

distribution of the reservoirs already discovered 

and the depths at which they wer~~ found. Next, 

judgments were made concerning ~·uantities of oil 

and gas that still might be discovered in the basin 

through additional exploratory drilling for new 

fields and reservoirs. In this stage of the work, the 

fundamental methodology describei in U.S. Geological Survey Circular 725 was usei. Although no 

major changes were made in this s·1bjective probability approach, it has been moiified and improved for this project. As a result, the kinds of 

details required in the data about undiscovered oil 

and gas resources are different. The appraisal task 

group used historical data as well as its knowledge 

of the geologic setting of the basin not only to 

estimate the range of quantities of oil and gas that 

might be present, but also to present these data in 

terms of the numbers of reservoirs to be found in 

each of several field-size classes and in three depth 

classes. A minimum size of occ·1rrence to be 

estimated was set explicitly to avoirf the necessity 

of estimating all the oil and gas that might exist in 

nature. Finally, the geologic task gJ4

oup was asked 

to report on an oil-and-gas-in-place basis rather 

than on a recoverable basis. This permitted subsequent analyses to deal with variations in costs, 
prices, and recovery factors, and provided a clear 

separation between economic and geologic 

analysis. 

DISCOVERY-PROCESS MODEL 

After the geologic appraisal of undiscovered oil 

and gas was made, the next task group formulated 

a discovery model. The model was used to determine the most likely sequence in which the undiscovered reservoirs will be discovered and to 

estimate the amount of drilling that will be required to find progressively more of the remaining 

oil and gas. The geologic appraisal and the discovery model can be used independently or jointly. 

By extrapolating the past history of drilling in 

terms of the number of holes drilled and the oil and 

gas found as a result, the discovery model projects 

the number and sizes of fields to be discovered and 

the quantity of oil and gas contained in these fields. 

The discovery model also shows how many dry 

holes and producing wells would be required to 

detect various proportions of the remaining targets, given the areal dimensions of these targets 

and their numbers. The geologic appraisal and discovery model produced different but comparable 

estimates of remaining resources and indicated a 

new avenue for future research. 

ENGINEERING AND COST ANAYSIS FOR 

FUTURE FIELDS 

After the appraisal of in-place conventional 

resources and of the discovery of new reservoirs 

through exploratory drilling, the task group translated the oil and gas discovered into recoverable oil 

and gas by estimating the numbers of production 

wells required, the rate at which the oil and gas 

may be produced, and the point at which the reservoirs are abandoned (that is, the proportion of the 

oil and gas originally in place that is left unrecovered). This required establishing standard drilling density and production patterns based on customary practices reflecting depth, reservoir size, 

amenability to secondary recovery, and other factors. From these patterns, the entire sequence of 

development and production of the basin was 

estimated. 

THE INTEGRATING ECONOMIC MODEL 

The task group completed the conventional oil 

and gas analysis by using an integrating economic 

model that combined physical processes and economic considerations. The amount of oil and gas 

that is actually discovered and produced is a 

reflection of the economic motivation to drill exploratory and development wells, of the broader 

goals of the oil and gas industry, and of the effects 

of Government policies and regulations. Th~ model 

represents recovery of discovered oil and r-as as a 

function of the recovery of costs under a range of 

returns on investment and assumed price~· .. A discounted cash-flow computation is used where production is the only source of revenue, and all future 

production receives the assumed price. In this 

simplified representation, neither the industry's 

broader goals nor current Federal regulations are 

modeled. All calculations are based on the size and 

depth of fields predicted by the discovery model as 

a function of exploratory wells drilled. All discounted cash flows are based on production profiles 

from engineering analysis, as descri'·,~d in 

"Engineering and Cost Analysis for Future 

Fields." 

ADDITIONAL OIL FROM KNOWN FIELDS 

So far, the analysis has accounted only for the 

future oil and gas to be recovered from undiscovered oil and gas reservoirs. In addition, the 

analysis takes into account: 

(1) The oil and gas which may be produced from 

known reservoirs but which is not now included in proved reserves; and 

(2) The additional oil and gas to be recovered 

by means of enhanced-recovery technologies not included in the convE:ntional 

model. 

INDICATED AND INFERRED RESERVEf 

The amount of additional oil and gas from indicated and inferred reserves is related to those 

reserves added to the proved category thro'1gh extension drilling, revisions resulting from ne,v information, and the added recovery resulting from the 

installation of secondary-recovery projects. The 

methodology used in this task basically involved a 

statistical analysis of change in ultimate recovery 

over time. 

ENHANCED OIL AND GAS RECOVERY 

The enhanced oil recovery (EOR) methc do logy 

projects enhanced production potential by using a 

data base that describes specific res~rvoirs 

selected from the major producing fields in the 

region. This data is believed to cover a sub~tantial 

percentage of the remaining oil in place in the Permian Basin and a much higher percentage of the 

best EOR prospects. 

13 
Economic criteria are used in the model to evaluate five EOR methods: steam drive, in situ combustion, gas miscible flooding, surfactant polymer 

flooding, and polymer-augmented waterflooding. 

The evaluation involves three steps: 

(1) Screening reservoirs according to geologic 

and economic factors, and assigning EOR 

techniques to the most attractive prospects; 

(2) Identifying minimum acceptable prices and 

reservoir-specific production profiles over a 

period of time, on the basis of prices and 

rates of return; and 

(3) Extrapolating production data to regional 

levels and accumulating reserves. 

Potential production from EOR is estimated only 

for known fields. New fields are treated in the discovery model. 

The methodology of enhanced gas recovery 

(EGR) is analogous to that of EOR. A detailed geological description of potential EGR targets and an 

economic evaluation of alternative recovery 

methods are used to determine the economically 

attractive projects. The development and production schedules over a period of time are then projected for these projects, and reserve estimates are 

accumulated. 

OTHER OCCURRENCES 

The assignment to the remaining task group was 

to determine whether the basin has a geologic 

potential for providing commercially significant 

hydrocarbons from unconventional sources, such 

as oil shale, brown and black shale rich in organic 

matter, coal, tar sand or other heavy oils, geopressured brines, or hydrates. This group found 

that little oil and gas was available from all these 

so-called unconventional sources, and, therefore, 

no discussion of them appears in this report. 

The end product of this analytical process constitutes a complete review of the oil and gas resource 

and supply potential of the basin. The oil and gas 

resources in place are fully accounted for, and the 

associated range of probabilities are shown. These 

estimated resources are translated into recoverable quantities at assumed cost and at various 

rates of return a11d price settings. 

We do not suggest that by means of this 

methodology, we have produced a wholly accurate 

assessment of Permian Basin hydrocarbon 

resources, but the assessment does reasonably approximate the amount of oil and gas that might 

ultimately be recovered at a given price and at a 

14 

given rate of return. This methodology does not 

enable us to predict the time that various oil and 

gas quantities will be produced, but it does provide 

a means to grade the resource base economically 

and to approximate the amounts of oil and gas left 

to be discovered and produced in the Permian 

Basin by relating some sense of the effort, both 

physical and economic, that will be required to actually transform resources into proiucible oil and 

gas. 

FUTURE PRODUCTIOJIT OF 

UNDISCOVERED OIL AND GAS FROM 

THE PERMIAN BASIN 

PERMIAN BASIN RESOURCE APPRAISAL 

The Permian Basin, which has been one of the 

most prolific sources of petrole'lm in North 

America, is now in an advanced stage of exploration and development. Very large quantities of oil 

and natural gas have been found th~re in rocks of 

Paleozoic age (those 225-570 million years old), 

and minor amounts have been found in younger 

reservoirs (table 4). Reservoirs produce oil from 

depths of less than 500 feet to slightly more than 

14,000 feet and natural gas from depths of less 

than 500 feet to more than 21,000 feet. Most of the 

oil (71 percent) has been found in the relatively 

shallow Permian rocks, and most of the 

nonassociated gas (71 percent), in the deeper, older 

Paleozoic rocks (table 4). 

GEOLOGY 

The Permian Basin is a large asymmetric structural depression in the Precambr~an basement, 

filled primarily with Paleozoic sediments. It had 

essentially acquired its present stn1.etural form by 

Early Permian time, although that form has been 

modified by subsequent tectonic activity. Rocks of 

all Paleozoic systems are present and have a maximum combined thickness of mor~ than 25,000 

feet. The location and major structural elements in 

the Permian Basin are shown in figure 8. 

From Cambrian through Mississiopian time, the 

area was relatively stable; from 2 broad marine 

shelf, it evolved into a marine basin with associated 

shelves. This basin was the site of extensive carbonate and subordinate fine clastic sedimentation. 

Its deepest part was in the approximate vicinity of 

the present Delaware Basin. Only mild structural 

movement and deformation took p1ace during this 

early period, producing local uncc'1formities and 

structural anomalies of low and br0ad relief. The 
TABLE 4.-Discovered oil and gas in place, Permian Basin (1921 to December 31, 1974) 

Natural gas in placet 

Geologic subdivision Oil in placet (in trillion cubic feet) 

(1Q9 bbls) Associated Dissolved N onassociated 

post-Permian ------------------ 0.184 0.000 0.006 trace 

Permian ---------------------- 65.070 2.414 30.323 6.268 

Carboniferous ------------------ 11.926 .352 10.228 7.721 

older Paleozoic ----------------- 14.368 1.167 16.284 2 33.636 

undifferentiated Paleozoic ________ .003 .000 .001 .000 

Total 91.551 3.933 56.842 2 47.625 

t Discovered quantities cited here are estimates of initial oil or gas in place and do not include quantities that may accrue to known fields through future growth by extension, 

new pays, or new pools (hence, they exclude inferred reserves but include cumulative past production and proved reserves). 2 Includes 2.2 trillion cubic feet of C02 • 

deeper parts accumulated fine clastic sediments 

and some interbeded limestone in Mississippian 

time. 

The dolomite of the Ordovician Ellenburger 

Group and Devonian limestones and dolomites are 

the principal reservoirs of the older Paleozoic and 

Mississippian sequence, although other productive 

reservoirs are found throughout. Traps in the older 

Paleozoic rocks are primarily in faulted anticlines, 

some of large size; truncation of strata below unconformities also produced significant stratigraphic and combination traps. 

From Early Pennsylvanian into Early Permian 

time, the region was subjected to intense structural deformation and orogenic movement that 

culminated in the formation of the present tectonic 

elements (fig. 8) and provided a depositional setting totally different from the relatively stable 

basin that existed earlier. The tectonic elements include the Diablo and Central Basin Platforms, the 

deep Delaware, Val Verde, and Midland Basins, 

and their surrounding shelves (Northwestern and 

Eastern). Sedimentation in Pennsylvanian time 

varied according to the tectonic setting. Coarse 

clastic sediments were deposited near the 

shorelines of basins and limestones seaward of the 

clastic deposits. Reefs built at that time constitute 

a large percentage of the limestone. In Late Pennsylvanian time, the deeper basins were sediment 

starved, and only thin marine shales were 

deposited. Pennsylvanian rocks are absent in many 

localities because of erosion or nondeposition, particularly along the trend of the Central Basin Platform. Among the types of traps present, reefs are 

common. 

In Permian time, sediments continued to build on 

the tectonic setting formed in Pennsylvanian time. 

Reef building increased; the great Permian reefs 

are the most striking feature of the entire Permian 

Basin. The reefs generally formed at the basin 

15 

hingelines and separated the clastic and thin 

limestone deposits of the basins from the backreef 

lagoonal deposits of sandstone, mudstone, carbonate, and anhydrite interfingering layers. 

The growth of the great reefs and the lagoons 

behind them led to the dominance of Permian 

rocks in the production of oil and gas. Most of the 

Permian oil and gas traps are related to the reefs 

and backreef rocks and their varied porosities. 

Many well-known reservoirs are found in this setting, including the San Andres Limestone, the 

dolomite of the Grayburg Formation, the reef of 

Abo Sandstone, and the Glorieta Sandstone. Many 

other reservoirs, including some from other settings such as the "Spraberry" fractured siltstone, 

contribute to the dominance of the Permian section 

in hydrocarbon production in the Permian Basin. 

ANALYSIS AND ASSESSMENT 

The assessments of undiscovered oil and gas in 

place reported here fall in the right-hand column of 

the resource classification diagram (fig. 7). Not all 

in place resources will be recovered because of 

economic and technological limitations. 

Some deposits of hydrocarbons are too small, too 

dispersed, or too remote to be classified as 

resources. The smallest size class used in this study 

is that of a reservoir containing 1,000 barrels of oil 

in place or 1 million cubic feet of nonassociated gas 

in place. Resources assessed here are for the most 

part conventional oil and gas and exclude tight gas 

sands, tar sands, and heavy oil deposits. 

The Paleozoic section of the Permian Basin was 

divided into three identifiable major stratigraphic 

units for purposes of assessment of undiscovered 

hydrocarbons. These three units are separated in 

many places by natural boundaries within the 

stratigraphic column and consist, respectively, of 

rocks of the Permian, the Carboniferous, and the 
0 

0 50 100 150 KILOMETERS 

EXPLANATION 

------ OUTLINE OF STRUCTURAL 

ELEMENTS 

----+--- ARCH 

_....__ ...... ......__THRUST FAULT -SAWTEETH 

ON UPPER PLATE 

hiiJ:ifil!il!ili!i11!'il!t, "" :nw STUDY AREA BOUNDARY 

FIGURE 8.- Structural elements in the Permian Basin. 

16 
remam1ng older Paleozoic systems. Each major 

stratigraphic unit (such as the Permian, Carboniferous, and older Paleozoic) was analyzed independently by a team of geologists. Because of 

restrictions imposed by physical characteristics of 

each unit, specific methods of data preparation and 

treatment in each unit vary to a certain degree. 

However, the objective of the analysis-to assess 

undiscovered in place hydrocarbons, and the probability distributions for pool sizes containing these 

hydrocarbons- dictated similar methods of approach for all three units. The separate 

assessments were combined into the totals 

reported here. 

The procedure for estimating the undiscovered 

oil and natural gas in the Permian Basin involved 

an intensive review of the geology and analysis of 

historical data, and ultimately the application of 

subjective probability methods for the actual 

assessment. 

GEOLOGIC ANALYSES 

All available geologic, drilling, reservoirengineering, and related data were compiled for 

the three major stratigraphic units. The Dallas 

Field Office of the Energy Information Administration, U.S. Department of Energy (at that 

time part of the U.S. Bureau of Mines) supplied 

data concerning total known oil and gas reserves 

of the Permian Basin, initial oil and gas in place, 

estimates of ultimate recovery, amounts of 

associated and dissolved gas, field and pool sizes, 

discovery dates, age of productive units, depths of 

production, and general reservoir characteristics. 

Basic drilling information, derived from the 

Petroleum Information Corp. "Well History Control System" (unpub. proprietary commercial data 

file) was used to establish the well density, penetration depths, identification of stratigraphic units, 

and historical success records of exploratory wells. 

Publicly available literature provided information 

on porosities, permeabilities, reservoir lithologies, 

amounts of net pay sections, gas/oil ratios, 

hydrocarbon properties, trapping mechanisms, 

and types of reservoir seals. Literature on the Permian Basin, USGS files, and unpublished maps also 

provided isopach, lithofacies, and some structural 

maps. Studies on geophysical investigations were 

not available. 

Subsurface geologic maps were prepared for 

5,000-foot depth intervals and were used, together 

with isopach maps, to calculate the total area and 

volume of the three major stratigraphic units. 

17 

Volumes of sediment in each of the three major 

stratigraphic units were partitioned into the depth 

intervals of 0-10,000, 10,000-20,000, and 

20,000-30,000 feet. 

Drilling-density maps were prepared and provided the basis for outlining maturely drilled areas, 

immaturely drilled areas, and totally undrilled 

areas. Maturely drilled areas are defined as having 

12 or more wells per 25 square miles, and immaturely 'drilled areas as having less than 12, and 

more than 0, wells per 25 square miles. Combined 

with rock distributions, these maps provided 

volumes and areas of maturely drilled, immaturely 

drilled, and undrilled rock in each major 

stratigraphic unit and in each depth interval. The 

drilling-density maps were based on maps of newfield wildcats drilled through or into specific 

stratigraphic units and were derived from 

Petroleum Information Corp. "Well History Control System" (unpubl. proprietary commercial data 

file). To these maps, the locations of oil and gas 

fields producing from the same or older 

stratigraphic units were added. The resulting combined maps were contoured on the basis of well 

density. 

To gain some idea of the possible range of undiscovered oil and gas in place, we applied yield 4 

factors to the volumes or areas of immaturely 

drilled and undrilled rock. These yield factors were 

derived from maturely drilled areas of the basin 

and were applied to sedimentary-rock volumes or 

areas within individual tectonic elements or on a 

gross regional scale or trend basis. To calculate a 

possible "high" amount of undiscovered oil or gas 

for any one area, we assumed that geologic and 

reservoir conditions in the immaturely drilled or 

undrilled areas were similar to those existing in the 

maturely drilled producing area. Such ~onditions 

include lithologic and reservoir variables, trap 

types, sealing mechanisms, and source rocks. We 

calculated "low" amounts by: (1) reducing the total 

area or volume of sedimentary rock in immaturely 

drilled areas by a quantity assumed tested by the 

exploratory wells in the area, (2) discounting undrilled or immaturely drilled sedimentary-rock 

volume in direct proportion to the success ratio 

established in maturely drilled producing areas 

before applying the yield factor, or (3) discounting 

either the undrilled sedimentary-rock volumes or 

historic-yield factors, assuming particularly unfavorable geologic conditions. Yield factors were 

directly lowered in some places to reflect a reduced 

4 Yield, as used here, applies to in place rather than recoverable quantities. 
probability of occurrence of additional giant fields. 

We also applied analog models to major tectonic 

elements within the Permian Basin by using 

known hydrocarbon yield factors from other major 

elements, such as the highly productive Midland 

Basin and Central Basin Platform. 

STATISTICAL ANALYSIS 

We analyzed historic finding rates by plotting 

discovered volumes of hydrocarbons against units 

of exploratory effort for each of the three major 

stratigraphic units and for several pool-size 

classes. The amount of oil discovered as drilling 

effort increased has declined dramatically (fig. 9). 

However, such a decline is not apparent for 

nonassociated natural gas (fig. 10). Finding rates 

for pool-size categories, not shown here, indicate 

that oil is no longer being found in the larger poolsize classes, which historically have contributed the 

major quantities of discovered resources. Even the 

larger components of the smallest size class are 

being found in decreasing numbers. In terms of 

natural gas pool sizes, no clear finding-rate trend 

can be identified. 

40 1930 

SUBJECTIVE PROBABILITY PROCEDURES 

Subjective probability procedures were used in 

the final assessments. These procedures were 

similar to those described by Miller and others 

(1975), except that associated dissolved-gas 

estimates were derived from oil estimates through 

the use of historic depth-dependent gas/oil ratios. 

Estimates of the least quantity of oil or gas expected at 95, 75, 25, and 5 percent probability and 

a modal estimate describing the highest probability 

of occurrence were produced separately for the 

major stratigraphic units within the basin for the 

depth increments 0-10,000, 10,000-20,000, and 

20,000-30,000 feet. These were then aggregated 

by means of Monte Carlo techniques into the Permian Basin totals shown in table 5 and into the 

depth intervals shown in table 6. 

METHODS FOR POOL-SIZE ASSESSMENT 

Data for pool-size assessments of future 

discoveries were compiled as an integral part of 

the overall data collection and analysis. The 

EXPLANATION 

(/) 

-' 

~ 30 a: 

<X: 

CD 

u.. 

0 

PERMIAN 

CARBONIFEROUS . 

OLDER PALEOZOIC 

(/) 

z 

0 

:J 

-' 20 CD 

~ 

w' 

u 

:5 

a.. 

~ 

....J 10 

0 

0 

0 40 80 120 160 

EXPLORATORY FOOTAGE SINCE 1920, IN MILLIONS OF FEET 

FIGURE 9.-Historic finding rate for oil, 1920-1974, Permian Basin. 

18 
1970 

6 

EXPLANATION 

PERMIAN 

1-

UJ 

UJ CARBONIFEROUS u.. 

~ 

Ill OLDER PALEOZOIC 

::::l 

u 4 

u.. 

0 

(/) 

z 

Q 

...J 

...J 

a: 

1-

~ 1950 UJu 

~ ...J 2 0.. 

~ 

(/) 

~ 

t!J 

0 

0 40 80 120 160 

EXPLORATORY FOOTAGE SINCE 1920, IN MILLIONS OF FEET 

FIGU RE 10.-Historic finding rate for nonassociated natural gas, 1920-74, Permian Basin. 

historic pool-discovery data were subjected to 

several analyses with each major stratigraphic 

unit. 

(1) Histograms were prepared for all pool-size 

classes by depth intervals and by equal 

units of exploratory effort. 

(2) Cumulative frequency distributions were calculated for the entire historic period and 

for the last two 40-million-foot units of exploratory effort. 

(3) A linear regression was fitted to the historic 

cumulative frequency distributions in an 

attempt to project numbers and frequencies of pools in the very small classes. 

(4) Finding-rate curves were calculated for various field-size classes. 

Probability estimates of the pool sizes in which 

the assessed undiscovered oil and nonassociated 

gas in place occur were produced by subject probability procedures for each of the major stratigraphic units and depth intervals. Pool sizes were 

19 

estimated as in place quantities. Dissolved and 

associated gas occurrences were not included in 

size estimates of those pools. 

The evaluators provided estimates of the 

minimum pool size corresponding to the 95, 75, 25, 

and 5 percentile probabilities and also of a modal 

("most likely") value. Attempts were made to fit 

several functions to these subjective estimates. 

Although no totally satisfactory fit was found, a 

lognormal curve was used. As a result of the 

lognormal curve, the calcuated mean pool sizes appear unduly large, and the reported distributions 

should be viewed only as approximations of the 

assessed distributions of undiscovered pool sizes. 

Pool-size assessments were made by stratigraphic 

interval. Aggregations of the pool-size distributions into a basin total are not currently available. 

SUMMARY RESULTS 

Assessed total undiscovered oil and gas in place 

are summarized in table 5 and shown by depth 
TABLE 5.-Estimates oftotal undiscovered hydrocarbons in place 

[The values shown are the estimates corresponding to the probability that there is at least that amount. Values shown are derived from lognormal curve fits at the 0.95 and 0.05 

probability levels] 

0.95 0.75 0.25 0.05 Mean Standard 

probability probability probability probability deviation 

Oil in place (109 bbls) ------------------------ 3.32 4.53 7.22 10.43 6.35 2.29 

Gas in place (in trillion cubic feet) 

Dissolved and associated ------------------- 2.99 4.06 6.31 8.83 5.57 1.85 

N onassociated --------------------------- 8.24 11.38 18.80 28.27 16.30 6.58 

Total --------------·------------------- 12.89 16.50 24.29 33.80 21.87 6.74 

TABLE 6. -Estimates of total undiscovered hydrocarbons in place by depth interval 

[The values shown are the estimates corresponding to the probability that there is at least that amount. Values shown are derived from lognormal curve fits at the 0.95 and 0.05 

probability levels] 

Depth interval (thousand feet) 0.95 

probability 

0.75 

probability 

0.25 

probability 

0.05 

probability Mean Standard 

deviation 

Undiscovered oil in place (10 9 bbls) 

0-10 ___________________________________ _ 

10-20 ___________________________________ _ 2.31 

.51 

3.37 

.79 

5.91 

1.52 

8.87 

2.56 

5.05 

1.30 

2.18 

.69 

Undiscovered associated dissolved gas in place (trillion cubic feet) 

0-10 ___________________________________ _ 

10-20 ___________________________________ _ 1.76 

.68 

2.58 

1.07 

4.42 

2.08 

6.70 

3.53 

3.80 

1.77 

1.56 

.97 

Undiscovered nonassociated gas in place (trillion cubic feet) 

0-10 ___________________________________ _ 

10-20 ___________________________________ _ 

20-30 ___________________________________ _ 

1.43 

3.73 

.75 

interval in table 6. Probability distributions for the 

data in table 5 are given in figures 11 through 14. 

Table 7 shows the estimated mean depths of occurrence for undiscovered hydrocarbons in place by 

depth intervals for all Paleozoic systems, of 10,000 

feet. Examples of the fit of lognormal curves for a 

few of the pool-size probability distributions, alon$" 

with dots representing the numerical average d;f 

original estimates to which the curves have been 

fitted, are given in figures 15 through 17. 

THE DISCOVERY-PROCESS MODEL 

Through discovery and production-cost analyses, 

the number, size, and depth of occurrence of future 

oil and gas discoveries in the Permian Basin can b~ 

estimated. Because the Permian Basin has a long 

exploration history, the pattern of future 

discoveries may be forecast by extrapolating the 

past drilling and discovery record. 

The method used here to forecast the size 

distribution of future discoveries is based upon a 

well-documented and not surprising characteristic 

of the petroleum-discovery process; the large 

20 

2.16 

6.17 

1.28 

3.83 

12.74 

2.73 

5.98 

21.90 

4.86 

3.31 

10.70 

2.29 

1.52 

6.15 

1.38 

TABLE 7.-Estimates of mean depths of occurrence of 

undiscovered hydrocarbons in place-all Paleozoic systems 

Depth interval (thousand feet) 

0-10 ------------

10-20 ------------

20-30 ------------

0-30 ------------

[n.a., not applicable] 

Mean depth of occurrence (ft) 

Oil 

6,100 

11,800 

n.a. 

7,300 

Nonassociated gas 

7,600 

15,400 

21,500 

14,700 

deposits tend to be discovered early in the exploration of an area (Ryan, 1973; Barouch and Kaufman, 1978; Drew and others, 1978, 1979; and Arps 

and Roberts, 1958). Any reasonable quantitative 

model of the discovery process must incorporate 

this characteristic. The model described here was 

proposed by Arps and Roberts (1958) and assumes 

that the probability of the next exploratory well 

finding a field of a given area is proportional to the 

ratio of the area of the field to the area of the basin. 

Thus, a field having a large surface area has a 

higher probability of being discovered early than 

does a field having a small surface area. For this 
1.0 

~ ~ 

\ PROBABILITY 

0.95: 3.32 billion bbls 

0.05: 10.43 billion bbls 

0.8 

>- 0.6 1-

:::::i 

a:i 

<( 

a::l 

0 \ Mean: 6.35 billion bbls 

Standard deviation: 2.29 billion bbls 

~ 

~ " 

a: 

c.. 0.4 

0.2 

~ r--.___ 

0.0 - 0 2 4 6 8 10 12 

RESOURCE IN PLACE, IN BILLIONS OF BARRELS 

FIGURE 11.- Probability distribution of the total Paleozoic undiscovered oil in place, aggregated for depths of 

0-20,000 feet. 

reason, the model initially projects a distribution of 

the areal sizes of future discoveries. This distribution is then converted into a distribution of the 

volumes of predicted future recoverable petroleum 

by relating the average areal size of fields to the 

average volume of recoverable petroleum that they 

contain. 

This approach was originally devised to forecast 

future discoveries in a basin having only a single 

productive horizon without large structural relief. 

The approach had to be modified before it could be 

used in a basin, characterized by many productive 

strata at varying depths and modes of geologic occurrence (for example, the Permian Basin). To 

apply the model to the Permian Basin, we divided 

the basin into four layers, each 5,000 feet thick. 

Forecasts of future discovery rates were then 

made independently for each layer. 

Two types of information were required for the 

analysis: (1) detailed information on the exploratory drilling history of the basin, obtained 

from the Petroleum Information Corp. "Well 

History Control System" (proprietary unpub. 

commercial data file) which gives the completion 

date and total depth of each exploratory well 

drilled before January 1, 1975; and (2) information 

on the known oil and gas fields in the Permian 

Basin; including the volume of recoverable oil and 

gas, the discovery, and the depth and surface projection area of each field, prepared by the Dallas 

Field Office of the Energy Information Administration, DOE (unpub. data, 1977-78.) 

EXPRESSING THE DATA IN DEPTH INTERVALS 

The oil and gas fields were divided into four 

depth-class intervals: 0-5,000, 5,0W)-10,000, 

10,000-15,000, and 15,000-20,000 feet. Few data 

were available for depths greater than 1f,OOO feet. 

No estimates were made for fields deeper than 

20,000 feet because of insufficient data as of 

December 31, 1974. A field was assigned to the interval that contained its largest reservo'r. Within 

each interval, the fields were partition(\d into 20 

size classes based upon quantities of recoverable oil 

and gas (table 8). "Oil equivalent" ex:[:ressed as 

BOE (barrels of oil equivalent) repres~nts total 

21 
1.0 

\ ' 0.8 

~ PROBABILITY 

0.95: 2.99 trillion ft3 

0.05: 8.83 trillion ft3 ~ 0.6 

:::; 

co 

<( 

OJ 

0 

a: 

a.. 0.4 \ Mean: 5.57 trillion ft3 

Standard deviation: 1.85 trillion ft3 

\ 

"' ~ 1----~-

0.2 

0.0 

0 2 4 6 8 10 12 

RESOURCE IN PLACE, IN TRILLIONS OF CUBIC FEET 

FIGURE 12.-Probability distribution of total Paleozoic undiscovered dissolved and associated gas in place, aggregated for depths of 

0-20,000 feet. Pool sizes in trillions of cubic feet (ft3). 

volatile hydrocarbon fluids. It includes barrels of 

oil, barrels of lease condensate, and thousands of 

cubic feet of wet natural gas converted to BOE. 

The average volume of recoverable oil equivalent 

and average areal extent of the fields in each size 

class and depth interval combination were also 

computed. 

TABLE 8.-Field-size classes 

[BOE, barrels of oil equivalent] 

Size clsss Size range (million BOE recoverable oil and gas) 

1 -------------------------------

2 -------------------------------

3 -------------------------------

4 -------------------------------

5 -------------------------------

6 -------------------------------

7 -------------------------------

8 -------------------------------

9 -------------------------------

10 -------------------------------

11 -------------------------------

12 -------------------------------

13 -------------------------------

14 -------------------------------

15 ------------------------------- 16-------------------------------

17 -------------------------------

18 -------------------------------

19 ------------------------------- 20 -------------------------------

0.0 to 0.006 .006 to .012 .012 to .024 .024 to .047 .047 to .095 .095 to .19 .19 to .38 .38 to .76 .76 to 1.52 1.52 to 3.04 3.04 to 6.07 6.07 to 12.14 12.14 to 24.3 24.3 to 48.6 48.6 to 97.2 97.2 to 194.3 194.3 to 388.6 388.6 to 777.2 777.2 to 1,554.4 

1,554.5 to 3,109.0 

22 

The number of exploratory wells drilled each 

year was converted into the number of net wells 

per year within each depth interval. For example, 

an exploratory well drilled to a total depth of 7,500 

feet was counted as one well in the 0-F,OOO-foot interval and as half a well in the 5,000-10,000-foot 

interval. A well drilled to a total depth of 20,000 

feet was counted as one well in each of the four 

depth intervals. 

FORM OF THE MODEL 

The discovery-process model select(ld to predict 

future rates of discovery in the Permian Basin has 

the following analytic form for relating discoveries 

to exploratory wells: 

Fa (w)=Fa ( 00) * (1- e-CAw/B~ 

where: 

Fa (w)=the cumulative number of discoveries 

estimated to be made in size class a by 

the drilling of w exploratory wells, 

Fa ( oo) =the ultimate number of fields in size class 

A that occur within the b~sin, 
1-or-------=-;;==--,---------------~----------------r-----------------

o.ar----------------+----~----------+---------------~----------------~ 

PROBABILITY 

0.95: 8.24 trillion ft3 

0.05: 28.27 trillion ft3 ~ o.sr------------------+----------~~----~-------- Mean: 16.30 trillion ft3 

Standard deviation: 6.58 trillion ft3 1-

:J 

iil 

<( 

OJ 

0 

a: 

c.. 0.4.---------------4---------------~~--------------~--------------~ 

0.2r----------------+----------------+-------~~----~----------------~ 

0.00~--------------~----------------~--------------~----------------~ 8 16 24 32 

RESOURCE IN PLACE, IN TRILLIONS OF CUBIC FEET 

FIGURE 13. -Probability distribution of total Paleozoic undiscovered nonassociated gas in place, aggregated for depths of 

0-30,000 feet. Pool sizes in trillions of cubic feet (ft3). 

B =area of the basin, 

A= average areal extent of the fields in the 

given size class and depth interval, 

w =cumulative number of net exploratory 

wells for the depth interval, and 

C =the efficiency of exploration. For random 

drilling, C= 1; if the exploration is 

twice as effective as random, C = 2. 

The ultimate number of fields expected in the 

class, Fa ( oo ), was estimated from the model and 

the discovery record, after a value for C had been 

estimated. 5 The value of Fa ( oo) was calculated for 

each size class of fields within each depth interval 

by solving the discovery-process model equation. A 

sample calculation for field-size class 10 in the 

0-5,000-foot interval is given below: 

Input data for size- class 10, 

depth interval 0-5,000 feet 

Average areal extent of fields= 

Permian Basin size= 

Efficiency of exploration= 

Cumulative exploratory wells 

through 1960 = 

2.2 mi2 

100,000 mi2 

2.0 

14,243 

23 

Number of discoveries in size-class 10, in the 

0-5,000 foot interval through 1960= 59 

Solution for ultimate number of fields 

FlO ( oo) FlO (w) 1-e-CAw/B 

59 

1- e-2.0.2.2. l4.243/too.ooo 

= 126.7 fields 

Given the number of discoveries in this size class 

through 1960 and the cumulative net wells in the 

interval, the model estimates that 126.7- 59= 67.7 

fields of this size (1.52 to 3.04 million BOE) remaining to be discovered after 1960 in this dep-l:h interval. Of course, we do not discover a fraction of a 

field any more than we throw 1.5 heads in 3 tosses 

of a coin. The statistical expectation ir 3 coin 

tosses, however, is 1.5 heads, just as the statistical 

expectation for class 10 fields is 126.7. 

5 For each value of Cit is possible to use the pre-1961 discovery data and the model 

to forecast the 1961-1974 discoveries in each size class in a given deptli interval. The 

criterion for selecting a value for C for a particular interval was that the total oil in 

the forecasted 1961-1974 discoveries be equal to the total oil in the adual 1961-74 

discoveries. The value of C selected for a particular interval was then UF"d to forecast 

the post·1974 discoveries in each size class for that depth interval. 
1.0 

0.8 ~ 

>- 0.6 

1-

:::::i 

cc 

<{ 

m 

0 

a: 

a.. 0.4 

0.2 

~ PROBABILITY 

0.95: i 2.89 trillion ft3 

0.05: 23.80 trillion ft3 

Mean: ~1.87 trillion ft3 

Standard deviation: 6.74 trillion ft3 

\ 

""' ~ "', ,,~ 

8 16 24 32 

RESOURCE IN PLACE, IN TRILLIONS OF CUBIC FEET 

FIGURE 14.-Probability distribution of total Paleozoic undiscovered gas (dissolved, associated, nonassociated) in p1ace, aggregated for 

depths of 0-30,000 feet. Pool sizes in trillions of cubic feet (ft3). 

TABLE 9.-Compa·rison of the numbers ofd·iscoveries through 1974 with the number forecast, keyed on the pre-1!?61 discovery and 

explora.tory driZZ.ing data ·in the 0-5,000joot depth interval 

Size class 

2 -----------------------

6 -----------------------

7 -----------------------

8 -----------------------

!J -----------------------

10 -----------------------

11 -----------------------

12 -----------------------

13 -----------------------

14 -----------------------

15 -----------------------

16 -----------------------

17 -----------------------

H! -----------------------

1!! -----------------------

20 -----------------------

Area (square miles) 

0.13 

.14 

.16 

.22 

.25 

.39 

.49 

.94 

1.23 

2.21 

4.2-1 

5.40 

8.30 

18.19 

40.42 

49.19 

67.20 

81.75 

12!!.88 

40.25 

Actual 

211 

84 

84 

92 

127 

135 

129 

104 

111 

84 

75 

49 

35 

1!J 

14 

16 

9 

Total ---------------------------- ------------------------- 1,387 

We can determine whether an estimate arrived 

at by means of this method is reasonable by making an historical forecast from 1960 to some subsequent year before 1979. The forecast can then be 

checked against the actual number of discoveries 

24 

Discoveries 

Estimated Difference 

200.1 lO.!J 

66.0 18.0 

8-1.7 - .7 

67.0 25.0 

10!!.6 17.4 

114.8 20.2 

125.3 3.7 

92.8 11.2 

107.4 3.6 

84.5 - .5 

82.9 -7.!! 

52.2 -3.2 

33.3 1.7 

18.2 .8 

14.0 .0 

16.0 .0 

9.0 .0 

6.0 .0 

2.0 .0 

1.0 .0 

1,286.8 100.2 

made in the field-size class from 19fl) to that particular year. The forecast shown t~low projects 

discoveries for size-class 10. On the l"~.sis of 25,055 

wells drilled in the 0-5,000-foot interval from the 

start of exploration through 1974, 
1.0 

0.8 

~ ~ 0.6 

m 

<( 

~ 0.4 a: 

a.. 

0.2 

0 

1.0 

0.8 

>- I-:;;;! 0.6 m 

<( 

m 

0 0.4 a: 

a.. 

0.2 

) 

) 

\_ 

~ 

) 

\ 

"-

0-1o.boo tt -, 

PROBABILITY 

0.95: 0.002 million bbls 

0.05: 15.481 million bbls 

~ r-- -

_I I I 

1o.ooo.-r.ooo 

1

ft 

PROBABILITY 

0.95: 0.001 million bbls 

0.05: 5.769 million bbls 

r----o 

1.0 

0.8 

~ ::::i 0.6 

iii 

<( 

m 

~ 0.4 

a.. 

0.2 

0 

1.0 

0.8 

~ ~ 0.6 

iii 

<( 

co 

~ 0.4 

a.. 

0.2 

) 

\ 

\ .............. 

---

C) 

) 

\ ............ 1---

_I ~ 

1

10.0001 

PROBABILITY 

0.95: 0.002 million bbls 

0.05: 11.121 million bbls 

f..-- ,.... 

-

_I_ I 

10,0,00-20,0010 ft 

PROBABILITY 

0.95: 0.002 million bbls 

0.05: 8.336 million bbls 

,.... 

0 

0 4 8 12 16 20 2 4 6 8 10 12 14 

POOL SIZE, IN MILLIONS OF BARRELS 

FIGURE 15.- Lognormal-probability size distribution of undiscovered Permian oil pools in depths of 0-10,000 and 10,000-

20,000 feet. 

F 10 (25055) = 126.7 * {1- e-z.o.2.2.25o55ttooooo) 

= 84.5 deposits to be discovered 

by 12/31/74 

As 59 discoveries in this size class had been made 

by 1960, the model is forecasting an additional 

84.5-59.0=25.5 fields in class 10 to be discovered 

between 1960 and 1974. In fact, 25 discoveries 

were made in the size class during the 15-year 

period, so the model produced a remarkably accurate forecast. The results of analogous calculations for other classes are presented in table 9. The 

level of accuracy varies among the field-size classes 

and also across the depth intervals. In general, 

however, acceptable agreement was found between the predicted and the acutal levels of 

discoveries. 

The major differences between the actual and 

predicted number of discoveries in the 0-5,000-foot 

depth interval were found in six of the eight 

smallest size classes (table 9). In each of these six 

size classes, the model underpredicted the actual 

level of discovery. These underpredictions occurred because the rate of discovery in these small 

25 

POOL SIZE, IN MILLIONS OF BARRELS 

FIGURE 16.- Lognormal-probability size distributio'1 of undiscovered Carboniferous oil pools in depths of 0-10,000 and 

10,000-20,000 feet. 

size classes accelerated during the 1961-74 time 

period in comparison with the pre-1961 rates of 

discovery. The consequence of these underpredictions is small, however, because most of tl:le fields 

involved contain relatively small amo'lnts of 

petroleum. 

FORECASTING FUTURE RATES OF RECOVERY 

Forecasts of the number of discoveries within 

each field-size class and depth interval were made 

for 20 increments of drilling, each consisting of 

1,000 exploratory wells at the surface. Within each 

of these drilling increments, a portion of the. wells 

on a net-well basis was applied against the expected size distribution of fields remaining to be 

discovered at the start of each drilling inc':'ement. 

The assignments of the net wells to be drilled in 

each drilling increment were taken from extrapolations of the historical trends in the net-well 

penetration in each depth interval versus the 

cumulative wells drilled at the surface through 

197 4. A mathematical function was fitted to each 

of these net-well curves and then extrapolated for 
1.0 

> 0.8 .... 

~ l ~1o,ro ft 

I ~ 0.6 

co 

~ 

co 0.4 

0 

cr: 

a. 0.2 

PROBABILITY 

0.95: 0.003 billion ft3 

\ 0.05: 53.081 billion ft3 

\o 

' 1'---.. 

0 """' 

0 20 40 60 

POOL SIZE, IN BILLIONS OF CUBIC FEET 

1.0 

> 0.8 .... 

4) l 10.~~0,000 ft 

I ~ 0.6 

co 

PROBABILITY 

0.95: 0.003 billion ft3 

~ 0.05: 46.708 billion ft3 

co 0.4 

0 

cr: 

a. 0.2 ~ 

' ......_ ..... 

0 

0 20 40 60 

POOL SIZE, IN BILLIONS OF CUBIC FEET 

1.0 

> 0.8 .... 

) 

DEJPER THfN 20,~0 ft 

) I I ~ 0.6 

co 

PROBABILITY 

0.95: 0.001 billion ft3 

~ 0.05: 32.107 billion ft3 

co 0.4 0 

cr: 

a. 0.2 \> 

"'--. - 0 - 0 20 40 60 

POOL SIZE, IN BILLIONS OF CUBIC FEET 

FIGURE 17.-Lognormal-probability size distribution of undiscovered nonassociated Carboniferous gas pools in depths of 

0-10,000, 10,000-20,000, and deeper than 20,000 feet. 

an additional20,000 exploratory wells to be drilled 

in the future. 

The number of deposits expected to be 

discovered within each field-size class for any 

future increment of exploratory drilling can be 

determined by aggregating the expected number 

of discoveries to be made within each depth interval. The first increment of 1,000 exploratory wells 

drilled at the surface results in 900 net wells in the 

26 

0-5,000-foot interval, 500 net wells in the 

5,000-10,000-foot interval, 130 net wells in the 

10,000-15,000-foot interval, and 35 net wells in the 

15,000-20,000-foot interval. The expected size 

distribution of fields remaining to be discovered at 

the start of the first drilling incremE'llt within each 

of the four depth intervals is shown in tables 10 

through 13. 

The number of discoveries (150.9) forecast within 

the first 1,000-well increment is giv~n in table 14. 

The largest discovery is predicted in class 17 (194.3 

to 388.6 million BOE). This discove':"y (in expectation, 0.1 fields) is predicted to be in the 

15,000-20,000-foot depth interval. VTith the exception of class 1, the largest number of discovered 

fields within a single field-size class is expected to 

occur with class 7 (0.19 to 0.38 million BOE), 

where a total of 16.7 discoveries are expected to be 

made within all four of the depth intervals. 

Comparing the expected number of discoveries 

across the depth intervals reveals a trend in the 

forecast sizes of discoveries. In the shallowest, 

most highly explored depth interval, no discoveries 

are expected to be larger than field-size class 12 

(6.07 to 12.14 million BOE); in the se~ond and third 

depth intervals, discoveries are e:rpected to be 

made to size class 15; and in the deApest interval, 

discoveries are expected in size claFses 16 and 17 

during the first drilling increment. 

A similar table can be made for each of the increments of exploratory drilling. A comparison 

made across the successive drilling increments indicates that the total number of disc-:weries per increment is projected to decline grad·.1ally and that 

the larger discoveries are projected to become less 

frequent. Thus, both the success rath and average 

size of the discoveries are projected t.o decline with 

each successive increment of exploratory drilling. 

CONCLUSIONS 

The discovery-process model pr1~dicts that a 

large number of oil and gas fields remains to be 

discovered- approximately 34,000 fields in the 

basin at depths shallower than 20,000 feet- but 

that most of these fields individually contain very 

small volumes of oil and gas, as the following 

tabulation shows: 

Field size (millions of barrels 

of oil equivalent) 

48.6 and larger ______ _ 

12.14 to 48.6 ________ _ 

1.52 to 12.14 _______ _ 

Number 

6.6 

20.7 

681.6 

Percentage of total remaining 

fields 

0.02 

0.06 

2.00 
TABLE 10.-Expected ultimate number of fields remaining to be discovered after 1971,. in the 0-5,000joot depth interval 

Size class 

1 -------------------------------

2 -------------------------------

3 -------------------------------

4 -------------------------------

5 -------------------------------

6 -------------------------------

7 -------------------------------

8 -------------------------------

9 -------------------------------

10 -------------------------------

11 -------------------------------

12 -------------------------------

13 -------------------------------

14 + -----------------------------

Area (square miles) 

0.13 

.14 

.16 

.22 

.25 

.39 

.49 

.94 

1.23 

2.21 

4.24 

5.40 

8.30 

46.18 

Expected number of Number of fields 

fields remaining found by 197 4 

4,106.1 211 

1,355.3 84 

1,006.3 84 

789.4 9Z 

951.6 127 

625.5 135 

463.5 12r 

175.2 10~ 

130.3 111 

41.4 84-

10.2 75 

2.5 4r 

.1 35 

.0 67 

TABLE 11.-Expected ultimate number of fields remaining to be discovered after 1971,. in the 5,000-10,000joot depth interval 

Size class 

6 -------------------------------

7 -------------------------------

8 -------------------------------

9 -------------------------------

10 -------------------------------

11 -------------------------------

12 -------------------------------

13 -------------------------------

14 -------------------------------

15 -------------------------------

16 + - ----------------------------

Area (square miles) 

0.12 

.12 

.13 

.19 

.20 

.29 

.42 

.47 

.76 

1.28 

2.21 

3.76 

5.40 

10.86 

20.30 

72.14 

Expected number of Number of fields 

fields remaining found by 197 4 

5,462.9 21f 

2,922.0 11f 

2,856.8 12~ 

2,189.6 13f 

2,468.0 164 

1,718.2 16f 

1,382.6 20( 

751.6 16( 

570.5 15f 

245.4 1 '"' 94.6 9f 

26.6 7f 

5.9 5( 

1.5 47 

.2 27 

.0 27 

TABLE 12.-Expected ulh:mate number of fields remaining to be disco'vered after 1971,. in the 10,000-15,000-foot deptf., interval 

Size class 

2 -------------------------------

3 -------------------------------

4 -------------------------------

5 -------------------------------

6 -------------------------------

7 -------------------------------

8 -------------------------------

9 -------------------------------

10 -------------------------------

11 -------------------------------

12 -------------------------------

13 -------------------------------

14 -------------------------------

15 -------------------------------

16 + -----------------------------

Area (square miles) 

0.21 

.22 

.33 

.25 

.31 

.37 

.31 

.43 

.63 

1.30 

1.20 

1.90 

3.89 

4.77 

7.53 

12.67 

27 

Expected number of Number of fields 

fields remaining found by 1974 

511.0 49 

307.9 31 

277.2 36 

400.7 56 

320.6 48 

302.7 53 

325.4 62 

249.1 54 

196.1 62 

97.8 47 

93.1 64 

34.5 4f 

6.3 28 

1.6 21 

.3 18 

.0 r 
TABLE 13.-Expected ultirnate number offields remaining to be discovered ajler 1974 in the 15,000-20,000joot depth interva.l 1 

S1ze elass 

•J 

-------------------------------

3 -------------------------------

4 -------------------------------

5 -------------------------------

9 -------------------------------

10-------------------------------

11 -------------------------------

12 -------------------------------

13 -------------------------------

14 -------------------------------

15 - ------------------------------

16 -------------------------------

17 -------------------------------

18 -------------------------------

Area (square miles) 

1.00 

1.00 

.00 

1.00 

1.00 

.78 

1.00 

.25 

1.00 

2.25 

3.67 

4.00 

4.50 

9.00 

10.50 

9.00 

21.00 

14.00 

Expected number of Number o~ fields 

fields remaining found by 1974 

17.6 

17.6 

.0 0 

26.5 3 

17.6 

35.3 

17.6 

8.8 1 

8.8 1 

22.9 4 

10.7 3 

1.9 1 

2.7 2 

2.6 3 

5.5 9 

.3 1 

.2 1 

.1 1 

1 The USGS resource appraisal group estimated that no oil, and a mean value of 2.29 trillion cubic feet of gas in place, exists below 20,000 feet. 

TABLE 14.-Nurnber of discoveries expected to be made in each size class with the .first ·increment of 1,000 explo'ratory holes drated in 

the Permian Basin after 1974 

Size class 

3 -------------------------------------------------

4 -------------------------------------------------

5 -------------------------------------------------

9 -------------------------------------------------

10 -------------------------------------------------

11 -------------------------------------------------

12 -------------------------------------------------

13 -------------------------------------------------

14 -------------------------------------------------

15 -------------------------------------------------

16 -------------------------------------------------

17 + ------------------------------------------------

0-5,000-

foot depth 

7.5 

3.0 

2.9 

39 

4.3 

4.4 

4.1 

3.0 

2.9 

1.6 

.8 

.3 

.0 

.0 

.0 

.0 

.0 

5,000-10,000-

foot depth 

10.1 

5.4 

5.7 

6.4 

7.6 

7.7 

8.9 

6.9 

6.6 

4.8 

3.2 

1.7 

.6 

.2 

.1 

.0 

.0 

10,000-15,000- 15,000-20,000- Total foot depth foot depth 

2.8 0.3 20.7 

1.7 .3 10.4 

2.0 .0 10.6 

3.1 .4 13.1 

2.6 .3 14.8 

2.9 .5 15.5 

3.4 .3 16.7 

2.!:1 .1 12.9 

3.2 .1 12.8 

2.3 .5 9.2 

2.8 .4 7 •) 

1.7 .1 3.8 

.6 o) 1.4 

.2 .3 .7 

.1 .7 .9 

.0 .0 .1 

.0 .1 .1 

T··~l ------------------------------------------~~~~~~~~~~~~~~~~~~~.~~~~~~~~~~ 38.0 75.9 32.3 4.7 150.9 

The model, thus, predicts that 97.9 percent of the 

oil and gas fields remaining to be discovered in the 

Permian Basin individually contain less than 1.52 

million BOE. 

Furthermore, the model predicts that nearly all 

the expected fields remaining to be discovered that 

contain more than 48.6 million BOE each are 

expected to be in the 15,000-20,000-foot depth interval. In contrast, the 20.7 fields remaining to be 

discovered that individually contain between 12.14 

and 48.6 million BO E are expected to occur in 

approximately equal numbers in the 5,000-

10,000-foot, 10,000-15,000-foot, and 15,000-

20,000-foot depth intervals. The bulk of the smaller 

oil and gas fields expected to remain in the basin 

are predicted by the model to be at depths 

shallower than 10,000 feet. 

28 

A prediction of the rate at which t~ese oil and 

gas fields will be discovered in the future was made 

for 20 successive future 1,000-well in~rements of 

exploratory drilling. The predicted s:ze distribution of discoveries to be made in each of these drilling increments forms one of the basic inputs into 

the economic analysis discussed in "E~ngineering 

and Cost Analysis for Future Fields", and "The Integrating Economic Model." 

ENGINEERING AND COST ANALYS~S FOR 

FUTURE FIELDS 

The costs of oil and gas reserve:" from undiscovered fields were estimated by an engineering 

and cost-analysis model. The model e~timated the 

exploration, development, and producf0n costs for 
the distribution of fields found per 1,000 exploratory wells drilled. The analysis depended on 

the predicted size and depth of undiscovered fields 

provided by the discovery process model discussed 

in "The Discovery-Process Model." 

EXPLORATION COSTS 

For each increment of 1,000 exploratory wells, 

we predicted the average depth by using a function 

estimated from historical data where average 

depth of exploratory wells was specified as a function of the cumulative number drilled since 1956 

in the Permian Basin (see fig. 18). 

To obtain the average cost for drilling and 

equipping future exploratory wells, we fitted a 

function of average costs versus average depth 

(see fig. 19) and used extrapolations of this function. Data used for estimating this function were 

published in the "Joint Association Survey of the 

U.S. Oil and Gas Producing Industry" (American 

Petroleum Institute, 1975). These costs were 

inflated to the appropriate 1977 values. 

We obtained total exploration cost per exploratory well, exclusive of the land acquisition 

cost, by using a fitted function (see fig. 20) that 

specified total exploratory cost per well nersus the 

cost of drilling and equipping exploratory wells, 

from 1966 through 1975 (American Petroleum Institute, 1967-78). For all results presented here, 

land acquisition costs were assumed to l'~ zero. 

FIELD DESIGN AND INVESTMENT CO"TS 

The discovery-process model categori~ed fields 

to be discovered by depth interval and BOE size 

class. Because of the differences involved in the 

economics of oil production and gas production, 

the fields discovered were separated into oil and 

gas fields. Ratios of oil fields to total fhlds were 

projected from a fitted function that specified the 

ratio as a function of depth interval and size class 

(see table 15). 

Field Design. -For oil and gas fields, tl'~ number 

of required development wells was determined by 

dividing nominal field recovery by nominal 

10P--------------r--------------r--------------r--------------r-------------~ 

1-

w 

w 

LL 

LL 

0 

en 

0 

z 

<( 

en 

:::> 

0 

~ s~------------~--------------~~~~------~--------------~------------4 ~ 

::C 

~ w 

0 

....J 

....J 

w 

~ 

>- a: 

0 

~ 6~----~~~--~--------------~------------~--------------~------------4 a: 

0 

....J 

a.. 

X 

w 

w 

(!) 

<( 

a: 

w 

> <( 

~~o------------~2~o--------------3~o--------------4~o--------------5~o------------~6o 

CUMULATIVE EXPLORATORY WELLS, IN THOUSANDS 

FIGURE 18.-Average depth of exploratory wells as a function of cumulative exploratory wells drilled in the Permian Basin. 

29 
5 10 15 

WELL DEPTH, IN THOUSANDS OF FEET 

FIGURE 19.-Exploratory well drilling and equipping costs as a function of well depth in the Permian Basin in 1975 (1977 costs can 

be obtained by increasing by 18.9 percent). 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

TABLE 15.-Ratio of oil fields to total fields 

in the Permian Basin 

Size class 0-5,000- 5,000-10,000- 10,000-15,000-

foot depth foot depth foot depth 

----------------------- 0.86 0.84 0.54 

----------------------- .78 .78 .51 

----------------------- .72 .73 .49 

----------------------- .68 .69 .47 

----------------------- .65 .67 .45 

----------------------- .65 .66 .43 

----------------------- .65 .66 .41 

----------------------- .67 .67 .40 

----------------------- .70 .69 .39 

----------------------- .73 .71 .37 

----------------------- .77 .73 .36 

----------------------- .81 .76 .36 

----------------------- .86 .79 .35 

----------------------- .90 .82 .35 

----------------------- .94 .85 .35 

----------------------- .97 .87 .34 

----------------------- 1.0 .89 .35 

----------------------- 1.0 .90 .35 

----------------------- 1.0 .91 .35 

----------------------- 1.0 .90 .36 

reserves per well. We estimated the nominal 

values for fields under primary recovery only by 

extrapolating :fitted curves (reserves versus size 

class), which we estimated by using historical· 

values from those fields that have undergone 

primary production only. We used a similar procedure for determining reserves per producing 

30 

TABLE 16.-Expected ultimate oil recovery per field 

in the Permian Basin 

Size class 

1 -----------------------

2 -----------------------

3 -----------------------

4 -----------------------

5 -----------------------

6 -----------------------

7 -----------------------

8 -----------------------

9 -----------------------

10 -----------------------

11 -----------------------

12 -----------------------

13 -----------------------

14 -----------------------

15 -----------------------

16 -----------------------

17 -----------------------

18 -----------------------

19 -----------------------

20 -----------------------

[Million barrels) 

0-5,000-

foot depth 

0.002 

.007 

.013 

.027 

.054 

.108 

.216 

.433 

.868 

1.740 

3.500 

7.010 

14.100 

28.200 

56.700 

114.000 

228.000 

458.000 

918.000 

1,840.000 

5,000-10,000 10,000-15,000-

foot depth foot depth 

0.002 

.005 

.011 

.022 

.044 

.090 

.181 

.367 

.741 

1.500 

3.030 

6.130 

12.400 

25.000 

50.600 

102.000 

207.000 

418.000 

846.000 

1,710.000 

0.002 

.005 

.011 

.021 

.042 

.084 

.166 

.330 

.656 

1.300 

2.590 

5.150 

10.200 

20.300 

40.400 

80.300 

160.000 

317.000 

630.000 

1,250.000 

well and ultimate recovery for (1) oil fhlds susceptible to secondary recovery and (2) nonassociated 

gas fields. These basic data are presented in tables 

16-22. For completeness, values were included for 

oil fields deeper than 15,000 feet where no 

historical oil fields existed. Ultimate oil recovery 
1000~----------~-------------r------------.-----------~r-------·-----, 

.....1 

.....1 

w 

~ 

t-~ffi 

~c.. 

800~----------~------------+------------t------------t---------~~ 

(.)(/) 

z a: 600 

o::S i=o 

~Q 

Ou.. 

i[o 

X (f.) 

wo .....1 z 400 .. •-----------------+-------------~~~:_--------------1-----------------1-----------------1 << I- (f.) 

O::J t-o ::I: 

1-

~ 

0 oL_ ____________ 1L00------------~2~0~0------------3~0~0~----------~4~00~----------~500 

DRILLING AND EQUIPPING COSTS, IN THOUSANDS OF DOLLARS PER WELL 

FIGURE 20. -Total exploration cost per exploratory well (minus cost of acquiring undeveloped acreage) as a function of drilling cost 

per well in 1977. 

TABLE 17.-Expected ultimate oil recovery per well from 

primary oil fields in the Permian Basin 

[Thousand barrels) 

Size class 0-5,000- 5,000-10,000- 10,000-15,000- foot depth foot depth foot depth 

1 ----------------------- 1.490 1.930 2.160 2 ----------------------- 4.280 4.070 4.170 3 ----------------------- 7.580 8.670 9.590 4 ----------------------- 11.800 15.900 18.900 5 ----------------------- 17.300 25.900 32.400 6 ----------------------- 24.500 39.000 50.700 7 ----------------------- 33.800 55.100 74.100 8 ----------------------- 45.700 74.600 103.000 9 ----------------------- 53.300 82.900 136.000 10 ----------------------- 54.900 118.000 198.000 11 ----------------------- 68.900 132.000 261.000 12 ----------------------- 95.600 140.000 333.000 13 ----------------------- 135.000 154.000 419.000 14 ----------------------- 188.000 189.000 526.000 15 ----------------------- 254.000 258.000 662.000 16 ----------------------- 334.000 374.000 834.000 17 ----------------------- 428.000 550.000 1,050.000 18 ----------------------- 536.000 802.000 1,310.000 19 ----------------------- 658.000 1,140.000 1,630.000 20 ----------------------- 794.000 1,580.000 2,010.000 

per field and ultimate gas recovery per well were 

projected, and ultimate oil recovery per well was 

set equal to the same value as the 

10,000-15,000-foot interval values. 

31 

TABLE 18. -Expected ultimate associated-dissolved gas 

recovery per oil well from primary fields in the Permian Basin 

[Million cubic feet at 14.73 psia (pounds per square inch absolute) and 60° F) 

Size class 0-5,000- 5,000-10,000- 10,000-15,000-

foot depth foot depth foot depth 

1 ----------------------- 1.490 4.320 7.470 2 ----------------------- 4.740 9.210 14.400 3 ----------------------- 9.050 20.100 32.000 4 ----------------------- 15.200 38.400 63.000 5 ----------------------- 24.100 65.700 110.000 6 ----------------------- 36.500 103.000 175.000 7 ----------------------- 53.200 153.000 261.000 8 ----------------------- 75.100 216.000 371.000 9 ----------------------- 81.900 266.000 506.000 10 ----------------------- 117.000 327.000 657.000 11 ----------------------- 164.000 389.000 806.000 12 ----------------------- 223.000 453.000 1.070.000 13 ---------------------- 293.000 518.000 1.460.000 14 ----------------------- 374.000 584.000 1.960.000 15 ----------------------- 467.000 652.000 2,580.000 16 ----------------------- 572.000 721.000 3 320.000 17 ----------------------- 688.000 1,080.000 4.170.000 18 ----------------------- 816.000 1,570.000 5 150.000 19 ----------------------- 955.000 :~.240.000 6 240.000 20 ----------------------- 1,110.000 :J,100.000 7,450.000 

For technical reasons, secondary-r€~overy 

techniques are not applicable to some oil £Blds. A 

ratio of primary oil fields to total oil fields was 

derived for each size and depth class of oil field. 
TABLE 19. -Expected ultimate ail rerovery per weU from secmulJJ,ry 

arui ']Jf'eSSUre maintenance fields in the Permian Basin 

[Thousand barrels) 

Size class 0-5,000- 5,000-10,000- 10,000-15,000-

foot depth foot depth foot depth 

1 ----------------------- 2 -----------------------

3 -----------------------

4 -----------------------

5 -----------------------

6 ----------------------- 12.500 41.500 

7 ----------------------- 20.300 49.100 

8 ----------------------- 28.500 58.400 

9 ----------------------- 37.200 69.500 107.000 

10 ----------------------- 46.300 82.300 131.000 

11 ----------------------- 55.800 96.900 154.000 

12 ----------------------- 65.800 161.000 178.000 

13 ----------------------- 76.300 176.000 202.000 

14 ----------------------- 87.200 186.000 336.000 

15 ----------------------- 99.600 219.000 484.000 

16 ----------------------- 129.000 304.000 648.000 

17 ----------------------- 195.000 456.000 828.000 

18 ----------------------- 298.000 624.000 1,020.000 

19 ----------------------- 438.000 831.000 1,230.000 

20 ----------------------- 614.000 1,070.000 1,460.000 

TABLE 20.-Expected ultimate gas recovery per oil well from 

secondary and pressure maintenance fields in the Permian 

Basin 

[Million cubic feet at 14.73 psia (pounds per square inch absolute) and 60° F] 

Size class 

1 -----------------------

2 -----------------------

3 -----------------------

4 -----------------------

5 -----------------------

6 -----------------------

7 -----------------------

8 -----------------------

9 -----------------------

10 -----------------------

11 -----------------------

12 -----------------------

13 -----------------------

14 -----------------------

15 -----------------------

16 -----------------------

17 -----------------------

18 -----------------------

19 -----------------------

20 -----------------------

0-5,000-

foot depth 

12.000 

23.400 

34.900 

46.300 

57.800 

69.200 

80.600 

92.100 

104.000 

122.000 

145.000 

185.000 

242.000 

315.000 

405.000 

5,000-10,000-

foot depth 

93.500 

111.000 

136.000 

168.000 

208.000 

254.000 

374.000 

400.000 

420.000 

452.000 

514.000 

622.000 

796.000 

1,050.000 

1,410.000 

10,000-15,000-

foot depth 

348.000 

464.000 

580.000 

695.000 

811.000 

1,360.000 

1,910.000 

2,470.000 

3,020.000 

3,580.000 

4,100.000 

4,680.000 

TABLE 21.-Expected ultimate nona.ssociated gas reco·very 

per· .field in the Perm·ian Basin 

[Million cubic feet at 14.73 psia (pounds per square inch absolute) and 60° F] 

Size class 0-5,000- 5,000-10,000- 10,000-15,000- Greater than foot depth foot depth foot depth 15,000-foot depth 

1-4 86 102 95 102 5 366 347 334 286 6 704 720 756 839 7 1,364 1,412 1,412 1,269 8 2,670 2,991 2,836 3,234 9 5,544 5,418 5,130 5,562 10 11,206 11,368 10,773 10,989 11 20,760 21,690 20,560 26,528 12 47,355 48,735 46,554 43,860 13 95,245 85,407 86,184 96,964 14 185,319 186,912 180,455 160,376 15 361,284 3!:l0,010 400,842 359,114 16 714,015 554,960 713,600 852,826 17 1,490,688 1,452,192 1,278,025 1,935,413 18 2,889,936 2,634,969 2,645,554 3,341,724 19 6,140,000 6,140,000 6,140,000 6,140,000 20 12,300,000 12,300,000 12,300,000 12,300,000 

32 

TABLE 22.-Expected ultimate nonassociated gas recovery 

per well in the Permian Basin 

[Million cubic feet at 14.73 psia (pounds per square inch absolute) and 60° F) 

Size class 0-5,000- 5,000-10,000· 10,000-15 000- Greater than 

foot depth foot depth foot derth 15,000-foot depth 

1-4 86 51 95 102 

5 183 347 334 286 

6 352 360 756 839 

7 341 706 706 1,269 

8 -------- 445 997 1,418 1,617 

9 504 1,357 2,565 2,781 

10 862 1,624 3,591 3,663 

11 1,038 2,169 5,140 6,632 

12 1,155 2,565 7,759 10,965 

13 2,215 4,067 12,312 13,852 

14 3,141 5,841 16,405 20,047 

15 4,301 9,070 22,269 25,651 

16 5,805 13,874 28,544 32,801 

17 7,764 25,932 36,515 41,179 

18 10,248 28,333 45,613 49,143 

19 10,248 28,333 45,rJ3 49,143 

20 10,248 28,333 45,fl.3 49,143 

This ratio was used to apportion oil fields to be 

discovered into: (1) fields susceptible to primary 

recovery alone, and (2) fields susceptible to both 

primary and secondary recovery. Tr~se ratios are 

presented in table 23. 

TABLE 23.-Ratio of primary oil .fields to total oil fields 

in the Perrnia.n Ba.sin 

Size class 

1 -----------------------

2 -----------------------

3 -----------------------

4 -----------------------

5 -----------------------

6 -----------------------

7 -----------------------

8 -----------------------

9 -----------------------

10 -----------------------

11 -----------------------

12 -----------------------

13 -----------------------

14 -----------------------

15 -----------------------

16 -----------------------

17 -----------------------

18 -----------------------

19 ----------------------- 20 

0-5,000-

foot depth 

1.000 

1.000 

1.000 

1.000 

1.000 

.984 

.958 

.891 

.781 

.636 

.474 

.318 

.188 

.097 

.048 

.030 

,025 

.013 

.000 

.000 

5,000-10,000- 10,000-15,000-

foot depth foot depth 

1.000 1.000 

1.000 1.000 

1.000 1.000 

1.000 1.000 

1.000 1.000 

.986 1.000 

.983 1.000 

.972 1.000 

.940 .981 

.881 .962 

.792 .938 

.679 .895 

.554 .818 

.429 .693 

.315 .515 

,213 .307 

.119 .116 

.032 .001 

.000 .000 

,000 .000 

Depth intervals were: (1) 0-5,000 feet, 

(2) 5,000-10,000 feet, (3) 10,000-15,000 feet, and 

(4) greater than 15,000 feet. Average depths 

(based on historical data) for oil fields corresponding to each interval were: (1) 3,400, (2) 7,200, 

(3) 11,400, and (4) 16,000 feet (no historical 

fields). The average depths for nonassociated gas 

fields were: (1) 3,400, (2) 7 ,200, (3) 12,200, and 

(4) 17,700 feet. 

For those fields susceptible to secondaryrecovery methods, the design and assumptions of 

the recovery program depended on the field's 

depth interval. 
(1) In the 0-5,000-foot interval, the primary producing wells were assumed to constitute 70 

percent of all the wells that produced oil. In 

the secondary-recovery program, the remaining 30 percent of the producing wells 

were drilled, and a sufficient number of 

primary producing wells were converted to 

injection wells so that there was one injection well for each producing well. 

(2) For the interval between 5,000 and 10,000 

feet, the number of newly drilled injection 

wells is given by the relationship: 

WNI=((PH)'12 -1)2 

where WNI is the number of newly drilled 

injection wells and PH is the number of 

primary producing wells. This relationship 

provides the number of wells needed to 

infill drill the centers of a square array of 

wells that produced during the primary 

stage. The number of primary producers 

that must be converted to injection wells is 

such that there is a one-to-one ratio of producing to injection wells during secondary 

recovery. 

(3) In the two intervals deeper than 10,000 feet, 

it is assumed that a pressure maintenance 

program was carried out from the initial 

stage of development. For each set of four 

primary producing wells, an injection well 

was drilled. 

Investment Costs.- We estimated drilling and 

equipping costs for production wells, and dry-hole 

costs, using data taken from the "Joint Association 

Survey of the U.S. Oil and Gas Producting Industry" (American Petroleum Institute, 1975). 

Drilling costs were inflated to attain mid-1977 cost 

levels. The drilling and equipping costs were 

expressed as a fitted function of depth. Figures 21 

and 22 present the estimated functions. 

Costs of dry development wells for all fields were 

included by increasing costs of each producing well 

by 19 percent of the cost of a dry hole. Using the 

U.S. data from 1971 through 1975, we found that 

the ratio of dry to successful development 'vells did 

not depend strongly on depth; therefore, the 

average ratio for all depths was used. 

Cost estimates for field lease equipme'l.t were 

based on data from Dietzman, Pierce, Funk, and 

Anderson (1978). Costs of oil-field lease eq'Iipment 

were expressed as a function of well depth (see fig. 

23). The cost curve shown in figure 23 is derived 

from a combination of rod-pumped operatjons to a 

maximum of 8, 000 feet, and hydraulically pumped 

operations from 8,000 to 12,000 feet. Costs of 

nonassociated gas-field equipment were eYoressed 

as a function of well depth and field size (f~e table 

24). 

PRODUCTION SCHEDULES AND PRODUCTION COSTS 

Production Schedules.- Size classes for all fields 

were based on a BOE scale. The classes ranged 

from the smallest at 0 to 5,930 BOE to the largest 

at 1,554.5 million to 3,109.0 million BOE. The upper limit of each class is double the upper limit of 

the next smaller class. The nominal fhld size 

estimated for each class base is based upon 

averages of known fields, as mentioned earlier. 

For each oil field, the primary production 

schedule for representative producing oil wells was 

prepared by using representative expon~"ltial oil 

well decline rates (see table 25) and a calcuhtted initial producing rate (depending upon the oil 

recovery per well) limited by the Texas allowable 

yardstick. Three examples of primary oilTABLE 24.-Cost of lease equipment per nonassociated gas development well in the Permian Basin in 1977 dollnrs 

Size class 

1-4 -----------------------------

5 -------------------------------

6 -------------------------------

7 -------------------------------

8 -------------------------------

9 -------------------------------

10 -------------------------------

11 -------------------------------

12 -------------------------------

13 -------------------------------

14-------------------------------

15 -------------------------------

16-------------------------------

17 -------------------------------

18 -------------------------------

19 -------------------------------

20 -------------------------------

[Surface producing equipment from wellhead to flange on meter run] 

Ultimate recoverable 

range (thousand cubic feet) 

0 to 0.25 

0.25 to 0.5 

.5 to 1 

1 to 2 

2 to 4 

4 to 8 

8 to 16 

16 to 32 

32 to 64 

64 to 128 

128 to 256 

256 to 512 

512 to 1,024 

1,024 to 2,048 

2,048 to 4,096 

4,096 to 8,192 

8,192 to 16,380 

0-5,000-

foot depth 

$13,000 

13,000 

13,000 

13,000 

13,000 

13,000 

13,000 

13,000 

13,000 

13,000 

13,000 

13,000 

13,000 

13,000 

20,500 

20,500 

20,500 

33 

5,000-10,000-

foot depth 

$14,000 

14,000 

14,000 

14,000 

14,000 

14,000 

14,000 

14,000 

14,000 

21,500 

21,500 

21,500 

21,500 

27,000 

27,000 

27,000 

27,000 

10,000-15,000-

foot depth 

$16,000 

16,000 

16,000 

16,000 

16,000 

16,000 

23,500 

23,500 

23,500 

23,500 

23,500 

24,500 

30,500 

43,500 

45,000 

45,000 

45,000 

Greater than 15,000· 

foot depth 

$1'l,OOO 

16,000 

16,000 

16,000 

16,000 

16,000 

23,500 

23,500 

23,500 

23,500 

21,500 

2t500 

31,500 

4'3,500 

45,000 

45,000 

45,000 
5 10 15 20 25 

WELL DEPTH, IN THOUSANDS OF FEET 

FIGURE 21.-Drilling and equipping cost per development well versus depth in the Permian Basin in 1975 (1977 costs can be obtained by increasing by 18.9 percent). 

production schedules are shown in figure 24. For 

oil fields undergoing secondary recovery, we 

calculated the well-production schedule during the 

secondary-recovery phase by using a percentage of 

remaining ultimate well recovery each year, on the 

basis of a nominal 10-year waterflood life. 

TABLE 25.-Exponential oil-well decline rates per year in the 

Permian Basin 

Size class 

1 -----------------------

2 -----------------------

3 -----------------------

4 -----------------------

5 -----------------------

6 -----------------------

7 -----------------------

8 -----------------------

9 -----------------------

10 -----------------------

11 -----------------------

12 -----------------------

13 -----------------------

14 -----------------------

15 -----------------------

16 -----------------------

17 -----------------------

18 -----------------------

19 -----------------------

20 -----------------------

0-5,000· 

foot depth 

1.50 

1.00 

.90 

.35 

.29 

.24 

.22 

.22 

.22 

.22 

.22 

.20 

.20 

.20 

.20 

.20 

.20 

.20 

.20 

.20 

5,000-10,000- 10,000-15,0~0-

foot depth foot depth 

1.50 1.50 

1.10 1.10 

1.00 1.00 

.51 .61 

.38 .40 

.34 .35 

.32 .35 

.32 .29 

.32 .29 

.24 .29 

.24 .29 

.21 .20 

.21 .20 

.21 .20 

.20 .20 

.20 .20 

.20 .20 

.20 .20 

.20 .20 

.20 .20 

34 

Production streams for associated/dissolved gas 

from all oil fields were based on t'-:te percent of 

cumulative oil production to the percent of 

cumulative gas production, a relationship that was 

derived from an engineering materi~.l balance approximating a depletion drive reservoir (see fig. 

25). 

Production schedules for nonassoci::tted gas wells 

were assumed to initially show con~tant production based on a daily contract quantity of 1 million 

standard cubic feet per 3 billion cubic feet of 

nominal reserves per well. The period of constant 

production was based upon th~ calculated 

deliverability characteristics for a well of a field of 

a given size and depth class (Hicks, 1978). An exponential decline was used to descri'-le production 

after the production decline began (see fig. 26). 

Production Costs. -For oil wells and for 

nonassociated gas wells, direct op~rating costs 

were expressed as a function of beth depth and 

output. Basic cost data were taken f11

om Dietzman 

and others (1978) and inflated by 14 percent (see 

fig. 27 and 28 and table 26). 
2000 en 

a: 

<l: 

....J 

....J 

0 

Q 

Ll.. 

0 

en 

c 1500 z 

<l: 

en 

::J 

0 

J: 

~ 

~ 

w' 

....J 

0 1000 

J: 

>- a: 

Q 

~ 

z 

w 

~ 

a.. 

0 

....J 500 w 

> w 

Q 

Ll.. 

0 

~ 

en 

0 

u 

10 15 20 

WELL DEPTH, IN THOUSANDS OF FEET 

FIGURE 22. -Cost of development of dry hole versus depth in the Permian Basin in 1975 (1977 costs can be obtained by increasing 

by 18.9 percent). 

TABLE 26.-A nnua.l direct operating expenses for nonassocia.ted gas wells ·in the Perm·ian Basin in 1977 dollars 

Size class 0-5,000- 5,000-10,000- 10,000-15,000- More than foot depth foot depth foot depth 15,000-foot depth 

1-4 $3,600 $4,200 $5,800 $8,800 5 3,600 4,300 5,900 8,800 6 3,600 4,300 5,900 8,900 7 3,600 4,300 5,900 8,900 8 3,600 4,300 6,000 8,900 9 3,600 4,300 6,100 9,000 10 3,600 4,400 6,200 9,100 11 3,700 4,400 6,300 9,400 12 3,700 4,500 6,600 9,800 13 3,800 4,600 7,000 10,100 14 3,800 4,800 7,400 10,700 15 4,000 5,100 8,000 11,300 16 4,100 5,500 8,600 12,000 17 4,300 6,800 9,500 13,000 18 4,500 7,000 10,500 13,800 19 4,500 7,000 10,500 13,800 20 4,500 7,000 10,500 13,800 

Indirect operating expenses include general and 

administrative overhead costs and certain property taxes. These costs are expressed on a per unit 

output basis and were set as $0.229 per barrel of oil 

and $0.0435 per 1,000 cubic feet of gas. 

35 

We calculated recovery per well for each price 

and return by accumulating annual production and 

assuming that production stops when the economic 

limit rate is reached. The economic limit if reached 

when the sum of operating costs and productionrelated taxes exceeds the operator's reveT}Ue. 

ASSUMPTIONS FOR PRESENT VALUE CALCULATIONS 

The following assumptions were used in the 

calculations of present values: 

(1) A 5-year limit on the carryover of hsses for 

income tax purposes. 

(2) Operators' working interest was 87.5 

percent. 

(3) State, county, and school property taxes and 

wellhead severance taxes are rollo.d into a 

royalty type tax of 6.4 percent of gross income for oil and 9.3 percent of gross income for gas. 

(4) Federal income tax rate was 48 percent. 

(5) Depreciation method was unit of production 

method. 
100-----------------r----------------~---------------r----------------, 

..J 

..J 

w 75 ~ 

·ffi 

t;;a.. 

o(J) 

Ua: 

t-< zj 

wo 

~CI a.. 50 - u. 

~0 W(J) 

wCI 

(J)Z 

<t:< w(J) 

..J:::::> 

0 

I 

I- 25 ~ 

4 8 12 16 

WELL DEPTH, IN THOUSANDS OF FEET 

FIGURE 23.-Lease equipment cost per well versus depth for primary oil production in the Permian Basin in 1976 (1977 costs can be 

obtained by increasing by 9.0 percent). 

(6) Cost depletion was applied when determining taxable income. 

(7) Costs were based on mid-1977 prices, and the 

entire analysis assumed constant 1977 

dollars. 

(8) 70 percent of drilling costs for successful 

development wells along with dry-hole 

costs were expensed, and the remaining 

field-development costs were capitalized. 

(9) Natural-gas prices were tied to the price of 

oil on a Btu basis. 

ESTIMATED MARGINAL COST FUNCTIONS FOR 

UNDISCOVERED RECOVERABLE OIL AND GAS 

RESOURCES IN THE PERMIAN BASIN 

Economic analysis of the exploration process 

begins with the relationship between incremental 

units of exploration effort and the number and size 

36 

of fields discovered as a consequence of these units 

of effort. 

The portion of the resource base that is physically discoverable is restricted by the state-of-the-art 

of exploration technology. That portion always 

represents less than 100 percent of the undiscovered fields that may actually exist. Within 

this "effective upper limit" of a region's 

discoverable oil and gas, we expect the amounts 

found per unit effort to decrease as cumulative exploration increases. However, a technical 

breakthrough in exploration can change the upper 

limit of what is discoverable and can increase the 

amounts discovered per unit of effort. 

Given a discovery, the analysis shifts to the function that describes physical relationships involved 

1n the recovery of in-place resource~ .. Again the 
...J 

...J 

w 

~ 

60 

50 

'a: 40 Zw 

oa.. 

i=CJ) 

u...J 

::>w 

oa:: 

~~ a.. al 30 ...JU. 60 

...JCJ) 

<(0 

::>Z 

z<( 

ZCJ) 

<(::> 

~ 20 

I-

~ 

10 

5 10 15 20 25 30 35 

TIME, IN YEARS 

FIGURE 24.-Oil-production-decline curves for primary recovery at 7,200 feet in the Permian Basin. 

state-of-the-art in production technology places an 

upper limit on the portion of oil and gas that can be 

physically recovered and produced. Even when the 

analysis includes future tertiary-recovery 

technology, less than 100 percent of the oil and gas 

in place is recovered. 

In "Permian Basin Undiscovered Resources Appraisal," we discussed in detail subjective appraisals of the undiscovered oil and gas in place in 

the Permian Basin. In "The Discovery-Process 

Model," we described exploration and provided 

direct estimates of the number of fields that might 

be discovered with incremental units of exploratory effort. Estimates of what is recoverable 

from these future "discoveries" were th~n determined by using the field-development information, 

production-decline curves, and cost data described 

in "Engineering and Cost Analysis for Future 

Fields." 

37 

The Permian Basin resource estimates and the 

discovery-process model were prep11red by 

separate task groups working concurrently, rather 

than sequentially. As a consequence, worl· remains' 

to be done in integrating more fully the Fubjective 

resource estimates and the historic discovery data 

projected by the discovery-process model. 
>- a: 

100 

~ 80 

0 

u 

w 

a: 

(/) 

<( 

(!) 

~ 60 

<( 

~ 

~ ::l 

0 

w 

1-

~ 40 CL 

X 

w 

u. 

0 

1-

z 

w 

~ 20 w 

c.. 

20 40 60 80 100 

PERCENT OF EXPECTED ULTIMATE OIL RECOVERY 

FIGURE 25.- Percent of expected ultimate gas recovery as a function of percent of expected ultimate oil recovery in the 

Permian Basin. 

METHODOLOGY 

This section is concerned with estimates of 

marginal cost functions for undiscovered 

recoverable oil and gas resources in the Permian 

Basin. We constructed the marginal cost curves by 

using the methods described in "The DiscoveryProcess Model" and "Engineering and Cost 

Analysis for Future Fields" and considering a 

return on investment and market prices of oil and 

gas. 

The return and price considerations assume that 

i~cremental units of exploration, development, and 

production effort will not take place unless the expected revenues received for eventual production 

sufficiently cover the incremental costs, including a 

normal rate of return on investment. The costs per 

38 

barrel of oil or per 1, 000 cubic feet of gas 

discovered, developed, and produced in the Permian Basin increase as additional units of effort increase. The marginal cost functions p:--esented here 

show how much of the theoretically di"coverable oil 

and gas, identified in "Permian Basin Undiscovered Resource Appraisal" and "The 

Discovery-Process Model," would be classified as 

recoverable at alternative prices and rates of 

return. 

The output of the discovery-proces" model for a 

given increment of exploration is a frequency 

distribution of the expected number cf fields found 

for a particular size and depth catego:--y, where the 

size is expressed in BOE. To estimate the marginal costs of finding and developing these undiscovered fields, the fields must be cr.tegorized as: 
500 

400 

a: 

<( 

w 

>-

za:: 

ow 

-0.. 

~~ uw 300 =>w gu. 

a::u 

O..iij 

(/):::> 

<(U 

c.9u.. 

...Jo 

<((/) 200 :::>z 

zo 

z- <C:::l ~ 

~ 

100 

5 10 15 20 25 30 

TIME, IN YEARS 

FIGURE 26.- Nonassociated gas-well-production curve for a class-13 field in the depth bracket of 0-5,000 feet in the 

Permian Basin. 

(1) crude oil and associated-dissolved gas and 

(2) nonassociated gas. The deposits in the "crude 

oil and associated-dissolved gas" category are then 

classified as: (1) technically susceptible to primaryrecovery techniques alone, and (2) susceptible to 

both primary and secondary techniques. These 

categories are necessary for a more accurate identification of the appropriate production processes 

and their related costs. 

The economic analysis of the deposit is a standard application of discounted cash flows (DCF). 

The net after-tax cash flow for a representative 

producing well is calculated and then discounted at 

various rates of return. The cash flows are obtained by subtracting operating costs, capital 

costs, and taxes from product revenues. If the 

calculations indicate that the DCF at an assumed 

price level and rate of return is negative, that 

deposit is considered uneconomic and will not be 

produced. 

The model can be applied in a straig'ltforward 

manner to determine which deposits will be produced after discovery and how much oil and gas 

will be recovered under specific price and cost conditions. Determining how many additional exploratory wells will be drilled is more dircult. The 

dynamics of the exploration process are not well 

understood, and probably no model can simulate 

actual practice realistically. However, it is possible 

to assume classical economic behavior unier conditions of perfect knowledge. Then, the number of 

exploratory wells drilled can be determined on the 

basis of the present value of future exploration cost 

being equivalent to the present value o:f develop39 
15~----------------------~-----------------------,------------------------, 

.....J 

.....J 

w 

~ 

(J)C::: 

1-W 10 (/)0.. 

0(/) 

ua: 

(,9<( 

z.....J _.....J 

1-0 

<x:o 

a: 

LULl. 

c..o 

0(/) 

.....JCI 

<z 

:::::>c:x: 

Z(J) 

z:::::> 5 

<X:O 

:I: 

I-

~ 

oo~----------------------~5~----------------------~10----------------------~15 

WELL DEPTH, IN THOUSANDS OF FEET 

FIGURE 27.-Annual direct operating cost per producing oil well versus depth for primary recovery in the Permian Basin in 1976 

(1977 costs can be obtained by increasing by 14 percent). 

ment (exclusive of exploration cost). In other 

words, the positive surplus of present value obtained through developing the various fields must 

eventually provide a cash flow adequate to pay for 

the number of exploratory wells drilled. Recognizing the narrowness of these assumptions, the study 

group estimated the number of exploratory wells 

that could be drilled (in increments of 1,000 wells) 

until the incremental cost of drilling exploratory 

wells was equal to or greater than the present 

value of the developed deposits discovered by the 

last 1,000 exploratory-well increment. This point 

varied with the price and rate of return assumed. 

SUMMARY OF RESULTS 

Table 27 provides estimates of the oil and gas 

resources that could be found and produced from 

40 

the Permian Basin as a function of J: rice, finding 

cost, and production cost. The prices, rates of 

return, and number of exploratory wells that 

would be justified under the assumptions made are 

indicated. If the price is assumed to be $40 per 

BOE, the economically recoverable oil equivalent 

attains a maximum of 4. 7 billion BOY: at a 5 percent rate of return, 4.3 billion BOE at a 15 percent 

rate of return, and 3.9 billion BOE at a 25 percent 

rate of return. These quantities can b~ compared 

with the 38.2 billion BOE already discovered in the 

Permian Basin by the end of 1974. 

Between 30,000 (at 25 percent rate of return) 

and 48,000 (at 5 percent rate of return) exploratory 

wells were estimated to be economic~.lly viable at 

the $40 price level. Figure 29 shows how the exploratory effort varies as price and rG'.te of return 
50~--------------------~----------------------,----------------------, 

40 ....I 

....J 

w 

~ 

en a: 1-W 

(1.)0.. 

0(/) 

uc:: 30 (.!)<( z....l _....J 

1-0 <(C 

c:: 

wu. a..O 

0(/) 

....JC 

<Cz ::::><( 

Z(f.) 

20 

z::::> 

<CO I 

I-

~ 

10 

ooL------------------------4~----------------------....Js~--------------------~,2 

WELL DEPTH, IN THOUSANDS OF FEET 

FIGURE 28. -Annual direct operating cost per producing oil well versus depth for secondary recovery in the Permian B<~.sin in 1975 

(1977 costs can be obtained by increasing by 14 percent). 

vary. This can be compared with the slightly more 

than 30,000 exploratory wells which were drilled in 

the Permian Basin through December 31, 1974, in 

which approximately 10 times more BOE were 

discovered than the BOE projected for the next 

30,000-48,000 wells. 

At $15 a barrel and a 15 percent rate of return, 

only 12,000 exploratory wells would be drilled and 

2.3 billion BOE reserves added. The model can be 

used to answer two questions: (1) what price and 

rate of return are required to stimulate a certain 

level of exploration to find a given amount of oil 

and gas in BOE's?; or, (2) what amount of oil and 

gas can be anticipated from the Permian Basin at 

the present or some future price and rate of 

return? 

The output of the model can be examined m 

41 

terms of associated-dissolved gas, non~.ssociated 

gas, and oil resulting from various price levels and 

rates of return. The graphs shown in figures 30-32 

reveal the declining size of the targets discovered 

as a result of additional exploratory effort. As the 

marginal cost curves turn sharply upward, oil- and 

gas-reserve additions to be gained at costs of $10 

to $25 per barrel are considerably greater than 

those at $25 to $40 per barrel. 

Another interesting result shown in the analysis 

is the dominance of nonassociated gas in the remaining resources in the Permian B~sin. This 

dominance is true under all price and rate-of-return assumptions. When nonassociated gas is 

added to the associated-dissolved gas:, crude oil 

represents only about one-quarter of the future 

potential. 
TABLE 27.-PotenNal recoverable oil and ga.s resources from. fu.tu.re d·iscoveri.es in the Permian Basin as a function of output price, ma·rginal finding 

cost, marginal production cost, exploratory wells, and return on investment (ROI) 

[BOE, barrels of oil equivalent; Tcf, trillions of standard cubic feet of natpral gas] 

CUMULATIVE POTENTIAL RESOURCES 

Output Cumulative 

ROI exploration a Marginal oosts2 Associated gas Nonassociated gas price (percent) wells' ($/BOE) (in thousands) Finding Production OilBOE Tcf BOE Tcf BOE Total BOE 

($/BOE) ($/BOE) (in billions) (in billions) (in billions) (in billions) 

10 -------- 5 10 $ 2.64 $ 7.36 0.489 1.371 0.260 6.803 1.291 2.040 

15 5 1.67 8.33 .264 .750 .142 4.234 .803 1.209 

25 2 1.26 8.74 .108 .304 .058 1.948 .370 .536 

15 -------- 5 19 4.58 10.42 .813 2.273 .431 9.384 1.781 3.025 

15 12 3.00 12.00 .578 1.614 .306 7.559 1.434 2.318 

25 8 2.15 12.85 .417 1.164 .221 5.982 1.135 1.773 

;!:>-

1:\:1 20 -------- 5 26 6.40 13.60 1.013 2.822 .535 10.654 2.022 3.570 

15 18 4.30 15.'/0 .792 2.205 .419 9.170 1.740 2.951 

25 12 2.97 17.03 .582 1.621 .308 7.586 1.436 2.326 

25 -------- 5 33 8.49 16.51 1.178 3.276 .622 11.610 2.203 4.003 

15 24 5.79 19.21 .965 2.684 .509 10.332 1.961 3.435 

25 17 4.03 20.97 .763 2.121 .393 8.954 1.699 2.865 

30 5 38 10.30 19.70 1.278 3.536 .670 12.220 2.319 4.268 

15 29 7.14 22.86 1.094 3.014 .572 11.110 2.108 3.774 

25 22 5.19 24.81 .918 2.547 .483 9.996 1.897 3.298 

35 -------- 5 43 12.27 22.63 1.366 3.788 .719 12.741 2.418 4.503 

15 34 8.65 26.35 1.202 3.334 .632 11.803 2.240 4.075 

25 26 6.19 28.81 1.024 2.839 .539 10.712 2.033 3.596 

40 -------- 5 48 14.59 25.41 1.488 4.006 .760 13.162 2.498 4.706 

15 38 10.05 29.95 1.284 3.557 .675 12.253 2.325 4.284 

25 30 7.31 32.69 1.119 3.100 .588 11.294 2.143 3.850 

1 Exploratory wells assumed to be drilled since December 31, 1974. The stopping rule for exploratory wells drilled does not take into account the tax benefit of charging the cost of exploratory wells 

against current income. Therefore, these figures overestimate the effective cost of exploratory drilling. 2 At the margin, the sum of the marginal finding cost and the marginal production cost is equal to the output price (column 1). 
40 

1-

z 

w 35 ....J 

<( 

> 5 

0 

w 

....J 30 6 

u.. 

0 

....J 

w 

(I: 

(I: 25 

<( 

CXl 

0:: 

w 

Q.. 

(/) 20 0:: 

<( 

....J 

....J 

0 

0 

~ 15 

u) 

<( 

(.9 

Cl 

z 

<( 10 ....J 

6 

u.. 

0 

w 

~ 5 0:: 

Q.. 

oL--------------1•o--------------2~o---------------3~o--------------4~o------------~5o 

EXPLORATORY WELLS, IN THOUSANDS 

FIGURE 29.-Exploratory wells projected to be drilled in the Permian Basin as a function of price of oil an<1 gas and rau• of return on 

investment (ROI). 

CONCLUSION 

Estimates of undiscovered recoverable oil and 

gas, made using assumptions of $15 per BOE and 

15 percent rate of return, indicate that oil and gas 

discoveries after January 1, 1975, will be 2.3 billion 

BOE, or less than 7 percent of the estimated 

ultimate recovery from fields discovered before 

1975. The production of oil and gas in 1974 from 

the Permian Basin was approximately 1.4 billion 

BOE. Thus, the amount produced in 1 year is 60.3 

percent of the total estimated potential recoverable resources from future discoveries in the 

Permian Basin at a price of $15 per BOE and a 15 

percent aftertax real rate on investment. Given the 

highest price ($40 BOE) and lowest required rate 

of return (5 percent) shown in table 27, the 1944 

production equals 29.7 percent of the total poten43 

tial recoverable resources from future discoveries. 

Even in this most favorable example, the results 

indicate that estimated potential recoverable 

resources from future discoveries are l;ttle more 

than 3 years of production at the 1974 l~vels. 

ADDITIONAL SUPPLIES FR<J M 

KNOWN FIELDS 

ESTIMATES OF INDICATED AND INF:ERRED 

RESERVES 

The second part of this study shifts from undiscovered oil and gas resources to the res'lurces remaining in the fields discovered in the past. The 

most common measure of the production potential 

of known fields is proved reserves. The definition 

of proved reserves is intentionally conservative. It 
1-

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w 

....J 

~ ::::> 

d 

w 

....J 

5 

u.. 

0 

....J 

w 

a: 

a: 

<( 

co 

a: 

w 

a.. 

(/) 

a: 

<{ 

....J 

....J 

0 

0 

~ 

t-' 

(/) 

0 

u 

....J 

<( 

z 

(.9 

a: 

<{ 

~ 

15 

10 

5 

NONASSOCIATED 

GAS 

a~--------------._--------------~--------------~--------------~~------------~ 0 2 3 4 5 

OIL EQUIVALENT, IN BILLIONS OF BARRELS 

FIGURE 30.-Marginal cost of recoverable oil and gas resources from undiscovered deposits in the Permian Basin- 5 percent discounted cash-flow rate of return. 

reflects the measurements, estimates, and 

historical production data for the field and provides 

a projection that is unlikely to overstate what can 

be produced in the future at current prices and 

technology. 

The proved reserves of the Permian Basin 

reported by the industry as of December 31, 1976, 

were: 5.5 billion barrels of oil and 18.2 trillion cubic 

feet of natural gas, 6 as compared with past produc~ 

tion from the Permian Basin of 18.6 billion barrels 

of oil and 55.8 trillion cubic feet of natural gas. A 

judgment can be made concerning how much oil 

6 These figures represent the sum of proved reserves reported by the American 

Petroleum Institute and the American Gas Association for the Southeast New Mexico District and Texas Railroad Commission Districts, 7C, 8, and 8A. The four districts, although not 1dentical to the Permian Basin as defined in this report, closely 

approximate it and are considered identical for the purpose of counting reserves and 

original oil in place. 

and gas was originally in place in the parts of 

known fields that provided this past production 

and that contain the remaining proved reserves. 

These amounts are approximately 90.4 billion barrels of oil and 108.4 trillion cubic feet of natural 

gas. The combination of past proiuction and 

proved reserves indicates that 26.0 percent of the 

oil will ultimately be recovered in the Permian 

Basin. 

As additional production experience is gained 

and as more development and extension wells are 

drilled in known fields, additional quantities of oil 

and gas may be projected with sufficiert confidence 

to include these quantities in the proved category. 

Subsequent production must be subtracted from 

e~rlier proved estimates, and new information may 

cause upward or downward revisions in previous 

44 
40 

~35 

z 

w 

....J 

~ 

5 

030 

w 

....J 

0 

LL 

0 

....J 25 w 

a: 

a: 

<( 

CD 

a: 

~20 

(/) 

a: 

:3 

....J 

0 

0 15 

~ 

~' 

(/) 

0 

u 

<i! 10 

~ 

(.!) 

a: 

<( 

:E 

5 

TOTAL 

2 3 4 5 

OIL EQUIVALENT, IN BILLIONS OF BARRELS 

FIGURE 31.~Marginal cost of recoverable oil and gas resources from undiscovered deposits in the Permian Basin-15 percent discounted cash-flow rate of return. 

estimates. History indicates also that the recovery 

factor does not remain constant over time because 

new secondary projects are introduced into fields 

and economic conditions change. As a consequence, the estimate of ultimate recovery, as well 

as perceptions of the amount of oil and gas originally in place, changes gradually over time. 

INDICATED RESERVES 

The initial step in accounting for the known oil 

and gas resources of the Permian Basin is, therefore, to estimate how much oil and gas may be produced from known fields, in addition to that included in proved reserves. Included in the first of 

these additional amounts are the quantities of oil 

expected to be recovered from projects that will 

45 

improve recovery in active fields- projet~ts where 

secondary recovery operations have begun, but are 

too new to evaluate; and proposed projects, which 

must be evaluated according to experien~e gained 

in other fields. According to the American Petroleum Institute (American Gas Association and 

others, 1977, table 1) these "indicated additional 

reserves" amounted to 1. 6 billion barrels of recoverable oil as of December 31, 1976. 

INFERRED RESERVES 

The combination of proved reserves plus any indicated additional r~serves does not full;T account 

for the potential of the known fields. The discovered reserves of oil and gas also include inferred reserves, which are hydrocarboTls whose 
40 

1- 35 

z 

w 

....J 

~ 

5 

d 30 w 

....J 

6 

LL 

0 

....J 25 w 

a: 

a: 

<( 

Ill 

(/) 

a: 

:5 

....J 

0 

Q 15 

z 

r: 

(/) 

0 

u 

~ 10 

~ 

(.!) 

a: 

<( 

~ 

TOTAL 

ooL-------------L--------------L2--------------~3~------------~4~--~------~5 

OIL EQUIVALENT, IN BILLIONS OF BARRELS 

FIGURE 32.-Marginal cost of recoverable oil and gas resources from undiscovered deposits in the Permian Basin-25 percent discounted cash-flow rate of return. 

quantity cannot be precisely determined. Nevertheless, this additional oil and gas probably will be 

recovered eventually, and its recovery will notrequire the exploratory drilling needed for a new 

field discovery. 

For all fields discovered in a given year, the 

American Gas Association (AGA), the American 

Petroleum Institute (API) and the Canadian Petroleum Association (CPA) have published through 

1978 (American Gas Association and others, 1967-

79) annual estimates of ultimate recovery. 

Changes in estimates of the quantity in place plus 

the recoverable quantities (proved reserves plus 

production) provide some basis for estimating the 

degree to which reserve and recovery figures may 

46 

change over time for individual fielc ~, an entire 

basin, or the United States as a whol~. Estimates 

of ultimate recovery eventually stabilize for 

mature fields and become good proje~tions of the 

actual recoverable quantity, if we asEume that no 

changes in price or technology take place. 

GENERAL OUTLINE OF DATA AND METHODS 

Proved reserves of crude oil and natural gas are 

defined by the API and AGA. These d~finitions include only the part of the oil and gas r~~source base 

that is known to be technically and economically 

producible. Because the estimate of proved 

reserves in a field depends on the degree of 
development and production in each field, the estimates are updated each year. On the average, estimates of ultimate recovery (past production plus 

proved reserves) increase with time; the changes in 

estimates are due to extensions, revisions, and new 

reservoir discoveries in old fields (referred to as 

"new pools" in subsequent discussion). Extensions 

and new pools are proved reserve additions warranted by increases in the perceived physical dimensions of the field as a result of additional drilling. Revisions are all other changes (either positive 

or negative). Generally, estimates of a field's 

ultimate production grow more rapidly in the first 

few years after discovery; most fields are welldefined after 6 years of development and production. 

Data on ultimate recovery can be used to estimate how much oil will actually be produced from 

fields that are not yet fully developed, if we assume 

that the estimates of their ultimate recovery grow 

in the same way that such estimates grew in the 

past. Briefly, an estimate of ultimate recovery for 

each year of age is made as the fields pass through 

that year of age. For example, the amount of 

growth as the fields advance from their fifteenth to 

their sixteenth year would be indicated by the 

changes in estimates for December 31, 1966, and 

December 31, 1967, for fields discovered in 1951. 

The percentage changes between successive 

estimates for all years for which data are available 

can then be calculated. The mean percentage 

change is the average growth that can be expected 

as fields age from their fifteenth to their sixteenth 

year. 

Such expected growth was calculated for each 

year. The estimated ultimate recovery for fields 

discovered in a given year was multiplied by the 

growth factors for each year beyond the age of the 

fields. The same method of analysis was also applied to original oil in place and to recoverable 

natural gas for the Permian Basin. Results are 

presented in tables 28 and 29. 

METHOD OF ANAL YSlS 

Let Qe(u, v) be the estimate of ultimate recovery 

made at the end of year v for all fields discovered 

during the year u. Let Q(u) be the actual, but unknown, amount of oil discovered in year u. We 

assume that: 

Qe(u, v)=Q(u)f(v-u)+Q(u)E(u, v) (1) 

where f(v-u) is a fraction which increases to 1.0 

as the age of the fields, v- u, increases to infinity. 

TABLE 28.-Growth 'in estimates of original oil "in placefor the 

Permian Basin 

[In this table, Permian Basin comprises Southeastern New Mexico and Texas 

Railroad Commission Districts 7C, 8, and SA] 

Di~~::ry Estimate Age of estimate 1/ftt) Corrected 

12/31/76 in yrs e~t.imate 

(billion bbl.) (t) (billion bbl.) 

1975 ------ 0.0472 0.5 5.84 0.2755 

1974 .0416 1.5 2.89 .1201 

1973 ------ .1610 2.5 1.95 .3142 

1972 .0997 3.5 1.76 .1753 

1971 .0857 4.5 1.58 .1353 

1970 .2359 5.5 1.42 .3347 

1969 .2511 6.5 1.36 .3409 

1968 .1041 7.5 1.32 .1372 

1967 ------ .1893 8.5 1.29 .2446 

1966 .6271 9.5 1.27 .7939 

1965 ------ .5114 10.5 1.25 .6387 

1964 .4189 11.5 1.22 .5109 

1963 .2555 12.5 1.23 .3136 

1962 .7279 13.5 1.23 .8932 

1961 .3888 14.5 1.22 .4735 

1960 .7398 15.5 1.21 .8936 

1959 ------ .6283 16.5 1.21 .7595 

1958 .4246 17.5 1.20 .5105 

1957 1.6167 18.5 1.15 1.8528 

1956 ------ 1.5509 19.5 1.14 1.7676 

1955 1.0706 20.5 1.14 1.2171 

1954 ------ 2.7785 21.5 1.12 3.1193 

1953 2.8443 22.5 1.11 3.1439 

1952 1.0497 23.5 1.10 1.1542 

1951 1.2816 24.5 1.07 1.3707 

1950 2.4700 25.5 1.04 2.5806 

1949 ------ 12.4150 26.5 1.01 12.5650 

1948 4.0569 27.5 1.04 4.2146 

1947 2.0158 28.5 1.03 2.0856 

1946 .8728 29.5 1.03 .8975 

1945 ------ 3.5591 30.5 1,05 :3.7296 

1944 2.4933 31.5 1.02 2.5443 

1943 1.4396 32.5 L02 1.4716 

1942 .8482 33.5 1.04 .8818 

1941 2.2130 34.5 1.02 2.2491 

1940 1.9322 35.5 L02 1.9704 

1939 1.4757 36.5 L01 1.4868 

1938 .8560 37.5 L02 .8733 

1937 ------ .7615 38.5 L02 .7766 

1936 6.8011 39.5 1.02 1).9313 

1935 2.2127 40.5 L02 2.2520 

1934 2.6043 4L5 L01 :l.6344 

1933 .2241 42.5 1.01 .2266 

1932 .5565 43.5 1,02 .5695 

1931 ------ .0082 44.5 L03 .0084 

1930 3.3113 45.5 1.01 :1.3519 

1929 ------ 5.1144 46.5 L01 ii.1639 

1928 1.4529 47.5 1.00 1.4575 

1927 .6538 48.5 1.00 .6558 

1926 8.5027 49.5 1.00 8.5027 

1925 2.0742 50.5 1.00 ::.0742 

1924 .1249 5L5 1.00 .1249 

1923 .5842 52.5 1.00 .5842 

1922 0 53.5 1.00 0 

1921 .1658 54.5 1.00 .1658 

1920 ------ 0 55.5 0 

Pre-1920 (I 0 

Total 89.9300 94.5200 

The error term, Q(u)E(u,v), is assumed to be proportional to Q(u). Taking logarithms gives: 

lnQe(u, v)= lnQ(u) + ln(f(v- u)+E(u, v)). 

We now fix u and regard both sides as functions 

of v only and ignore the error term, E(u,v). 

Taking the difference betwen successive estimates of the amount of oil or gas discovered in a 

year u gives equation (2): 

lnQe(U,V+ 1)-lnQe(u, v)=ln.f{v+ 1-u)-ln./{v·-u) (2). 

47 
TABLE 29.- Gro·wth in est·imates of recoverable natu.ral gas for 

the Perm·ian Basin 

[In this table, Permian Basin comprises Southeastern New Mexico and Texas 

Railroad Commission Districts 7C, 8, and SA] 

Di~J>i'rery Estimate Age of estimate Corrected 

12/31/76 in yrs 1/j{t) estimate 

(trillion cubic (t) (trillion cubic 

feet) feet) 

1976 0.0965 0.5 4.748 0.4582 

1975 .2377 1.5 2.311 .5493 

1974 .3787 2.5 1.673 .6336 

1973 .9057 3.5 1.499 1.3578 

1972 .4966 4.5 1.462 .7260 

1971 .5044 5.5 1.360 .6860 

1970 .6070 6.5 1.326 .8051 

1969 1.587 7.5 1.326 2.105 

1968 1.962 8.5 1.250 2.452 

1967 0.9316 9.5 1.201 1.119 

1966 1.347 10.5 1.195 1.6091 

1965 1.004 11.5 1.176 1.181 

1964 .7197 12.5 1.177 .8470 

1963 5.951 13.5 1.186 7.060 

1962 2.653 14.5 1.189 3.154 

1961 1.301 15.5 1.238 1.611 

1960 .8093 16.5 1.176 .9514 

1959 .2894 17.5 1.1027 .3191 

1958 .8278 18.5 1.134 .9386 

1957 1.466 19.5 1.085 1.590 

1956 1.371 20.5 1.063 1.458 

1955 .6345 21.5 1.018 .6460 

1954 2.596 22.5 1.012 2.628 

1953 1.574 23.5 1.014 1.596 

1952 2.815 24.5 1 2.815 

1951 .4043 25.5 1 .4043 

1950 2.77 26.5 1 2.777 

1949 2.452 27.5 1 2.452 

1948 .8001 28.5 1 .8001 

1947 .8041 29.5 1 .8041 

1946 .7491 30.5 1 .7491 

1945 3.048 31.5 1 3.048 

1944 2.016 32.5 1 2.016 

1943 .4739 33.5 1 .4738 

1942 .3197 34.5 1 .3197 

1941 1.241 35.5 1 1.241 

1940 .2037 36.5 1 .2037 

1939 1.432 37.5 1 1.432 

1938 .3360 38.5 1 .3360 

1937 .1426 39.5 1 .1426 

1936 3.295 40.5 1 3.295 

1935 1.435 41.5 1 1.435 

1934 2.257 42.5 1 2.257 

1933 .0497 43.5 1 .0497 

1932 .1268 44.5 1 .1268 

1931 .0 45.5 1 .0 

1930 2.692 46.5 1 2.692 

1929 10.55 47.5 1 10.55 

1928 1.075 48.5 1 1.075 

1927 .1751 49.5 1 .1751 

1926 1.284 50.5 1.284 

1925 .2503 51.5 .2503 

1924 .2806 52.5 .2806 

1923 .1989 53.5 . 1989 

1922 .0 54.5 .0 

1921 .0026 55.5 .0026 

1920 .0 56.5 .0 

Pre-1920 .0 a:57.5 

Total 73.937 81.167 

The left-hand side of equation (2) may be computed from the data. For a given time lag s, suppose we have the data lnQe(u,u+s)-lnQe(u,u+s-1) 

for n different values of u, then define: 

h(s)= .E (lnQe(u, u+s)-lnQe(u, u+s-1)*a(u, s) u 

where the weighting factors a(u,s) are chosen so 

that for a fixed s, _Ea(u,s)= 1 and a(u,s) is proporu 

tional to Qe(u,u+s). The reason for using weighting 

factors, rather than a simple average, is to reduce 

the effect of changes in estimates for years in 

which very little oil was discovered. Then define: 

s 

H(s)= .Eh(i). The two functions H(s) and lnf(s) 

i=l 

differ by an unknown constant, that is independent 

of s: 

ln.f{s)=H(s)+C. 

The constant C can be estimated from the fact 

that ln.f{s) increases as s increases and it approaches zero as s approaches infinity. By examining the graph of H(s), one can esti1nate when H(s) 

will be close to its asymptotic valua.. This value is 

the negative of the estimate of C. Another way of 

estimating C is to choose, by any method, an age of 

fields beyond which growth is negligible. If this age 

is "a" then take C to be -H(a) and set.f{s)=1 for 

s ~a. This method is particularly useful if the 

discovery dates of older oil fields are being changed 

so that substantial quantities of crude oil are being 

shifted from one discovery year to another. 

The analysis was applied to estimates of 

recoverable natural gas and original oil in place. 

Statistical irregularities made choo~ing the asymptotic values for H(s) difficult, especially for natural 

gas. 

The discovery year assigned to a particular field 

often changes. When the data for a small region 

such as the Permian Basin are an~.lyzed, shifting 

the discovery year of a field can introduce large 

variations in the ultimate production of all the 

fields discovered in a given year; such variations 

have nothing to do with additions to reserves 

through extensions and revisions. This problem 

was resolved by grouping the fields according to 

the decade of discovery to determjne to within 10 

years the age at which the growtr of the fields is 

virtually over . 

In the Permian Basin, the 1973 estimate of 

ultimate gas production from fields discovered between January 1, 1950, and January 1, 1960, was 

51.1 trillion cubic feet. The 1976 estimate for the 

same fields was 51.3 trillion cubic feet. This stability indicated that estimated sizes of Permian Basin 

gas fields discovered between January 1, 1950, and 

January 1, 1960, were not likely to grow 

significantly beyond the Decem'ler 31, 1976, 

estimates. 

The projection of historical growth rates into the 

future will probably led to an overestimate of the 

amount of growth that can be expected from 

known fields, because fields are now developed 

more rapidly than they were in tr~ past and are 

smaller on the average. 

48 
A VARIATION ON THE METHOD OF ANALYSIS 

The delay between the discovery of a field and 

the estimate of its size can be measured by an index of industrial activity, rather than time. The 

mathematics of the analysis is the same when some 

other index is used. 

Pelto (1973) considered the problem of growth in 

estimates of field size, specifically estimates of 

original oil in place in the conterminous 48 states. 

His method differed from that described above, in 

four respects. First, instead of using a geometric 

mean of ratios of successive estimates, he used an 

arithmetic mean. Second, he omitted certain 

discovery years (pre-1920, 1921, 1923, 1924, 1934, 

and 1935) from his calculations because irregularities in the data for those years were probably caused by changes in the discovery years 

assigned to some fields. Third, he omitted the first 

three estimates (1966, 1967, and 1968) because 

they were subject to significant startup errors. 

Last, he used a smoothing function. Later, Pelto 

applied his method to recoverable natural gas. The 

discovery years omitted from the natural-gas 

calculations were 1941, 1957, 1959, and 1965. 

When Pelto's method and the method described 

above were applied to the entire conterminous 48 

States, the two methods produced similar results, 

and results given here for the Permian Basin are 

also similar. 

SUMMARY 

The estimate of original oil in place in the Permian Basin decreased during the period from 

December 31, 1974, to December 31, 1975, by 

0.285 percent. Application of the growth factors 

indicates that the December 31, 1975, estimate can 

be expected ultimately to increase by 5.1 percent 

for a predicted combined increase of 4.8 percent 

over the December 31, 1974, estimate. This would 

mean an increase of 4.4 billion barrels of oil, of 

which, at a 26 percent recovery factor, 1.1 billion 

barrels would be recoverable. 

The estimate of recoverable natural gas increased by 0.899 percent during the period from 

December 31, 1974, to December 31, 1976. The 

growth factors indicate that the December 31, 

1976, estimate can be expected ultimately to increase by 8. 9 percent. Thus, the overall increase in 

recoverable natural gas from the December 31, 

1974, estimate is 9.8 percent. This percentage of 

growth applied to the Permian Basin's December 

31, 1974, estimate of recoverable natural gas, 71.7 

49 

trillion cubic feet, means that an additional 7.1 Tcf 

would be produced from known fields. 

The inferred reserves of the Permian Basin, 

therefore, are calculated to be 1.1 billion barrels of 

crude oil and 7.1 Tcf of natural gas. However, projection of the growth of fields under the a~sumption that fields discovered in the 1960's and 1970's 

will show the same growth as fields discovered in 

the 1950's and before, will almost surely lea-l to an 

overestimate, because the more recently 

discovered fields are smaller. 

ENHANCED OIL AND GAS RECOVJ:RY 

The previous section accounts for the oil r.nd gas 

yet to be produced from known fields in tl'~ Permian Basin through normal drilling, develo~ment, 

and the addition of secondary-recovery pr')jects. 

However, advanced production techniques may be 

used to recover additional oil and gas from known 

fields, although such oil and gas is gener21ly not 

now included in the various reserve estimates (see 

fig. 33). These techniques go beyond injecting 

water or gas as a routine part of pressure 

maintenance, and most are either experimental or 

only marginally economic. The possibilif~s for 

such enhanced recovery in the Permian Ba"'in are 

discussed here. 

ENHANCED OIL RECOVERY 

Enhanced oil recovery (EOR) already makes a 

significant contribution in the Permian Basin. As 

shown below, about 0.3 billion barrels of oil has 

been produced or proven to date by EOR, t'le bulk 

of this results from the application of hydro~arbon 

gas miscible flooding in addition to the major carbon dioxide flood at the Kelly-Snyder field 

(SACROC unit). 

Number of Cumulative 

reservoirs EORI Proved Indicated 

having production reserves reserves substantial ----'-------------

EOR1 (as of December 31, 1977) 

production (million barrels) 

Hydrocarbon gas 

miscible ---------- 5 187.1 24.6 0.0 

C02 flooding ________ 2 75.6 14.0 9.5 

Other-------------- 1 .1 .0 .0 

Total --------- 8 262.8 38.6 9.5 

1 Enhanced oil recovery. 

In the Permian Basin, the further use C'f EOR 

techniques could conceivably increase ultimate 

recovery by an additional 10 billion barrels. This 

would raise ultimate recovery from roughly 26 percent to about 37 percent of the original oil in 
PRODUCED 

RESERVES 1:/ 

.AVAILABLE 1:/ FOR TERTIARY 

RECOVERY 

BILLION 

BARRELS 

20.5 

6.7 

56.0 

83.2 

PERCEriT ORIGINAL 

OIL IN PLACE 

25 

8 

67 

100 

TOTAL OIL IN PLACE 

FIGURE 33.-Production, reserves, and residual oil in place in the Permian Basin, exclusive of "Spraberry" Trend, December 31, 

1977. 

place. 7 However, recovering such additional 

amounts of oil will probably be limited by economic 

and major technological problems. 

METHODOLOGY 

The EOR potential of the Permian Basin is based 

upon projections for major reservoirs for which the 

use of EOR techniques appears feasible. For those 

fields that already have EOR projects, expansion 

of the projects was assumed where economic. We 

extrapolated the results to the level of the entire 

basin using the oil-in-place data by depth and 

lithology. The EOR supply possibilities were determined for two rates of return on investment and 

seven price ltvels. 

The EOR model used in this study was originally 

prepared by Lewin and Associates, Inc. (1976), and 

the Federal Energy Administration. Currently, 

the model has been updated and documented 

7 These figures exclude the "Spraberry" Trend, a very large formation of shale and 

silts~one that is economically producible only because of a system of naturally occurn~g, closely spaced vertical fractures, which permit an ultimate recovery currently estimated at no more than 7 percent of the original oil in place. 

50 

(Lewin and Associates, Inc., 1978) and is operated 

by the Energy Information Administration of the 

Department of Energy. The model is reservoirspecific and performs individual project evaluations on a sample of large candidate reservoirs 

from the Permian Basin. This sampl~ is believed to 

cover more than 50 percent of the o~l in place in the 

basin and a much higher percenU'.ge of the best 

EOR prospects. The model uses ec':lnomic criteria 

to evaluate the possible use of EOR methods in 

these reservoirs. Each recovery 1nethod has its 

own engineering efficiencies, costs, and other data 

specified. The evaluation involve;;- a three-step 

process: 

(1) Screening reservoirs according to geologic 

and economic factors, and assigning EOR 

techniques to the most attractive prospects.8 

(2) Identifying minimum acceptable prices and 

reservior-specific production profiles over a 

8 This screening process permits a choice, based u"lon fluid and reservoir 

characteristics, among steam drive, in situ combustion, ga:' miscible flooding, surfactant/polymer injection, and polymer-augmented waterflooding. 
period of time, on the basis of projected 

market prices and rates of return. 

(3) Extrapolating production data to regional 

levels and accumulating reserves. 

The study was conducted separately for sandstone and carbonate reservoirs, which then were 

classified by reservoir depth. Ninety-six reservoirs 

were included in the sample studied. The distribution of the reservoirs within these categories is 

given in table 30. The sample was extrapolated to 

obtain estimated values for the entire basin for 

both sandstone and carbonate formations and for 

various reservoir depths. The extrapolation factors 

used and the results obtained are shown below: 

Reservoir type <5 000 ft 5•

000- 10•

000 > 10 000 ft ' ft ' 

Sandstone: 

Sample OOIP 1 , billion bbls -----------

Total OOIP, billion bbls --------------

Extrapolation factor ---------------- Carbonate: 

Sample OOIP, billion bbls ------------

Total OOIP, billion bbls --------------

Extrapolation factor ----------------

1 Original ore in place. 

1.65 

10.81 

.153 

25.17 

32.50 

.774 

0.22 

4.94 .0.40 

.045 

15.64 2.94 

26.87 7.68 

.582 .383 

TABLE 30. -Classification of sample reservoirs selected for 

enhanced oil recovery in the Permian Basin 

Technically feasible for EOR a 

Sandstone ------------- Carbonate Infeasible for EOR~---------

<5,000 

No. OOIP 1 

(109B) 2 

2 1.65 

34 19.88 

5,000-10,000 ft > 10,000 ft 

No. OOIP No. OOIP 

(109B) (109B) 

2 0.22 

29 14.31 2.44 

5.29 1.33 10 .50 

41 26.8 36 15.9 19 2.9 

Sandstone -------------

Carbonate ------------- Total ________________ · _ __:____:::.:..=.::.. _ ___::..__--=.:.::.::___.::.::...__.::::..::__ 

1 Original oil in place. 2 B, barrel. 3 Enhanced oil recovery. 

The technology assumed was the best of the currently tested and applied carbon dioxide processes. 

More specifically, the model includes assumptions 

that: 

(1) Oil saturation is uniformly distributed within 

the part of the reservoir being developed at 

the time the project is initiated (this 

assumption may lead to an underestimate 

of drilling costs and, hence, an 

overestimate of recovery). 

(2) The effective sweep efficiency for the carbon 

dioxide varies according to the performance of the waterflood previously used 

and the reservoir lithology (that is, carbonate or sandstone); the carbon dioxide 

sweep efficiency used by the model is a 

function of ultimate primary/secondary 

sweep, as follows: 

00 sweep efficiency 

[Percent of waterflood sweep] 

Reservoir 

suitability 1 

Good ---------------------

Fair----------------------

Poor ---------------------

Sandstone 

reservoirs 

50 

40 

30 

1 As determined by the National Petroleum Council (1976). 

Carbonate 

reservoirs 

45 

40 

35 

(3) Residuql oil saturation in the swept zone 

after carbon dioxide flooding is 60 percent 

of the residual after waterflooding. 

( 4) Residual oil saturation in the unswept zone 

remains unchanged. 

(5) World oil prices remain at the mid-1977 level 

in constant dollar terms. 

Potential EOR production ranges from zero production at $10 per barrel to 5.1 billion and 4.6 

billion barrels at $40 per barrel for rates of return 

at 15 percent and 25 percent, respectively, as 

shown in table 31. 

TABLE 31.-Enhanced oil recovery potential of the Permian 

Basin 

[In billions of barrels; BOE, barrels of oil equivalent] 

Output price 15 percent 25 percent 

($/BOE) rate of return rate of return 

10 ---------------- 0.0 0.0 

15 ---------------- 1.34 .20 

20 ---------------- 2.93 1.30 

25 ---------------- 4.31 2.58 

30 ---------------- 4.70 3.65 

35 ---------------- 5.08 4.11 

40 ---------------- 5.11 4.56 

ENHANCED GAS RECOVERY 

Conventional gas production ordinarily recovers· 

a large fraction of the original gas in place, 70 percent or more in the Permian Basin; the remaining 

gas is generally not an attractive target for 

enhanced gas recovery (EGR) techniques. 

The usual targets for EGR, instead, are· 

discovered gas accumulations that have never been 

produced because conventional production 

methods are uneconomic. The gas in these fields is 

classified as a discovered subeconomic resource 

and is frequently designated "near-conventional" 

or "unconventional" gas, to indicate the 

subeconomic responsP to conventional production 

methods. 

51 

Within the Permian Basin, interest in EGR 

centers on the southern part, Sutton, Crockett, 
____________ ___j__ 

31 

PECOS 

r---

' ,-~ 

"'' I "'-l I '"-,"- ~-.J TERRELL 

EXPLANATION 3~~ , 

l\t~\\jilijj!j:jjjjjjjjjjijj!j North a rea 

~~~~South area 

20 

I I 

20 I 

UNITED I STATES 

MEXIco 

40 MILES 

I 

40 KILOMETERS 

KIMBLE 

-l1 

VAL VERDE 

_ _l__ I ---1 I 

! EDWARDS 1 L-_____ Lt_ __ _ 

REAL 

I 

FIGURE 34.-Areas of the Permian Basin for enhanced gas recovery. 

and Schleicher Counties in Texas (see fig. 34). TABLE 32.-Enhanced gas recovery potential of the Permian 

About 4,500 square miles of this subbasin may be Basin 

responsive to massive hydraulic fracturing (MHF) [In trillion cubic feet; BOE. barrels of oil equivalent] 

at some future time under the economic conditions 

assumed in this study. 

MHF now has advanced sufficiently to become 

standard production practice in many fields of low 

permeability. However, the economic and 

subeconomic resources of the area are difficult to 

identify separately. This report, therefore, 

assumes that all such resources are presently 

subeconomic and that exploiting this area will require future technological advances. 

EGR using MHF was analyzed at two rates of 

return and at a wide range of price levels (see table 

32). The methodology was similar to that for EOR. 

The response ranges from 7.4 trillion cubic feet at 

$10 per BOE and 25 percent rate of return to 13.7 

trillion cubic feet at $40 per BOE and either 15 or 

25 percent rate of return. 

52 

Output price 15 percent 25 percent 

($/BOE) rate of return rate of return 

5 ---------------- 8.9 7.4 

10 ---------------- 13.7 13.7 

15 ---------------- 13.7 13.7 

20 ---------------- 13.7 13.7 

25 ---------------- 13.7 13.7 

30 ---------------- 13.7 13.7 

35 ---------------- 13.7 13.7 

40 ---------------- 13.7 13.7 

EXPANDED PRODUCTION FROM KNOWN 

FIELDS: AN APPRAISAL OF RESULTS 

Although the undiscovered oil and gas resources 

of the Permian Basin have been discussed in "The 

Integrating Economic Model," the second part oJ! 

this study, which addresses future supply from 
known fields and analyzes separate problems, required different approaches. The statistical outputs 

given in "Estimates of Indicated and Inferred 

Reserves" and "Enhanced Oil and Gas Recovery" 

are less uniform in character than those in "Future 

Production of Undiscovered Oil and Gas from the 

Permian Basin," and, consequently, are difficult to 

aggregate. Therefore, a formal integrating model 

to show the potential for future recovery of oil and 

gas from known reservoirs has not been attempted. 

Using one set of assumptions (such as $15 per 

BOE and 15 percent rate of return), we can itemize 

(see following table) the current outlook in the Permian Basin for recovering additional oil and gas 

from discovered fields. In a general way, this table 

provides a concept of the relative magnitude of 

future supply. 

Reserves as of Oil Natural gas 

December 31, 1976 (billion barrels) (trillion cubic feet) 

Proved -------------- 5.5 18.2 

Indicated additional ____ 1.6 

Inferred ------------- 1.1 7.1 

From enhanced-recovery 

techniques ---------- 1.3 13.7 

From unconventional 

sources ------------ none none 

The estimation of proved, indicated, and inferred 

reserves in the Permian Basin involves no formal 

economic analysis; reserves are quantities considered economic under the price and technological 

conditions specified at the time of estimation. As a 

result, the indicated and inferred reserves data 

found in "Estimates of Indicated and Inferred 

Reserves" are not shown in terms of price ranges 

or rate-of-return alternatives. Although the question of economics is avoided by definition as an explicit variable in the reserve estimation at one 

specific time, the passage of time will require that 

these prior estimates be changed to reflect the subtraction of production, subsequent changes in 

price and technological conditions, and changes in 

classification as indicated, and inferred reserves 

are moved into the proved reserves category. 

Realistically, if upward price trends persist, a 

continuing transfer of current subeconomic Permian Basin oil and gas volumes into the reserves 

category will take place. In the Permian Basin, this 

transfer may prove to be a more important quantitative adjustment in the longer term than is the 

refinement of past reserves estimates. The estimation of subeconomic resources in known oil and gas 

fields involves the simultaneous consideration of 

technological and economic change, which can 

alter both the producibility and the ultimate 

recovery over time, under various price and rate of 

return expectations. This step in the ap'1raisal 

process is limited by a lack of knowledge about the 

quantity of oil and gas remaining in place. In addition, the appraisal problem is complicated b~cause 

the hydrocarbon mix includes varying prop0rtions 

of crude oil, nonassociated gas, associated and 

dissolved gas, and natural-gas liquids. 

In examining the marginal cost functionE of undiscovered oil and gas in "Future Production of 

Undiscovered Oil and Gas from the Permian 

Basin," we recognized that the economic model attempts to simulate the industry's explorationdecision process. Any discovery model, however, 

has difficulty in adjusting to geologic prolv~bility 

data as well as in properly capturing tre true 

nature of the corporate decision process. Once a 

discovery. has been made, development is most 

likely to be based upon engineering estimates and 

calculations. Unlike the exploration process, an oil 

and gas production model can be considered an 

assessment of development costs and risks versus 

the potential rewards to be gained. It involves 

reasonable estimates of the specific quantity of 

money needed as an initial investment, p:-:-ovides 

for certain operating costs, and forecasts an expected income from production within a re}atively 

narrow range of future circumstances. This is sufficient for the private decisionmaker as a basis for 

making his choices among alternative investments, 

when conventional reservoirs and technology are 

involved. The risk reflects the uncertainty of price 

and the accuracy of the development desig'l. 

NOTES ON METHODOLOGY 

This study of the Permian Basin was undertaken 

as an experimental effort to: (1) devise 

methodologies generally applicable for est:~~ating 

future oil and gas possibilities in a geologic basin; 

(2) test these methodologies in a mature basin for 

which available data are abundant and of good 

quality; and (3) extend the methodology of earlier 

resource appraisals by introducing economic considerations. In general, the methodologies used to 

inventory the remaining recoverable oil and 

natural gas resources of a single basin appear 

sound and should provide useful information and 

an opportunity for further refinement. 

Some concern must be expressed about the extremely high level of effort that has been invested 

in studying a single basin. However, a l~arning 

process has been involved, and future efforts 

should show the benefits of streamlining, b~cause 

53 
the early stages of the project need not be 

repeated. Thus, the time and expense of studying 

the two additional proposed regions should be 

reduced. 

The Permian Basin was selected as the first 

study because it is a mature producing basin. The 

second study concerns the Gulf of Mexico offshore 

and will have to deal with new economic and 

technological considerations as it applies its 

methodology to marine operations. The final pilot 

study will be the Baltimore Canyon basin of the 

Atlantic Ocean, which is largely a frontier area. 

Little exploration and drilling has taken place, and 

little "hard" information is available. Consequently, this last pilot project will involve a severe test of 

the methodology. 

In future work, several aspects of the approach 

must be refined. One question will concern the 

distribution of resources by depth category, the 

fineness of depth classifications being an important 

consideration. Further examination of the rationale behind a reservoir-size cutoff should also be 

made. 

Because estimates of reserve-cost functions 

must begin with an appraisal of the undiscovered 

oil and gas resources in place, the subjective 

resource-appraisal techniques developed and applied in "Future Production of Undiscovered Oil 

and Gas from the Permian Basin" must be related 

to discovery, perhaps by using mature regions as 

analogs. 

The engineering model used to project production profiles for future oil and gas discoveries in a 

basin should be examined carefully to determine 

how uncertainty can be estimated. Also, in using 

engineering or process calculations, the model may 

lose considerable economic sensitivity. The cost 

analysis also fails to reflect uncertainty. 

In examining the future potential of the known 

reserves and resources of a basin, this report 

reveals the difficulty of using a purely statistical 

approach to estimating inferred reserves. Such 

estimation seems more suitable at a national level 

than at that of a single basin level. 

Projection of the possible recovery rates by 

means of advanced technology is a relatively 

54 

recent endeavor and needs addithnal work. We 

found two special problems in analyzing the Permian Basin. First, some of the oil and gas included 

in the enhanced-recovery analysis perhaps should 

have been a part of the proved or indicatedreserves estimates. Conversely, tr~ growth of oil 

and gas-reserves estimates in part reflects past 

changes in technology, so 'that sone of the quantities counted as inferred :reserves may have been 

double-counted as the products of enhancedrecovery techniques. 

Second, the analysis of oil and g~as supply from 

undiscovered resources considered only primary 

and secondary forms of recover:r; that is, the 

enhanced-recovery analysis dealt O't}ly with known 

fields. As a result, the supply esti11ates probably 

understate potential recovery under various price 

and rate-of-return assumptions for undiscovered 

recoverable oil. To be sure, there if some justification for this approach with respect to the Permian 

Basin. In the Permian Basin, th~ undiscovered 

resources are in small fields, whereas the major 

potential for EOR and EGR is found in the larger, 

known fields. Therefore, applying enhancedrecovery calculations only to known areas probably 

does not create major errors. Nevertheless, in a 

less well-developed basin, such calculations should 

be applied to both known and unknown areas. This 

is very difficult because the EOR and EGR models 

depend on microgeologic informati0n. 

Finally, a complete basin analysis would include 

two aspects not included in this study. The absence 

of any important unconventional resources 

eliminated the need to devise a methodology for 

examining the quantities, technologies, and costs 

of such resources. Also, an integrating model to 

combine the various estimates of diFcovered oil and 

gas resources, comparable with that used for the 

undiscovered resources, was not CO't}structed. This 

model is an objective for future work. 

Despite the problems and limits mentioned, the 

study group believes that the methcdology leads to 

an improved understanding of the physical potential and economic characteristics of Permian Basin 

oil and gas resources. 
INTERAGENCY AGREEMENT FOR AN OIL AND GAS SUPPLY PROJECT 

1. Participating Agencies 

This Interagency Agreement is made and 

entered into this 13th day of December, 1976, between the following participating agencies of the 

United States Government: Department of the Interior (DOl), represented by the Office of Minerals 

Policy and Research Analysis (OMPRA), 

Geological Survey (GS), and Bureau of Mines (BM); 

Federal Energy Administration (FEA); Federal 

Power Commission (FPC); and Energy Research 

and Development Administration (ERDA). 

2. Purpose 

The purpose of this Interagency Agreement 

(the Agreement) is to delineate certain understandings between the participating agencies set 

forth in Paragraph 1 above, with respect to the execution, performance, and financing of the subject 

Project. 

3. Lead Agency 

The participating agencies, OMPRA, BM, FEA, 

FPC, and ERDA, hereby agree that GS will be the 

lead agency in achieving the purpose of the Agreement set forth in Paragraph 2 above. 

4. Steering Committee 

The Participating agencies shall plan and guide 

the Project through a Steering Committee, which 

shall be composed of the following members, their 

representatives, designated alternates, or successors: 

Richard F. Meyer, GS, Project Coordinator 

Robert L. Adams, OMPRA 

Robert R. Aitken, FEA 

Allen L. Clark, Jr., GS 

Jerry D. Ham, ERDA 

Gary W. Horton, GS 

Richard F. Mast, GS 

Ira Mayfield, FEA 

L.P. White, OMPRA 

Richard F. Zaffarano, BOM 

Gordon K. Zareski, FPC 

The Steering Committee, which may include Advisors and Conferees from outside the U.S. 

Government, shall make technical decisions with 

respect to the Project, assist in planning the work 

of the Project and in naming personnel to perform 

the Tasks named in Paragraph 5, and review the 

final report. 

5. Task Groups 

The work of the Project shall be divided into 

seven Tasks, each with a Leader and personnel 

designated by the Steering Committee: 

Task 1. Conventional Oil and Gas Resource 

55 

Appraisal and Field Size Distribution 

Task 2. The Exploration/Production Function 

Task 3. Future Conventional Oil and Gas 

Supply from Extension Drilling 

Task 4. Future Oil and Gas Supply from Improved Recovery 

Task 5. Future Oil and Gas Sup:-:-ly from 

N onconventional Sources 

Task 6. Econometrics and Supply 

Task 7. Annual Report 

6. Purpose of Project 

The purpose of the Interagency Oil and Gas 

Supply Project (Project) is (1) the preparation of 

curves showing supply of undiscovered recoverable 

oil and gas resources from all sources at various 

cost levels, and (2) the determination of possible 

changes, if any, in the levels of E:stimated 

recoverable oil and gas resources at varying 

price/cost ratios. 

To accomplish this will require examination of 

potentially recoverable hydrocarbon r~sources 

from such sources as oil shale, black organic shale, 

coal seams, heavy-oil reservoirs, tar sands, tight 

gas sands, geopressured reservoirs, abanioned oil 

fields, strippable oil fields, and water ~pths of 

more than 200 m; from enhanced oil-recovery 

methods in both known and undiscover~~d fields; 

and from extension drilling. Models must be 

prepared to include exhaustion, risk analysis, and 

field-size distribution with respect to future exploration. 

7. Duration of Agreement 

This Agreement is to cover work to be performed through September 30, 1977. Witl' the concurrence of the signatory agencies, it will be extended as required to complete the Proje~t. 

8. Financial Provisions 

Each Agency is responsible for funding its own 

personnel, with respect to salary and travel. GS 

will assume responsibility for grants, c-:mtracts, 

and similar funding arrangements, except as may 

be agreed upon in the future among one O':' more of 

the Participating Agencies. 

9. Reports 

The GS shall be responsible for publication and 

distribution of Annual Report(s) and completion of 

study preparation and publication of results. 

10. Revisions and Amendments 

From time to time GS, BM, OMPRA, FEA, 

FPC and ERDA mutually may consider it desirable 
to supplement, revise, or amend this Agreement in 

certain respects. 

11. Approval and Accepted 

GEOLOGICAL SURVEY 

By: V. E. McKelvey 

Title: Director 

Date: December 10, 1976 

OFFICE OF MINERALS POLICY AND 

RESEARCH ANALYSIS 

By: H. Enzer 

Title: Chief 

Date: (Undated) 

BUREAU OF MINES 

By: H. Falkie 

Title: Director 

Date: January 19, 1977 

U.S. ENERGY RESEARCH AND 

DEVELOPMENT ADMINISTRATION 

By: Hugh D. Guthrie 

Title: Director 

Date: February 11, 1977 

FEDERAL POWER COMMISSION 

By: William Yost 

Title: Chief, Bureau of Natural Gas 

Date: February 3, 1977 

FEDERAL ENERGY ADMINISTRATION 

By: J. Lisle Reed 

Title: Director, Office of Oil and Gas 

Date: January 28, 1977 

PARTICIPANTS IN THE PROJECT 

Robert L. Adams (Leader, Task 6) 

U.S. Department of the Interior 

Robert R. Aitken 

U.S. Department of Energy 

R. W. Allen 

U.S. Geological Survey 

Emil D. Attanasi (Co-Leader, Task 6) 

U.S. Geological Survey 

Eytan Barouch (Conferee) 

Clarkson College 

Ross E. Burke 

Energy Information Administration, DOE 

(separated) 

Allen L. Clark 

U.S. Geological Survey 

A. B. Coury 

U.S. Geological Survey 

56 

Robert Crockett 

Energy Information Adminiftration, DOE 

W. D. Dietzman 

Energy Information Adminiftration, DOE 

Wallace De Witt, Jr. 

U.S. Geological Survey 

Gordon L. Dolton 

U.S. Geological Survey 

Lawrence J. Drew (Leader, Task 2) 

U.S. Geological Survey 

Charles G. Everett 

Energy Information Adminiftration, DOE 

S. E. Frezon 

U.S. Geological Survey 

Thomas M. Garland 

Energy Information Administration, DOE 

O.W. Girard, Jr. 

U.S. Geological Survey 

Jerry D. Ham 

U.S. Department of Energy (separated) 

Douglas H. Harnish (Leader, Task 4) 

U.S. Department of Energy 

J. N. Hicks 

Energy Information Administration, DOE 

Gary W. Horton 

U.S. Geological Survey 

Gordon Kaufman (Conferee) 

M.I.T. 

Vello A. Kuuskraa (ConfereE:) 

Lewin & Associates, Inc. 

Lawrence H. Luhrs 

U.S. Department of Energy 

Richard F. Mast (Leader, Task 1) 

U.S. Geological Survey 

Ira Mayfield 

U.S. Department of Energy 

William J. McCabe 

U.S. Department of Energy 

Richard F. Meyer (Project Coordinator) 

U.S. Geological Survey 

Betty M. Miller 

U.S. Geological Survey 

David F. Morehouse 

Energy Information Administration, DOE 
Frederic H. Murphy 

Energy Information Administration, DOE 

Chester R. Pelto 

Energy Information Administration, DOE 

(retired) 

Keith Robinson 

U.S. Geological Survey 

David H. Root (Leader, Task 3) 

U.S. Geological Survey 

John J. Schanz, Jr. (Conferee) 

Resources for the Future 

Nancy D. Smith 

Energy Information Administration, DOE 

Frank W. Stead (Leader, Task 5) 

U.S. Geological Survey 

J erzy J. S to sur 

U.S. Department of Energy 

E rcan Tukenmez 

Energy Information Administration, DOE 

K. L. Varnes 

U.S. Geological Survey 

Ralph Williams 

U.S. Geological Survey 

John Wood 

Energy Information Administration, DOE 

J.M. Wunder 

U.S. Geological Survey 

Gordon K. Zareski 

Energy Information Administration, DOE 

(separated) 

REFERENCES CITED 

American Gas Association, American Petroleum Institute, 

Canadian Petroleum Association, 1967-79, Reserves of 

crude oil, natural gas liquids, and natural gas in the United 

States and Canada (v. 21-23 and 30-32) and Reserves of 

crude oil, natural gas liquids, and natural gas in the United 

States and Canada and United States productive capacity 

(v. 24-29): Washington, D.C., American Petroleum Institute, v. 21 for year 1966 through v. 32 for year 1978. 

American Petroleum Institute, 1967-78, Annual fourth quarter 

summary of the quarterly review of drilling statistics for the 

United States: Washington, D.C., American Petroleum Institute. 

--1975, Joint Association Survey of the U.S. Oil and Gas 

Producing Industry, 1973: Washington, D. C. American 

Petroleum Institute, 83 p. (issued annually). 

Arps, J. J., and Roberts, T. G., 1958, Economics of d-illing for 

Cretaceous oil on east flank of Denver-Julesbu~g Basin: 

American Association of Petroleum Geologies B:lletin, v. 

42, no. 11,p. 2549-2566. 

Barouch, E., and Kaufman, G. M., 1978, The interface between 

geostatistical modeling of oil and gas disco·rery and 

economics: International Association for Mathematical 

Geology Bulletin, v. 10, no. 5, p. 622-627. 

Dietzman, W. D., Pearce, H. F., Funk, V. T., and Anderson, 

T. C., 1978, Cost and indexes for oil field equip'llent and 

production operations in the United States: U.E'. Department of Energy, Energy Information Administration, 

DOE/EIA 0096, 81 p. 

Drew, L. J., Attanasi, E. D., and Root, D. H., 1978, lnportance 

of physical parameters in petroleum supply rrodels, in 

DeYoung, J. H., Jr., ed., Mineral policies in transition- Proceedings of the Mineral Economics Symposium, 

November 8-9, 1977, Washington, D.C.: [Wr.shington, 

D.C.], American Institute of Mining, Metallurgical, and 

Petroleum Engineers, p. 52-69. Also published ir Minerals 

and Society, 1979, v. 3, no. 2, p. 163-174. 

Drew, L. J., Root, D. H., and Bawiec, W. J., 1979, F-;timating 

future rates of petroleum discoveries in the Permian Basin, 

in Hydrocarbon Economics and Evaluation Symposium, 

8th, Dallas, Tex., 1979, Proceedings: Society of Petroleum 

Engineers-AIME p. 101-106. 

Hicks, James N., 1978, Computerized deliverability crlculations 

for nonassociated gas reservoirs: U.S. Department of 

Energy, Energy Information Administration, DOE/EIA 

0065, 78 p. (also available through U.S. Department of Commerce, National Technical Information Service, Springfield, 

Va. 22161). 

Lewin and Associates, Inc., 1976, The potential and economics 

of enhanced oil recovery-final report, prepared for Federal 

Energy Administration: Washington, D.C., Lewin and 

Associates, Inc. 241 p. 

--1978, Enhanced recovery of unconventional gas, volumes 

1 and 2: U.S. Department of Energy HCP/T27C5-01 and 

HCP/T2705-02; v. 1, 48 p.; v. 2, 537 p. 

Miller, B. M., and others, 1975, Geologic estimates of undiscovered recoverable oil and gas resources in tl " United 

States: U.S. Geological Survey Circular 725, 78 p. 

National Petroleum Council, 1976, Enhanced Oil Recovery 

(EOR); an analysis of the potential for enhanced oi' recovery 

from known fields in the United States-1976 to 2000: 

[Washington, D.C.], 231 p. 

Pelto, Chester, 1973, Forecasting ultimate oil recovery in Petroleum Economics and Evaluation Symposium, Dallas, 

Tex., 1973: Society of Petroleum Engineers, p. 41>-52. 

Ryan, J. T., 1973, An analysis of crude-oil discovery rate in 

Alberta, Canadian Petroleum Geology Bulletin, v. 21, no. 2, 

p. 219-235. 

U.S. Bureau of Mines and U.S. Geological Survey, 1980, Principles of a resource/reserve classification for minerals: U.S. 

Geological Survey Circular 831. 

U.S. Federal Power Commission, 1976, Report oft}~ supplytechnical advisory committee study subgroup on Gas 

reserves and resources classifications-National Gas 

survey: 153 p. 

57 -tr U.S. GOVERNMENT PRINTING OFFICE: 1980 0- 311-344/162