Future Supply of Oil and Gas 

From the Gulf of Mexico

U.S. GEOLOGICAL SUltyEY PROFESSIONAL PAPER 1294
Future Supply of Oil and Gas 

From the Gulf of Mexico

By E. D. Attanasi and]. L. Haynes

U.S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 1294

An engineering-economic costing algorithm combined 

with a discovery process model to forecast 

long-run incremental costs of undiscovered 

oil and gas

UNITED STATES GOVERNMENT PRINTING OFFICE, WASHINGTON : 1983
UNITED STATES DEPARTMENT OF THE INTERIOR 

JAMES G. WATT, Secretary

GEOLOGICAL SURVEY 

Dallas L. Peck, Director

Library of Congress Cataloging in Publication Data

Attanasi, E. D.

Future supply of oil and gas from the Gulf of Mexico.

(U.S. Geological Survey professional paper ; 1294)

Bibliography: p.

1. Petroleum in submerged lands Mexico, Gulf of. 2. Gas, Natural, in submerged lands Mexico, Gulf of.

I. Haynes, J. (John), 1954- . II. Title. III. Series: Geological Survey professional paper ; 1294. 

TN872.A5A87 1983 553.2'8'0916364 83-600030 ____ ____________

For sale by the Superintendent of Documents, U.S. Government Printing Office

Washington, D.C. 20402
CONTENTS

Page

Abstract 1

Introduction 1

Engineering-economic model 3

Methodology 3

Engineering data and assumptions 5

Field classification 5

Field design 6

Production schedules of oil and nonassociated gas wells 7

Economic assumptions and variables 8

Field development costs 8

Production costs and production related taxes 9

Assumptions for after-tax net present value calculations 10

Exploration costs 10

Industry behavior and market conditions 10

Forecasting future discoveries 11

Discovery process model 11

Estimated marginal cost functions for undiscovered recoverable oil

and gas resources in the Gulf of Mexico 12 

Conclusions and implications 16 

References cited 16 

Appendix A 17 

Appendix B 20

ILLUSTRATIONS

FIGURE 1. Map showing location of study area in the Gulf of Mexico 2

2. Graph showing wildcat well discovery rate for oil and gas in the Gulf of Mexico to the end of 1975 3

3. Map showing geographic locations of the offshore geologic trend areas in study area in the Gulf of Mexico 4

4. Schematic diagram of the structure of the engineering-economic cost algorithm 5 

5-9. Graphs showing:

5. Production curves for oil wells in the Gulf of Mexico 7

6. Production curves for nonassociated gas wells in the Gulf of Mexico 8

7. Marginal costs of recoverable oil and gas resources, by form of hydrocarbon, from undiscovered fields

(as of January 1,1977) in the Gulf of Mexico 15

8. Wildcat wells projected to be drilled in the Gulf of Mexico as a function of marginal finding and

development costs and various assumed in situ costs of resources 15

9. Marginal cost of recoverable oil and gas resources from undiscovered fields (as of January 1, 1977)

in the Gulf of Mexico as a function of various assumed in situ costs of resources 15

in
IV CONTENTS

TABLES

TABLE 1. Distribution of exploratory wells in the Gulf of Mexico by geologic trend and Federal lease sale 3

2. Expected nominal crude oil and nonassociated gas recovery per well and field 6

3. Percentages of prospective areas in each water depth interval 6

4. Cost estimates for fabrication and installation of oil and gas production platforms in the Gulf of Mexico 9

5. Gulf of Mexico oil and gas processing equipment capacities and costs 9

6. Exploration efficiencies, areal extent, and expected remaining number of fields for various field size classes

7. Fields predicted to be found by 3 groups of 20 successive increments of 200 wildcat wells in the Miocene-Pliocene trend

8. Potential recoverable oil and gas resources from future discoveries in the Gulf of Mexico as a function of output 

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

A2. Development well, platform, and processing equipment configurations for new nonassociated gas fields in the

A5 . Drilling costs and completion costs for the Gulf of Mexico 

A7. Development strategies: Drilling and production stages 

Bl. Oil production schedule constants for Texas and Louisiana offshore oil fields by size class 

R2 NVinassnrviafWl eras nrnrhirtinn enimtirm nnrntnofora 

17

17

17

10

10

10

19 

20

91
FUTURE SUPPLY OF OIL AND GAS FROM THE GULF OF MEXICO

By E. D. ATTANASI and J. L. HAYNES*

ABSTRACT

Appraisals of oil and gas resources, which are typically presented 

in terms of proved and undiscovered categories, generally do not provide information on the costs of finding and (or) developing the 

resources. A model for integrating predictions from a discovery process model to estimate incremental costs of finding and producing 

undiscovered oil and gas resources (as of January 1, 1977) is 

presented and applied to the offshore Gulf of Mexico. Incremental 

finding and development costs were estimated separately for the 

Miocene-Pliocene trend (47,500 mi2) and the Pleistocene trend 

(12,978 mi2). Water depths range from 0 to 656 feet. The model is 

composed of two procedures. In the first, field development and production costs are estimated. Then, a discounted cash flow analysis is 

applied to estimate the amounts of undiscovered oil and gas that 

would be found and produced at different prices and rates of return 

that were based on the development and production costs. Predictions are based on the principle that incremental units of exploration, development, and production will not be expended unless the 

revenue expected to be received will cover the incremental costs, including a specified rate of return on the incremental investment. 

Thus, for each new increment of wildcat wells, the expected positive 

surplus of present value obtained through the fields found (by that 

increment) must provide a cash flow that is sufficient to pay for the 

increment of wildcat wells drilled.

An estimated 9.47 billion barrels of oil and 94.28 trillion cubic feet 

of gas or 25.19 billion barrels of oil equivalent (BOE) are contained in 

fields discovered prior to 1977 in the Gulf of Mexico. The application 

of the model indicated that, at $35 per BOE (in 1981 dollars) and an 

after-tax rate of return of 15 percent, an estimated 4.80 billion barrels could be economically discovered and developed. At $50 per 

BOE, the estimated discoverable oil and gas amounts to 6.78 billion 

BOE. However, these quantities represent only 19 and 27 percent of 

the 25.19 billion barrels discovered before 1977. These results indicate the mature state of exploration in the offshore Gulf of Mexico in 

areas of water depths of 656 feet or less. Analysis of the results indicates that drilling two to three wildcat wells in the Miocene-Pliocene 

trend for every well drilled in the Pleistocene trend will continue to 

be economically optimal.

Results of the analysis also indicate that, if past trends continue, 

71 percent of the hydrocarbon resources discovered after January 1, 

1977, will be in the form of nonassociated natural gas. Crude oil is 

expected to account for only about 17 percent of the hydrocarbons 

discovered. Natural gas liquids, from nonassociated gas fields, are 

expected to amount to about 39 percent of the amount of crude oil 

recovered.

'Global Marine, Inc.

INTRODUCTION

Appraisals of undiscovered conventional oil and gas 

resources rarely are accompanied by estimates of the 

expected costs of finding and producing the resources. 

In this study, a model is developed that computes quantities of undiscovered oil and gas resources (that are 

potentially recoverable) as a function of price and rate 

of return for the areas immediately offshore Texas and 

Louisiana out to a water depth of 656 feet in the Gulf of 

Mexico. The study area, encompassing 60,478 mi2 , is 

outlined in figure 1. This study is intended to complement an earlier effort by Drew and others (1982) in 

which a discovery process model was developed to forecast rates of oil and gas discoveries in terms of barrels 

of oil equivalent (BOE) for this same area.

Estimated recoverable hydrocarbons contained in oil 

and gas fields discovered in the Gulf of Mexico prior to 

1977 are 9.47 billion barrels of liquids and 94.28 trillion cubic feet of natural gas. In 1978, this area accounted for about 9 percent of U.S. oil production and 

about 25 percent of U.S. natural gas production. The 

(discovered) field size distribution in the Gulf of Mexico 

is somewhat skewed in that the largest fields account 

for a disproportionately large amount of the hydrocarbons discovered to date. Of the 409 oil and gas fields 

discovered through 1975, the largest 11 (or 2.7 percent 

of the total) contain 29.3 percent of the total hydrocarbons, and the largest 69 fields (16.9 percent) contain 68 

percent of the hydrocarbons. This skewed field size distribution is present in spite of a relatively large marginal field size due to the substantially higher costs of 

operating offshore.

When all parts of an area are accessible (both legally 

and technologically) to explorationists, the principal 

result of the wide range in field sizes is that the rate of 

discovery (volume of oil and gas discovered per unit of 

exploration effort) declines. This occurs because most 

of the hydrocarbons are in large fields and are associated with large, easily detected structures. These fields 

tend to be found early in the discovery history of an 

area. However, at any one time, only part of the Gulf of 

Mexico was available or of interest to explorationists
FUTURE SUPPLY OF OIL AND GAS FROM THE GULF OF MEXICO

32N, 96W

TEXAS

GULF OF MEXICO

100 KILOMETERS

FIGURE 1. Location of study area in the Gulf of Mexico (L. J. Drew, written commun., 1982).

because new technology had to be developed for certain 

phases of offshore operations and because the State 

and Federal Governments had only partially leased 

the area. The graph of the overall discovery rate for the 

Gulf of Mexico (see fig. 2) exhibits some degree of regularity. The irregularities in the Gulf of Mexico discovery rate are probably the result of restricted access 

that explorationists had to areas of interest and to the 

substantial increase in natural gas prices in the early 

1970's, which made many moderately large natural 

gas fields profitable to develop.

In modeling the Gulf of Mexico discovery process, 

Drew and others (1982) divided the area by general 

geologic trend. The areas, the combined MiocenePliocene and the Pleistocene trends, are presented in 

figure 3. More wildcat wells have been drilled in the 

Miocene-Pliocene trend than in the Pleistocene trend. 

In table 1, data are presented that show the wildcat 

wells grouped by trend and by the lease sale date of the

tract upon which they were drilled. Drew and others 

(1982) estimated parameters of a discovery process 

model by using historical data from the Miocene-Pliocene trend and by using an assumption about the functional form of the underlying field size distribution. 

Because the Pleistocene trend has only recently been 

intensively explored (see table 1), Drew and others 

(1982) used the Miocene-Pliocene trend as an analog 

for the Pleistocene trend. They adapted the model to 

discovery data of the Pleistocene trend to forecast rates 

of discoveries in BOE's.

In the following sections, the engineering-economic 

model is developed, along with its supporting assumptions. After briefly discussing the discovery process 

model and its linkage with the economic model, the incremental costs of finding and developing currently undiscovered oil and gas fields in the Gulf of Mexico are 

estimated. Results of the analysis and their implications are considered in the final section of the study.
ENGINEERING-ECONOMIC MODEL

MILLIONS OFBOE PERWILDCAT WELL

>f\j.^O>OOOfO-^O>00 00O) 

- 1947-53 ___ C"^""" 1954-55 !T-=»« 1956-57 """" 1958-59 J+ 

«^" 1960-61 

\ 

^ 1962-63 

/ 

ff 1964-65 

/ 

9 1966-67

rn i >

' 3) 

W^ 1968-69 

\

\ 1970-71

/

R 15 

di 4 

1 fe

0 500 1000 1500 2000 2500 3000 3500 4000 

CUMULATIVE WILDCAT WELLS

FIGURE 2. Wildcat well discovery rate (in barrels of oil equivalent 

(BOE) per wildcat well) for oil and gas discovered in the Gulf of 

Mexico to the end of 1975.

TABLE I. Distribution of exploratory wells in Gulf of Mexico by 

geologic trend and Federal lease sale

_ Number of exploratory wells Date of

sale Area Miocene-Pliocene

11/54 Tex. La. 218

07/55 Tex. La. 126

08/59 La. 34 

02/60 La. Tex. 315

03/62 La. Tex. 835

10/62 La. 18

(\A/RA T a 94.

03/66 La. 34 

10/66 La. 44 

05/67 La. 424 

05/68 Tex. 186 

11/68 La. 19 

01/69 La. 18 

12/69 La. 28

07/70 La. 60

12/70 - La. 110

11/71 La. 22

OQ/79 T a RQ

12/72 La. 62 

06/73 Tex. La. 34

0^/74. T ,a ^4.

0^/74. TW 1 Q

07/74 Tex.-La. 0 

10/74 La. 131

09/7^ TW ^4.

05/75 Tex.-La. 103 

Others (State water and 

disputed leases) ______________ 2339

Pleistocene

0 

0 

0 

25 

252 

0 

0 

0 

0 

22 

0 

0 

1 

1 

22 

339 

6 

14 

263 

200 

126 

127 

12 

60 

83 

35

9

ENGINEERING-ECONOMIC MODEL

METHODOLOGY

The engineering-economic model uses predictions of 

the size and distribution by water depth of oil and gas 

fields to be discovered, with a specified exploration effort, to estimate the incremental costs of finding and 

producing currently undiscovered fields. For each size 

and water depth category, an economic analysis of the 

representative field is performed, assuming a particular wellhead price and rate of return. In particular, the 

net after-tax cash flow consists of revenues from the 

production of oil and gas minus the operating costs, 

capital costs in the year in which they are incurred, 

and taxes. When the after-tax net present value of the 

representative oil (or gas) field is greater than zero, 

then all the oil (or gas) fields in that particular size 

class and water depth interval are assumed to be developed. For a specified oil and gas price and rate of 

return, the calculated reserves of newly discovered 

(economic) fields are aggregated to estimate potential 

study area reserves.

The discovery process model developed by Drew and 

others (1982) for the Gulf of Mexico study areas was 

used to generate distributions of new discoveries by 

field size class for successive increments of exploratory 

wells. For a particular wellhead price of oil and gas, 

successive increments (of 200 wildcat wells) were 

assumed to be drilled until the incremental costs (which 

include drilling, geologic and geophysical data collection, and lease acquisition) of wildcat wells are equal to 

or greater than the net present value of the developed 

fields discovered by the associated increment (of 200) 

wildcat wells. These predictions of recoverable and undiscovered oil and gas are based on the principle that 

incremental units of exploration, development, and 

production will not be expended unless the revenue expected to be received will cover the incremental costs, 

including a specified rate of return on the incremental 

investment.

Figure 4 presents a simplified schematic diagram of 

the operations of the cost algorithm. Because the predictions made by the discovery process model are only 

in terms of frequencies for BOE size classes, new discoveries are classified into oil and nonassociated gas 

fields and also are allocated across different water 

depth intervals for cost analysis. By using historical 

data of discoveries since 1969, ratios of the proportion 

of new fields that were either oil or nonassociated natural gas were calculated and applied to predicting the 

number of new fields that would be oil fields and (or) 

nonassociated gas fields. Newly discovered fields within each size class also were allocated by water depth 

according to the proportion of prospective area overlaid
FUTURE SUPPLY OF OIL AND GAS FROM THE GULF OF MEXICO

32N, 96W 32N, 92W

TEXAS

GULF OF MEXICO

100 KILOMETERS

FIGURE 3. Geographic locations of the offshore geologic trend areas in the study area in the Gulf of Mexico (from an unpublished map of 

the Gulf of Mexico prepared by the U.S. Geological Survey for Federal OCS Lease Sale 38 held in 1975).

by each water depth interval.

Production schedules for oil and nonassociated gas 

wells were generated with formulations originally 

developed by the Dallas Field Office of the U.S. Department of Energy (John Wood, written commun., 1979). 

By using the production schedule and the associated 

nominal reserves per well, the number of wells per 

field were estimated, and a development design (number of wells, platform size, processing equipment size, 

and development time profile) for each field size class 

and water depth interval was specified. With the production schedule, the individual well cash flow was 

computed for a given set of oil and gas prices and costs. 

Economic well life was terminated after the well cash 

flow equaled the economic limit rate; that is, the year 

when operator income was equal to the sum of direct 

operating expenses and production-related taxes. For 

each individual well representative of a specific field 

size class, the net after-tax cash flow stream was computed. The net after-tax cash flow stream is the production revenue minus operating costs, capital costs in the

year they are incurred, and taxes. Individual well net 

after-tax cash flow streams are adjusted and aggregated to be consistent with the field development time 

profiles that are presented in detail in Appendix A. If 

the sum of the annual components of the after-tax discounted cash flow stream for the representative oil or 

gas field (for each size class and water depth interval) is 

greater than zero, then all the newly discovered fields of 

that size and water depth category are assumed to be 

developed and are added to total potential reserves.

This study does not consider the rate of exploratory 

drilling in the time dimension, and so a full supply 

analysis, that is, quantity of hydrocarbons produced 

per unit time, is not performed. Moreover, operators 

are assumed to drill nonpreferentially for oil or gas 

fields. Exploration continues until the exploration costs 

(drilling, geologic and geophysical data collection costs, 

and lease acquisition costs) of the next 200 wildcat 

wells exceed the after-tax net present value of the 

resources found by that increment of wells. Assuming 

that production continues to the economic limit rate,
ENGINEERING-ECONOMIC MODEL

FOR EACH:

 WELLHEAD PRICE

 RATE OF RETURN 

. INCREMENT OF 200 WILDCAT WELLS

DISCOVERIES GENERATED BY 

DISCOVERY PROCESS MODEL

FIELD TYPE AND 

WATER DEPTH

X

OIL

NONASSOCIATED 

GAS

DETERMINE 

WELL PRODUCTION 

SCHEDULE 

WELL CASH FLOW 

ECONOMIC WELL LIFE

AGGREGATE WELL CASH 

FLOWS ACCORDING TO 

FIELD DESIGN AND 

DEVELOPMENT PROFILE

DETERMINE FIELD CASH 

FLOW AND PRESENT 

VALUE (PV) FOR RATE 

OF RETURN

IF PV ) 0,

FIELD DEVELOPED, AND 

RESERVES ADDED TO 

TOTAL RESERVES

1

REPEAT ANALYSIS FOR 

EACH TYPE FIELD, 

FIELD SIZE, AND WATER 

DEPTH

SUMMATION: NET 

PRESENT VALUES OF 

ALL ECONOMIC OIL 

AND GAS FIELDS

DETERMINE TOTAL 

EXPLORATION COSTS 

OF LAST 200 Wl LDCAT 

WELLS

IF EXPLORATION COSTS OF LAST 

INCREMENT OF WILDCAT WELLS 

GREATER THAN NET PRESENT 

VALUE OF RESOURCES FOUND, 

STOP EXPLORATION AND SUBTRACT 

RESERVES: OTHERWISE CONTINUE 

EXPLORATION

FIGURE 4. Schematic diagram of the operations of the cost algorithm 

used to translate geologic appraisals into estimates of potential 

reserves available at a particular cost.

the last increment of oil or gas produced from a field 

will be approximately equal to the price. Consequently, 

for the economic resources discovered by the last (economic) increment of exploratory wells, the sum of finding costs and development and production costs per 

BOE is equal to the wellhead price. For the economic 

resources found by the last economic increment of exploration, these two sets of costs are termed the marginal finding costs and marginal development and production costs, respectively. Marginal finding cost is 

computed by dividing total exploration costs of the last 

economic wildcat well increment by the corresponding 

economic resources discovered by these wildcat wells. 

An estimate of marginal development and production 

costs per BOE is made by subtracting the marginal 

finding cost from the wellhead price.

ENGINEERING DATA AND ASSUMPTIONS

FIELD CLASSIFICATION

To design field development configurations and estimate costs, the newly discovered fields were classified 

as oil or nonassociated natural gas fields. Large offshore fields in the Gulf of Mexico may include hundreds 

of smaller, technically separate (both horizontally and 

vertically) reservoirs that contain crude oil, associated 

gas, or nonassociated gas. Official reserve estimates 

from the Minerals Management Service (formerly the 

U.S. Geological Survey's Conservation Division) of 

past discoveries are classified under the product categories of liquids (crude oil and natural gas liquids) and 

natural gas; consequently, a field could not be classified on the basis of specific products present or absent. 

As a result, a somewhat arbitrary basis for classifying 

fields as predominantly crude oil or predominantly 

natural gas was used. Crude oil fields were assumed to 

have a maximum ratio of gas to liquids (on a British 

thermal unit (Btu) basis) of 4 to 1; otherwise, a field 

was classified as a nonassociated gas field. Processing 

equipment designed for nonassociated gas fields permits the processing of sufficient liquids so that the gasliquids ratio can be as low as 4 to 1.

To arrive at appropriate ratios of crude oil fields to 

nonassociated gas fields by size class, past discoveries 

were classified according to this criterion. Because of 

the great disparity in the past between prices for liquids 

and prices for natural gas, the operators preferentially 

searched for crude oil and avoided searching for natural gas. It was not until the early 1970's that natural 

gas prices escalated, although operators probably 

began anticipating these price increases as early as 

1969. The ratio representing the mix between historical 

oil and gas discoveries, from 1969 to 1977 (smoothed 

across field size classes), was used to project the mix of
FUTURE SUPPLY OF OIL AND GAS FROM THE GULF OF MEXICO

future discoveries. The ratio of crude oil to natural gas 

fields also is assumed independent of water depth. For 

the intensively explored Miocene-Pliocene trend, 25 percent of the future discoveries in each size class are projected to be crude oil fields according to the definition 

discussed above. Similarly, for the Pleistocene trend, 36 

percent of future discoveries in size classes 7 through 11 

and 22 percent of the future discoveries in size classes 12 

through 16 are expected to be crude oil fields. The BOE 

size class ranges are presented in table 2.

Because development costs vary substantially with 

water depths, future discoveries also should be 

classified by water depth. Areas bounded by the water 

depth contours of 60, 240, 393, and 656 feet were 

measured by planimeter. Estimates of the proportion 

of area accounted for by the areas within each contour 

are presented in table 3 (L. J. Drew, written commun., 

1981). The proportion of future discoveries by water 

depth are assumed to correspond to the proportion of 

the prospective area within the water depth contours 

for each of the two trend areas. For purposes of cost 

estimation, fields that fall in the 0 to 60, 60 to 240, 240 

to 393, and 393 to 656 feet intervals are considered to 

lie at water depths of 40,150, 317, and 525 feet, respectively.

TABLE 2. Expected nominal crude oil and nonassociated gas

recovery per well and field 

[BOE, barrel of oil equivalent; bbl, barrels; mcf, million cubic feet]

Size 

class

7

g

9 

10

11 

12 

13

15 

16

17 

1 Q

19 

°0~"

BOE 

size class 

range 

(10" BOE)

A 1Q f\ QQ

r\ QQ f\ "7C

 0.76-1.52 

1 52 3 04

 3.04-6.07

6 07 12 14

12 14 24 30

97 ° 194 3

 194.3 -388.6

Crude oil 

recovery 

per oil well 

(10s bbl)1

111.0 

178.0 

270.0 

387.0 

466.0 

545.0 

637.0 

744.0 

870.0 

1,020.0 

1,190.0 

1,390.0 

1,620.0 

1,900.0

Nominal oil 

recovery per 

crude oil field 

(10s bbl)

220.5 

447.0 

894.0 

1,814.0 

3,628.8 

7,257.6 

14,726.4 

29,452.8 

58,905.6 

119,500.8 

239,001.6 

478,003.2 

970,752.0 

1,941,514.0

Nominal 

nonassociated 

gas recovery 

per gas well 

(10* ft')1 -2

0.8 

1.5 

2.5 

3.5 

5.1 

7.2 

10.8 

14.5 

20.3 

24.4 

29.6 

39.2 

39.7 

42.7

Nominal gas 

recovery per 

nonassociated 

gas per field 

(10" ft'y

1.58 

3.16 

6.32 

12.65 

25.30 

50.59 

101.18 

202.37 

404.74 

809.47 

1,618.94 

3,237.89 

6,475.78 

12,951.55

'Farmer and Zaffarano (in press) and John Wood, written commun. (1979). 

"Natural gas field reserves and well reserves are for wet gas where 1 bbl of oil =5.27 mcf 

gas.

TABLE 3. Percentages of prospective areas 

in each water depth interval1

Water depth in meters

Trend area

Miocene-Pliocene - 

Pleistocene 

Total prospective area 

I

0-60

 39.4 

 0.0 

 30.9

n

60-240

52.6 

53.9 

52.9

in

240-393

6.7 

38.3 

13.5

IV 

393-656

1.3 

7.8

2.7

'L. J. Drew, written commun., 1981.

FIELD DESIGN

New field discoveries have the following characteristics: size class, water depth interval, and type (either 

crude oil or nonassociated natural gas). When determining the field configuration (number of wells per 

field), nominal values (as opposed to price sensitive 

actual values) of reserves per field and well were applied. The required number of development wells was 

estimated by dividing the nominal reserves per well by 

the nominal recovery per field (see table 3). To be consistent with the data upon which the well production 

schedules used in the cashflow analysis are based, the 

nominal recovery per field was taken as the midpoint 

of the field size classes used in Farmer and Zaffarano 

(in press), which were at most 10 percent greater than 

the midpoints of the field intervals shown in the second 

column of table 2. In the case of oil fields, the midpoint 

was adjusted to compensate for the expected recovery 

of associated gas that accounts for 25 to 30 percent of 

the total hydrocarbons on a Btu basis. The nominal 

recovery per well for crude oil wells and natural nonassociated gas wells was obtained either from published 

sources (Farmer and Zaffarano, in press) or by calculating reserves per well by using the well production 

schedule and a nominal price and operating cost. Reserves per well for each size class are presented in table 

2.

Configurations of development wells, production 

platforms, and processing equipment were devised to 

estimate investment and operating costs for the representative field. For any particular offshore oil or gas 

field, many combinations of different platform sizes 

and processing equipment configurations may be used 

in actual practice in the Gulf of Mexico. Site characteristics such as slope or sea floor conditions may dictate 

certain development designs. Alternatively, the operator may stage or time field development to maximize 

profits according to special economic or regulatory conditions that prevail at the time of discovery. The approach taken in this study in constructing the field 

development scenarios was to minimize overall development costs subject to the degree of excess capacity (in 

terms of extra platform slots and processing equipment 

capacity) that is frequently observed in the Gulf of 

Mexico. The configurations also were subject to a 

degree of standardization necessary for handling by a 

computer-based cost algorithm.

Tables Al through A4 in Appendix A present equipment configurations and time profiles of development 

for each representative field. The field development profiles reflect the assumptions that, for the larger fields 

(larger than class-13 oil and class-14 gas), approximately 10 percent of the wells in the field are drilled 

with mobile drilling rigs (prior to the platform implace-
ENGINEERING-ECONOMIC MODEL

ment) and the remainder of the wells are drilled by using platform drilling rigs. It is also assumed that, for 

every 100 successful productive wells, 20 dry development wells will be drilled. These implied development 

well success rates approximate experience for offshore 

Louisiana for the years 1976 through 1979.

PRODUCTION SCHEDULES OF OIL AND NONASSOCIATED 

GAS WELLS

Oil and nonassociated gas well production schedules 

for the Gulf of Mexico were developed by the Dallas 

Field Office of the U.S. Department of Energy (John 

Wood, written commun., 1979). Their basic mathematical description is presented in Appendix B. Production 

schedules were derived by using data from offshore 

Louisiana and Texas fields. The schedules are assumed 

to represent a typical well for an average field within 

each field size class. The production schedules for the 

class 11 and larger oil fields indicated that the representative wells will produce at a constant initial production rate for a period and then begin to decline 

exponentially. Production rates for smaller fields begin 

their decline immediately. For oil fields, associated gas 

production was calculated by using estimated ratios of 

gas to oil for each size field class. These gas-oil ratios 

are presented in appendix table A8. Figure 5 presents 

several oil well production profiles.

Nonassociated gas well production schedules also indicate a constant initial production rate for a period 

followed by a decline in production according to a 

hyperbolic function. To estimate quantities of natural 

gas liquids expected to be produced by gas wells, the 

gas well production schedules were supplemented with 

information from a geologic resource appraisal of undiscovered prospects in the Gulf of Mexico prepared for 

the U.S. Department of Energy (Richard Farmer, written commun., 1982). The estimated natural gas liquid 

yield for the Miocene-Pliocene trend is 17.52 barrels of 

liquid per million cubic feet of gas produced, and, for 

the Pleistocene trend, the yield is 14.74 barrels of 

liquid per million cubic feet of gas. Figure 6 presents 

several nonassociated gas production profiles.

7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

40

30

01 2345

FIGURE 5. Production curves for oil wells in the Gulf of Mexico (in thousands of barrels per year). Each curve is based on an average well for 

a representative field in size classes 9,12, and 15 (based on data from John Wood, Dallas Field Office, U.S. Department of Energy, written 

commun., 1979).
FUTURE SUPPLY OF OIL AND GAS FROM THE GULF OF MEXICO

TIME, IN YEARS

FIGURK 6. Production curves for nonassociated gas wells in the Gulf of Mexico (in millions of cubic feet of gas per year). Each curve 

is for representative fields in size classes 9, 12, and 15 (based on data from John Wood, Dallas Field Office, U.S. Department of 

Energy, written commun., 1979).

ECONOMIC ASSUMPTIONS AND VARIABLES

In the following sections, we discuss cost estimation 

methodology and economic assumptions. First, the 

estimation of field investment or development costs are 

considered according to four components: (1) drilling 

and well completion costs, (2) platform costs, (3) processing equipment costs, and (4) platform abandonment 

costs. Then we review the method for estimating operating costs. Following these two sections, the assumptions that pertain to the estimation of the after-tax net 

present value of each prospect are presented. In the 

final section, we consider the three components of exploration costs: (1) drilling cost, (2) geologic and geophysical data collection, and (3) lease acquisition cost.

FIELD DEVELOPMENT COSTS

Field development or investment costs include the 

costs of drilling and equipping production wells, including dry holes, the costs of production platforms, the 

cost of oil and gas processing equipment, and platform 

abandonment costs. Product transportation costs are 

not considered in this study. In the cash flow calculations for the representative well, all development costs 

were ultimately put on a per-production-well basis.

The cost of drilling and equipping development wells 

depends on water depth and the type of drilling rig 

used. Because of this and also because of the rather 

substantial volatility of the market for drilling services in the Gulf of Mexico in recent years, historical 

data such as the Joint Association Survey drilling costs 

were not extrapolated to estimate current costs. Instead, a predictive model was developed to estimate 

drilling costs by using drilling rig day rates, costs of 

items charged on a daily basis, and the cost of items 

that are independent of time and water depth.

All wells were assumed to be drilled to a depth of 

11,500 feet. Overall costs were estimated from industrysupplied data and known market day rates for various 

drilling rig sizes. Development well drilling time was 

assumed to be 30 days, and wildcat wells required 40 

days drilling time. Well completion time was an additional 15 days. This assumption was made for both 

platform and jack-up or semisubmersible drilling rigs. 

Mobile drilling rigs were assumed to be used exclusively for development drilling for oil and gas fields 

smaller than size class 10. For larger fields (class-13 oil 

and class-14 gas), platform drilling rigs were assumed 

to be used for drilling and completing 90 percent of the 

development wells. For platforms of 24 slots or larger, 

two platform drilling rigs were assumed to be operat-
ENGINEERING-ECONOMIC MODEL

ing. A detailed accounting of the fixed and time-sensitive costs is provided in Appendix A.

Platform costs were estimated by using data from 

vendors. A multiple regression equation was estimated 

with available data and later used to estimate costs for 

platform configurations where data were not available. 

Because available data indicated a discontinuity in the 

cost trend as a function of water depth at about 300 feet 

water depth, two separate regressions were fitted. One 

regression applies to water depths to 300 feet, and the 

other to 300 feet and deeper. The two estimated equations are:

(1) for water depths of less than 300 feet:

Cs=2,566.75+0.0255606(WZ»2 -r-185.643(SLr) 

+0.714992(WDXSL!T)

(2) for water depths 300 feet or greater:

Cs=l,210.21+0.0539188(WD)2 +71.8772(SLr) 

+1.12302(SLTXWD)

where Cs is the cost (in thousands of dollars), WD is 

water depth (in feet), and SLT is the number of slots in 

each platform. Table 4 presents a sample of the cost 

estimates for various platform sizes and water depths.

Processing equipment costs were estimated from 

prices supplied by vendors for the standard oil and gas 

processing equipment packages widely used in the Gulf 

of Mexico. Table 5 presents the oil and gas equipment 

capacities and costs used in this study. No attempt was 

made to estimate costs for nonstandard processing 

equipment capacities because, in practice, an operator 

would buy an overdesigned standard capacity equipment package rather than designing and special ordering a one-of-a-kind processing equipment configuration. The rated-liquids capacity for crude and natural 

gas assumes an equal amount of water is processed. In 

particular, a 1,500-barrel-per-day crude oil facility can 

actually process 3,000 barrels of liquids per day. It is 

not uncommon to process 1 barrel of water for each barrel of crude oil. However, for nonassociated gas fields, a 

common ratio of water to natural gas liquids is 1 barrel 

of water to 10 barrels of natural gas liquids. Consequently, the actual liquid-product-processing capacities 

of the equipment packages shown in table 5 for natural 

gas fields are substantially understated.

Little or no publicly available data exists on the costs 

of platform abandonment. Abandonment procedures 

require that operators cut the platform below the sea 

floor and mud line and remove it from the tract. The 

platform then may be salvaged for the steel or be refurbished and moved to another site. Abandonment costs 

were estimated to be half the original platform installation costs. Although abandonment costs are not incurred until the platform wells are abandoned, the

TABLE 4. Cost estimates for fabrication and installation of

oil and gas production platforms in the Gulf of Mexico

(in millions of 1981 dollars)

Water depth 

meters

Platform size

12 24 36 48

50 ________

100 

200 

300

400

500 

Cf\f\

3.959

4.365

5.561

NA*

NA

NA

NA

4.623

5.778

6.547

NA

NA

NA

NA

5.287

5.908

7.533

1ft Qfift

16.090

22.291

NA

7.944

8.994

11.477

1 1; QTQ

99 ^A.^

29.891

10.601

12.079

15.420

20 779

9ft SQfi

37.492

47.466

13.257

15.165

19.363

45.092

56.414

'NA = not applicable.

TABLE 5. Gulf of Mexico oil and gas processing equipment

capacities and costs (costs include installation and are

in 1981 dollars)

Petroleum liquids capacity1 

(barrels per day)

Oil field equipment

Natural gas capacity 

(million cubic feet per day)

Cost 

(thousands dollars)

1,500 

2,500 __

*> 000

10,000 

20,000 

10

15

oc

60

120

650

775

QOO

1,200

1,375

Natural gas capacity 

(million cubic feet per day)

Gas field equipment

Petroleum liquids capacity* 

(barrels per day)

Cost 

(thousands dollars)

15 .

25 -

50 -

100 -

200 -

300

550

1,000

2,500

4,500

700

755

1,065

1,600

1,900

'Petroleum liquids capacity excludes water; water is assumed to be in a one-to-one ratio to 

petroleum liquids so that actual liquid processing capacity (including water) is double the 

petroleum liquids capacity.

decision to shut down production was assumed to be 

made without considering the abandonment costs. 

Consequently, the present worth of the amount 

(assuming a 15-percent discount factor) of abandonment costs (that would be incurred after shut down) is 

added to the initial capital costs of the platform and 

thereby included in the overall field development costs.

PRODUCTION COSTS AND PRODUCTION RELATED TAXES

Operating costs were computed per production platform using a cost function developed by the U.S. Department of Energy (Farmer and Zaffarano, in press). 

Operating costs for crude oil and nonassociated gas 

production wells and platforms of a similar size and 

water depth were estimated to be the same (see Farmer 

and Zaffarano, in press). The equation has the form

OCT=1,265,821+13,554.933(SLT)

+0.058798(SL7WZ»2
10 FUTURE SUPPLY OF OIL AND GAS FROM THE GULF OF MEXICO

where OCT is the operating costs per platform, SLT is 

the number of slots in the platform, and WD is the 

water depth in feet. The costs generated from this function are in 1977 dollars and were inflated by 1.736 to 

account for cost increases prior to 1981 (Funk and 

Anderson, 1982). Operating costs include overhead, 

insurance, transportation of personnel and other personnel services, well workovers, and maintenance.

Because most significant new fields are expected to 

be in Federal offshore waters, the only production 

taxes assumed for this study were Federal royalties at 

a rate of 16.7 percent. No other severance or State 

taxes were assumed to be imposed directly on field 

production.

ASSUMPTIONS FOR AFTER-TAX NET 

PRESENT VALUE CALCULATION

1. Estimated costs were based on those prevailing in 

1981, so that the entire analysis assumed constant 1981 dollars.

2. Operators have 100-percent working interest in the 

lease.

3. The Federal royalty rate of 16.7 percent on all production applied (except where otherwise explicitly stated), and no other State or local production 

taxes were assumed.

4. Federal income tax rate was assumed to be 46 percent of taxable income.

5. No limit on the carry over of losses for income taxes 

was assumed.

6. Depreciation was calculated by the unit-of-production method.

7. The investment tax credit was computed as 10 percent of all depreciable investment costs.

8. Cost depletion was applied when determining the 

depletion allowance for Federal income taxes. 

The basis for cost depletion included geologic and 

geophysical data collection costs and lease acquisition costs. In 1979, the estimated expenditure on geophysical data collection was $196.5 

million (U.S. Census Bureau, 1981). The Gulf of 

Mexico accounted for approximately 74 percent of 

the total 1979 geophysical crew months in the offshore conterminous 48 States (American Association of Petroleum Geologists, 1980). There were 

280 wildcat wells drilled in the Gulf of Mexico in 

1979, so the geophysical cost per well was about 

$519,000 per well. These costs were inflated to 

$732,000 per wildcat well to 1981 dollars by using the general drilling cost inflation of 18.7 percent experienced from 1979 to 1980 (American 

Petroleum Institute, 1982). Estimates of lease acquisition costs were computed by multiplying the 

nominal field reserve by an assumed per BOE in

situ value. The assumed in situ values were adjusted for water depth to compensate for extra 

risks and costs of operating in the deep areas. The 

adjustment scheme is discussed in the presentation of specific results pertaining to alternate 

assumed lease acquisition costs (see p. 00). The 

computation of depletable cost per unit output is 

the sum of expenditures on lease acquisition and 

geologic and geophysical data collection divided 

by the initial estimated reserves (or proportion of 

working interest in reserves). For both cost depletion and unit-of-production depreciation, calculated reserves for each well or field were determined by assuming that production stops when 

the economic limit rate is reached. The economic 

limit rate is the production rate at which 

operating costs plus production-related taxes 

equal operators revenues.

9. We assumed that 70 percent of the drilling costs of 

successful wells along with costs of all dry wells 

were expensed and that all well completion costs, 

platform costs, and processing equipment costs 

were capitalized.

EXPLORATION COSTS

1. All wildcat wells are drilled to a target depth of 

11,500 feet.

2. Expenditures for geologic and geophysical data collection are set at $732,000 per wildcat well.

3. Explorationists were assumed to search nonpreferentially for either oil or gas.

4. Newly drilled wildcat wells are allocated according 

to water depths in the same proportion as the percent of total prospective area in each water depth 

interval.

5. Exploration costs associated with each increment 

of wildcat wells also include expenditures associated with lease acquisition. Total lease acquisition costs were estimated by multiplying the 

quantity of economic resources discovered with 

each wildcat well increment by an assumed in 

situ value of the resource. In this scheme, the in 

situ values are adjusted for cost differences and 

risks of operating at various water depths.

INDUSTRY BEHAVIOR AND MARKET CONDITIONS

Several assumptions associated with industry behavior are reiterated here. First, it is assumed that field 

development design, along with development timing, 

are independent of current prices or operator price expectations. In practice, field design and development
FORECASTING FUTURE DISCOVERIES 11

staging are influenced by operators' cash flow needs 

and expectations about oil and gas prices. The result is 

a slight increase in actual development costs. It is also 

implicitly assumed that there will be sufficient excess 

capacity in the contract drilling industry and among 

equipment and platform suppliers to accommodate 

without substantial delays any change in industry 

activity.

This analysis assumes that lease selection practices 

will not be a constraint to explorationists. Further, it is 

also assumed that development of oil and gas resources 

in the Gulf of Mexico will not affect the price of oil or 

natural gas. Whereas this assumption is probably true 

for crude oil, it may not be realistic for natural gas, 

because in 1978 the Gulf accounted for 25 percent of 

U.S. natural gas production.

Lease acquisition costs were determined outside the 

model. Theoretically, the payments the petroleum industry makes to acquire prospective undeveloped oil 

and gas acreage is related to the in situ value of the 

resource. Uncertainty about the quantities of hydrocarbons accounts for the deviation of expected discovery costs (or resource replacement) from the in situ 

value of identified resources. Operators are risk averse, 

and the penalties associated with overestimating undiscovered resources are much greater than for underestimating the resources. As a result, lease bids should 

understate the in situ value of the resources. Individual 

tracts also have qualities that influence the price that 

operators are willing to pay. For example, for offshore 

tracts, water depth significantly influences costs of 

development and therefore will affect the price that 

operators are willing to pay for the tract. Moreover, at 

any specific time, the willingness of the petroleum industry to acquire and explore in any given basin or 

area depends on the quality of exploration opportunities and discovery costs for other areas.

Because of these complicating factors, it was not surprising that an analysis of long-term trends in bids for 

Federal offshore areas failed to yield a workable model 

that could be applied in this study to predict lease acquisition costs. In view of this, lease costs are assumed 

and set on the basis of per unit of oil and gas reserves 

that were discovered. Computations of the future costs 

of finding and developing oil and gas in the Gulf of 

Mexico were made assuming a suite of values for lease 

acquisition costs. Lease acquisition costs do not influence the decision as to whether to develop a particular 

identified field. For an increment of 200 wildcat wells, 

however, all lease costs must be recovered through the 

industry's activities. Consequently, the lease costs are 

added to exploration costs and will determine, in part, 

when total exploration costs will exceed the returns 

from fields discovered by an increment of exploratory 

wells.

FORECASTING FUTURE DISCOVERIES

DISCOVERY PROCESS MODEL

The discovery process model applied here was developed by Drew and others (1982). They used the analytical structure devised by Arps and Roberts (1958) 

who assumed that, for any size class field, the probability of discovery is directly proportional to the number 

of undiscovered fields and the ratio of their average 

areas to the effective basin area. A consequence of this 

assumption is that the largest fields in the basin tend 

to be found and developed early in the area's exploration history.

The analytical form of the Arps-Roberts model suggests that the proportion of undiscovered fields in a 

given size class declines exponentially as drilling continues. The cumulative number of discoveries expected 

to be made of fields for a given size class after drilling 

w cumulative wildcat wells is predicted with the 

equation:

where Ft(w) is the cumulative number of fields expected to be discovered in size class i by drilling w wildcat wells, Fj(oo) is the ultimate number of fields in size 

class i, B is the basin area, A; is the (average) area of 

fields in size class i, and Ct is the efficiency of discovery 

of fields in size class i. For random drilling, C;=l; if 

drilling is twice as efficient as random drilling, Ct =2. 

Arps and Roberts, in their initial application of the 

model, assumed a constant exploration efficiency across 

size classes.

In the application of the model to the Gulf of Mexico, 

Drew and others (1982) estimated the efficiency separately for each size class. For most classes in the 

Miocene-Pliocene trend, the number of discoveries for 

equal increments of exploratory effort by size class had 

declined by January 1977. However, for the classes 

smaller than class 12, discovery rates had remained 

relatively constant through 1976. Substantial increases 

in new oil and natural gas prices that occurred in the 

early 1970's resulted in many more reported discoveries of fields that were formerly reported as only 

shows of hydrocarbons because they had not been commercial. For size classes where the discovery data were 

thought to be influenced by economic truncation, C, 

and Fj(oo) were estimated by another method. Drew and 

others (1982) assumed that the ultimate underlying 

field size distribution is approximately log geometric 

in form. For example, for size class 12, the ultimate 

number of fields was estimated by multiplying the estimated ultimate number for class 13 by 1.65; that is, 

/J_2=1.65 -ft where fi is the ultimate number of fields in
12 FUTURE SUPPLY OF OIL AND GAS FROM THE GULF OF MEXICO

size class i. This scheme was applied to size classes 9 

through 12 for the Miocene-Pliocene trend.

For the sparsely explored Pleistocene trend, Drew 

and others (1982) used the Miocene-Pliocene trend as 

an analog. In particular, they assumed that the exploration efficiencies estimated for the Miocene-Pliocene 

trend by size classes would prevail in the Pleistocene 

trend. These assumed class efficiencies, together with 

the number of discoveries for each size class, permitted 

the estimation of the ultimate number of fields by size 

class. For field size classes less than class 13 that appear to be affected by economic truncation, the same 

procedure used in the Miocene-Pliocene trend was applied to the estimation of the ultimate number of fields 

by size class. In particular, for fields in size class 12 or 

smaller, the ultimate number of fields was estimated 

by using the relation /|_; = 1.65 /-.

In table 6, parameters of the model used for estimating the rate of future discoveries are presented. The 

values for FX°°) are obtained by adding the number of 

fields discovered to the number remaining to be found. 

Forecasts of future discoveries were made for 60 increments of 200 wildcat wells. Of course, for any given 

price and discount rate, not all of these 60 increments 

of 200 wells were economical. The discovery process 

model predictions are aggregated into 3 groups of 20 

successive increments of 200 wildcat wells for each 

trend and presented in table 7.

ESTIMATED MARGINAL COST FUNCTIONS FOR

UNDISCOVERED RECOVERABLE OIL AND GAS IN THE

GULF OF MEXICO

Table 8 presents estimates of marginal finding and 

production costs exclusive of the cost of lease acquisition. Because no lease acquisition costs are included, 

the costs underestimate the actual costs that firms will 

incur or, alternatively, the estimates of potential 

recoverable reserves are optimistic. However, these 

estimates indicate that even at $50 per BOE and a 

5-percent after-tax rate of return, economic undiscovered hydrocarbons in the Gulf of Mexico are about 33 

percent of total discoveries to January 1977 (of 25.19 

billion BOE). Furthermore, 13,600 wildcat wells (or 

well over 3 times the wildcat wells drilled through 

1977) are needed to identify these resources.

The results presented in table 8 provide information 

to answer two questions: What price and rate of return 

are required to stimulate a certain level of exploration 

to find a given amount of oil and gas? What amount of 

oil and gas can be anticipated from the Gulf of Mexico 

at present or some future price and rate of return? 

According to table 8, at a 15-percent required rate of 

return, raising the wellhead price from $35 per BOE to 

$50 per BOE increases the number of economic wildcat 

wells from 5,600 to 9,600, or 71 percent. As a result, 

the total potential recoverable oil and gas resources increase from 4.80 billion BOE to 6.78 billion BOE, or 41 

percent. Thus, in this example, by raising the price 43 

percent, from $35 to $50, an additional 70 percent more 

wildcat wells were economic and could be drilled, 

resulting in a 41-percent increase in hydrocarbon discoveries. However, this additional quantity of hydrocarbons amounts to only 8 percent of the amount of oil 

and gas discovered to January 1977.

The Miocene-Pliocene trend currently has about 

three times as many wildcat wells drilled in it as the 

Pleistocene trend. The analysis suggests that explorationists should optimally continue to drill the MioceneTABLE 6. Exploration efficiencies, areal extent, and expected remaining number of fields for various size classes in the Gulf of Mexico 

(from Drew and others, 1982, and J. H. Schuenemeyer, written commun., 1981)

Miocene-Pliocene trend1

Size 

class

9

11

12

13

14

15 _____________ 

lg _____________ 

17 _____________ 

18

1Q

90

Size range 

10" BOE

0.19-0.38 

0.38-0.76 

0.76-1.52 

1.52-3.04 

3.04-6.07 

6.07-12.14 

1914 94 3

24.3 -48.6 

48.6 -97.2 

97.2 -194.3 

194.3 -388.6 

388.6 -777.2

777 9 1 *\*\4. 9

1554.2 3108.4

Exploration 

efficiency

1.83 

2.24 

2.65 

2.65 

2.65 

2.65 

2.65 

3.40 

4.15 

4.89 

5.64

-

Area

(mi2 )

0.61 

.74 

.92 

1.18 

1.58 

2.17 

3.09 

4.55 

6.93 

10.91 

17.17

_

Fields 

discovered

by 1/1/77

24 

27 

27 

35 

50 

42 

43 

25 

17 

5 

2

Number Cj 

of fields Exploration 

remaining efficiency

2421.0 - 

1468.0 - 

864.4

512.2 - 

299.7 - 

163.0 - 

70.3 - 

23.9 - 

7.7 - 

.8 - 

0 - 

0

0 -

Pleistocene trend2

Area 

(mi2)

0.61 

.74 

.92 

1.18 

1.58 

1.66 

2.58 

4.03 

4.28 

9.79 

15.26

-

Fields 

discovered 

by 1/1/77

9 

11 

20 

17 

21 

26 

9 

8 

3 

1

Number 

of fields 

remaining

976.6 

591.9 

349.7 

206.4 

111.8 

62.9 

30.3 

13.9 

1.4 

.2 

0 

0

'Basin area (B) for the Miocene-Pliocene trend was 47,251 mi2. 

2Basin area (B) for the Pleistocene trend was 12,983 mi*.
FORECASTING FUTURE DISCOVERIES 13

TABLE 7. Fields predicted to be found by 3 groups of 20 successive 

increments of 200 wildcat wells in the Miocene-Pliocene trend 

and in the Pleistocene trend (each group represents 4,000 

wildcat wells in each trend)

Size 

class

Miocene-Pliocene trend

Wildcat well group 

I II III

Pleistocene trend

Wildcat well group 

I II III

7 -

8-

9 

10-

11 

12 -

13 -

14 

15 -

16 -

202.90

172.37

141.33

102.12

74.06

52.33

35.13

17.46

7.00

0.77

184.58

149.79

114.99

78.38

51.96

32.16

17.59

4.70

0.65

0.00

167.95

116.48

93.53

60.15

36.47

29.42

8.76

1.19

0.03

0.00

178.51

132.30

99.09

80.72

61.79

42.24

26.61

13.62

1.39

0.20

144.11

100.63

69.16

46.27

25.74

10.91

3.25

0.22

0.00

0.00

116.31

76.56

48.25

26.35

10.72

2.81

0.40

0.00

0.00

0.00

Pliocene trend at about that same ratio. This result, 

which is somewhat unexpected, probably occurs for two 

reasons. First, according to table 2, none of the prospective target areas for the Pleistocene trend are in the 

shallowest water depth interval. Almost half (46 percent) of the prospective area associated with the 

Pleistocene trend is located in water depths of greater 

than 240 feet, whereas 92 percent of the prospective 

area in the Miocene-Pliocene trend is located in water 

depths shallower than 240 feet. On the average, then, 

finding and development costs for Miocene-Pliocene 

trend areas will be much less than for comparably sized 

fields in the Pleistocene trend. Another reason for the 

larger number of wells in the Miocene-Pliocene trend is 

that it includes about 3.7 times the area of the Pleistocene trend. This result is also independent of the lease 

costs when they are introduced.

Figure 7 indicates the hydrocarbon mix associated 

with the results presented in table 7. Most of the future 

hydrocarbons from the Gulf of Mexico will come predominately from what we have defined as nonassociated natural gas fields. At a price of $35 per BOE 

(assuming a 15-percent rate of return), all liquids account for about 24 percent of the hydrocarbons on a 

BTu basis, whereas crude accounts for about 72 percent of liquids or about 17 percent of all hydrocarbons 

discovered. Associated gas accounts for about 5 percent 

of the total hydrocarbons, and nonassociated gas accounts for the remaining 71 percent of hydrocarbons. 

This mix of hydrocarbons holds for a wide range of 

prices and costs.

We might also compare the amount of resources discovered with the ultimate amount of resources remaining to be discovered. In this report, we have assumed 

an estimate of the nominal ultimate recovery for each 

field size class that is different from the historical 

average size of fields found in each size class. If the

assumptions used here were applied to the frequencies 

of remaining deposits (see table 6, size classes 8 to 16) 

that were estimated by Drew and others (1982), there 

would be 12.72 billion BOE of hydrocarbon resources 

remaining. Consequently, even at $50 per BOE (at a 

5-percent required return), only 63 percent of the total 

resources would be found and developed. The remaining resources beyond that amount would be very costly 

to find and develop without a significant technological 

breakthrough. Using the historical average for class 

size instead of the nominal recoveries used here, Drew 

and others (1982) estimated total remaining hydrocarbons to be 10.65 billion BOE or about 93 percent of the 

amount (11.48 billion BOE) that would have been obtained using our nominal field sizes for classes 9 

through 16. Because the data used for estimating the 

historical field size classes are based on proved 

reserves, the averages might be expected to increase as 

infield drilling results in larger estimates of reserves of 

the fields used in estimating the discovery process 

model. However, if the ultimate recovery of future discoveries only matches the proved reserves of past discoveries, then the overall results presented in table 8 

should be reduced accordingly, to perhaps 93 percent of 

the values presented.

The results presented in table 8 are compared in 

figures 8 and 9 to cases where various lease acquisition 

costs were assumed. Introduction of positive lease costs 

in this analysis will not affect the decision to develop 

an already identified field. However, lease costs are 

added to exploration costs and therefore influence the 

number of wildcat wells that are determined to be economic. Lease acquisition costs were introduced by 

assuming an in situ value per BOE adjusted for water 

depth for the resource. The amount of the required 

adjustment was estimated by running the economic 

model where lease costs were excluded and determining cost differences (reductions in after-tax present 

values) due to water depth costs. Analysis of the differences in the after-tax present values of marginal fields 

across the four water depth intervals used in this study 

indicate that, on the average (for a variety of prices and 

discount rates), the after-tax net present values of marginal fields at depth intervals of 60 to 240 feet, 240 to 

393 feet, and 393 to 656 feet were 90 percent, 70 percent, and 35 percent, respectively, of the values for the 

shallowest interval (0 to 60 feet) of water depth. These 

factors were used to scale the assumed in situ values of 

the resource.

Gruy and others (1982) recently reviewed prices paid 

for oil and gas reserves in merger and reserve acquisition transactions from 1979 to 1981. The prices ranged 

from $3.44 to $12.65 per BOE, with the most recent 

(February 1981) at $8.63. However, reserve estimates 

used in their study corresponded to currently recover-
TABLE 8. Potential recoverable oil and gas resources from future discoveries in the Gulf of Mexico as a function of output price, 

cost, marginal production costs, exploratory wells, and return on investment (ROI) (exclusive of lease cost)

[BOE, barrels of oil equivalent; Tcf, trillions of standard cubic feet of natural gas]

Miocene-Pliocene

Output 

price 

($/BOE)

15 

on

oc

30

QC

40 -

45

50

Cumulative 

ROI wildcat 

(percent) wells1

 5

15 

25

5

15 

25

 5

15 

25

5

15 

25

 5

15 

25

5

15 

25

5

15 

25

- - - 5

15 

25

800

2400 

600

3800 

1800 

200

5200 

2800 

1200

6600 

4000 

2000

8000 

5000 

3000

9200 

6200 

4000

10200 

7200 

5000

Marginal costs2

Finding 

($/BOE)

3.06

4.41 

2.69

5.86 

3.71 

2.17

7.55 

4.67 

3.10

9.05 

5.99 

3.80

10.57 

7.00 

4.70

12.10 

8.18 

5.60

13.53 

9.37 

6.70

Production

($/BOE)

11.94

15.59 

17.31

19.14 

21.29 

22.83

22.45 

25.33 

26.90

25.95 

29.01 

31.20

29.43 

33.00 

35.30

32.90 

36.82 

39.40

36.47 

40.63 

43.30

Total 

liquids 

(10")

.219

.563 

.178

.797 

.463 

.067

.958 

.661 

.339

1.098 

.834 

.527

1.211 

.956 

.703

1.334 

1.079

.847

1.393 

1.176 

.966

Total gas 

Tcf BOE 

(10")

4.344

11.028 

3.486

15.096 

8.994 

1.290

18.246 

12.444 

6.552

20.982 

15.738 

9.870

23.472 

18.162 

13.272

25.218 

20.796 

16.200

26.412 

22.512 

18.540

.724

1.838 

.581

2.516 

1.499 

.215

3.041 

2.074 

1.092

3.497 

2.623 

1.645

3.912 

3.027 

2.212

4.203 

3.466 

2.700

4.402 

3.752 

3.090

Total 

BOE

.943

2.401 

.759

3.313 

1.962 

.282

3.999 

2.735 

1.431

4.595 

3.457 

2.172

5.123 

3.983 

2.915

5.537 

4.545 

3.547

5.795 

4.928 

4.056

Cumulative 

wildcat 

wells1

200

800 

200

1200 

600

1800 

1000 

400

2200 

1400 

600

2600 

1600 

1000

3000 

2000 

1200

3400 

2400 

1600

Pleistocene

Marginal costs*

Finding 

($/BOE)

2.65

4.30 

2.61

5.35 

3.53

7.30 

4.64 

2.97

8.72 

5.85 

3.45

10.08 

6.43 

4.49

11.50 

7.66 

5.02

13.28 

9.08 

6.23

Production

($/BOE)

12.35

15.70 

17.39

19.65 

21.47

22.70 

25.36 

27.03

26.28 

29.16 

31.55

29.92 

33.57 

35.51

33.50 

37.34 

39.98

36.72 

40.90 

43.77

Total 

liquids 

(10')

.057

.194 

.058

.268 

.160

.343 

.238 

.113

.393 

.299 

.166

.431 

.332 

.243

.470 

.378 

.275

.497 

.416 

.335

Total gas 

Tcf BOE 

(109)

1.278

4.110 

1.296

5.574 

3.402

7.206 

4.968 

2.472

8.052 

6.264 

3.438

8.862 

6.804 

5.064

9.534 

7.800 

5.772

10.062 

8.592 

6.900

.213

.685 

.216

.929 

.567

1.201 

.828 

.412

1.342 

1.044 

.573

1.477 

1.134 

.844

1.589 

1.300 

.962

1.677 

1.432 

1.150

Tot

BO

(10

.2

.8

.2

1.1

.7

1.5

1.0

.5

1.7

1.3

.7

1.9

1.4

1.0

2.0

1.6

1.2

2.1

1.8

1.4

'Exploratory wells assumed to be drilled since December 31,1976. The stopping rule for exploratory wells does not take into account the tax benefit of charging the cost of exploratory wells again

current income. Therefore, these figures overestimate the effective cost of exploratory drilling. 

'At the margin, the sum of the marginal finding cost and the marginal production cost is equal to the output price (column 1).
FORECASTING FUTURE DISCOVERIES 15

CO

8

1-

LJJ

Q. 

O 111

LU CC 

O LU

is

is

50

45

40

35

30

2 25

O

DC

20

/ / 

CO 11

<

h O 

Q

£ 

<

O , Si

CO i < '

1 ' J

* I

I / /

M /

ILL

ol 

tu ,

/

*

/

01 234 56 7

UNDISCOVERED PETROLEUM, IN BILLIONS OF BOE

FIGURE 7. Marginal costs of recoverable oil and gas resources (in dollars per barrel of oil equivalent (BOE)), by form of hydrocarbon, from 

undiscovered fields (as of January 1, 1977) in the Gulf of Mexico (15 percent discounted cash flow return and zero lease cost assumed).

able reserves with production facilities already in 

place. Consequently, we performed the economic analysis using $1.50 and $3.00 per BOE as in situ values of 

the resource.

In figure 8, the number of economic wildcat wells is 

shown as a function of marginal finding and production costs for cases where assumed in situ resource 

values were zero, $1.50 per BOE, and $3.00 per BOE. 

Figure 9 shows the relation between potential recoverIN SITU VALUE OF

RESOURCE PER BOE

$3.00 $1.50 $0.0

PCO

81-

UJ

O. LU Q o

u m

> DC 

LU LU 

Q QQ CO

^ DC <5

li

-z. -z. C ~ 

_i

1

g

i

45

40

35

30

25

20

I 1 1 I I 1 1 J 1 X" 'X

x x X 

x XX

x' / S

' / ,' / / '

XX' .' .' .'

X x x 

X / ^ 

/ / "

X * ' X

x x x

X X X 

X / X 

X"* '"

X X

/ '

X , x 

X

X

X

-X , i ,,,,,,

01 23456789 10 

WILDCAT WELLS, IN THOUSANDS

FIGURE 8. Wildcat wells projected to be drilled in the Gulf of Mexico 

as a function of marginal finding and development costs of oil and 

gas (in dollars per barrel of oil equivalent (BOE)) and in situ per 

barrel of oil equivalent costs of resources (15-percent discounted 

cash flow return assumed).

able undiscovered reserves as a function of marginal 

finding and production costs for these same assumed in 

situ resource values. Figures 8 and 9 assume a 15-percent return on investments. At $35 per BOE, figure 7 

indicates recoverable resources for the $3.00 per BOE

IN SITU VALUE OF 

RESOURCE PER BOE

$3.00 $1.50 $0.0

co 50

to O

" 45

O § 40

^J

LU EC

> LU

LU Q.

0 8 35

 z. < < 3

o o

i Q 30

9c

25

20

J* 

.' / /

/

/

/ s

01234567 

UNDISCOVERED PETROLEUM, IN BILLIONS OF BOE

FIGURE 9. Marginal cost of recoverable oil and gas resources (in 

dollars per barrel of oil equivalent (BOE)) from undiscovered fields 

(as of January 1,1977) in the Gulf of Mexico as a function of in situ 

per barrel of oil equivalent costs of resources (15-percent discounted 

cash flow return assumed ).
16 FUTURE SUPPLY OF OIL AND GAS FROM THE GULF OF MEXICO

in situ costs at about 68 percent of the zero lease cost 

estimate, and for $1.50 per BOE recoverable resources 

are about 85 percent of the zero lease cost estimate. At 

$50 per BOE, the estimate at $3.00 per BOE in situ 

costs is almost 90 percent of the zero lease cost estimate, whereas the estimate assuming $1.50 per BOE 

in situ value was 91 percent of the zero lease cost estimate. As price and prevailing marginal costs are permitted to increase, relative differences in these potential discoveries diminish because the discovery rates 

are continually declining. In particular, although the 

higher prices (and lower in situ values) permit more 

wildcat wells to be drilled, the economic resources per 

wildcat well increment diminishes with the cumulative number of wildcat wells.

CONCLUSIONS AND IMPLICATIONS

The analysis shows that, at $35 per BOE and at a 

15-percent rate of return (without lease acquisition 

costs), the potential recoverable oil and gas discovered 

after January 1, 1977, is estimated to be 4.80 billion 

BOE. This amount is less than 19 percent of the estimated combined oil and gas discovered through 1976. 

Even at $50 per barrel (and a 15-percent return), the 

expected discoveries yield only 6.78 billion BOE from 

new fields, which is still only 27 percent of past discoveries. Without technological breakthroughs, additional 

oil and gas beyond this amount is likely to be very costly to find and develop.

The economic analysis indicates that, for every wildcat well drilled in the Pleistocene trend, there probably 

will be two or three wildcat wells drilled in the Miocene-Pliocene trend. Higher costs due to greater water 

depths for fields in the Pleistocene trend and the larger 

prospective area in the Miocene-Pliocene trend contribute to this result.

In all cases studied, if trends of the past 10 to 12 

years continue, over 71 percent of resources in future

discoveries will be in the form of nonassociated gas, 

and less than 17 percent of these resources will be in 

the form of crude oil.

Future oil and gas exploration in the Gulf of Mexico 

can still be profitable. At a 15-percent return and $35 

per BOE with lease costs corresponding to $3.00 per 

BOE for the in situ resources, an additional 3,000 wildcat wells (after January 1, 1977) can be commercially 

drilled. However, these wells are expected to yield only 

3.26 billion BOE of new reserves, which is less than 3 

years of production at the 1977 level of 1.1 billion BOE 

per year. Moreover, because these fields will generally 

be smaller and in deeper water depths, the oil and gas 

from the new discoveries will be more difficult and 

costly to produce.

REFERENCES CITED

American Petroleum Institute, 1982, American Petroleum Institute 

Basic Petroleum Data Book: v. 11, no. 2, Washington, D.C.

American Association of Petroleum Geologists, 1980, North American 

Developments Issue: Bulletin of the American Association of 

Petroleum Geologists, v. 64, no. 9, p. 1291-1570.

Arps, J. J., and Roberts, T. G., 1958, Economics of Cretaceous oil on 

the east flank of the Denver-Julesburg basin: Bulletin of American 

Association of Petroleum Geologists, v. 42, no. 11, p. 2549-2566.

Drew, L. J., Schuenemeyer, J. H., and Bawiec, W. J., 1982, Estimation of the future rates of oil and gas discoveries in the western 

Gulf of Mexico: U.S. Geological Survey Professional Paper 1252, 

26 p.

Farmer, Richard, and Zaffarano, Richard, OCS oil and gas supply 

model Data description, v. 3: U.S. Department of Energy tin 

press].

Funk, V. T., and Anderson, T. C., 1982, Cost indexes for domestic oil 

and gas field equipment and production operations, 1981: U.S. 

Department of Energy, Energy Information Administration, 

Washington, D.C., 158 p.

Gruy, H. J., Garb, F. A., and Wood, J. W., 1982, Determining the 

value of oil and gas in the ground: World Oil, March, p. 105-108.

U.S. Bureau of the Census, 1981, Current Industrial Reports, Series 

MA-13K(79)-1, Annual Survey of Oil and Gas, 1979: U.S. Government Printing Office, Washington, D.C., 74 p.
APPENDIX A. FIELD EQUIPMENT

CONFIGURATION, COSTS, AND

DEVELOPMENT PROFILES

This section presents assumptions and data relating 

to offshore field development equipment configurations 

and practices. Although one might find various operators using many different configurations to develop 

fields of similar sizes and at similar water depths, we 

felt that the particular configurations used in this 

study are representative of current practices in the 

Gulf of Mexico.

Development well, platform, and processing 

equipment configurations for newly discovered oil 

fields and for newly discovered nonassociated gas fields 

are presented in tables Al and A2, respectively. The 

configurations were designed to allow for a degree of 

expected excess capacity (in terms of platform slots and 

processing equipment capacity) that generally prevails 

in Gulf of Mexico production practices. As indicated by 

these tables, in cases where water depths were greater 

than 300 feet, the minimum platform costs were the 

same as costs associated with a 12-slot platform at that 

particular water depth, even though a platform of less 

than 12 slots would actually be constructed. The minimum amount of steel and the number of pilings required for operation of the smaller platforms at these 

water depths would be approximately equal to the 

amounts used in fabrication of a 12-slot platform.

TABLE Al. Development well, platform, and processing equipment 

configurations for new oil fields in the Gulf of Mexico

Field Platform 

size Number of size 

classes wells (slots)

7 _____

9 _______

10

11 _______

19

13 _____

14 _______

15 _____

16 ____

17

18 

19 _____

20 

0

0

3

4

5

7

9

14

20

33

KK

82

163

303

121 , 4

12l,4

121 , 4

1O1 A

121 , 6

191 Q

12

18

12

12

19

12

12

12

Processing equipment 

capacity

Gas 

(106 ftfVd)

15

15

15

OK

50

en

100

100

100

100

100

100

100

100

Liquids Number of platforms 

(bbl/d) and equipment package

300

300

300

KKf\

1,000

1,000

2,500

2,500

2,500

2,500

2,500

2,500

2,500

2,500

1

1

1

1

1

1

1

1

2

3

8

16

32

TABLE A2. Development well, platform, and processing

equipment configurations for new nonassociated gas fields

in the Gulf of Mexico

1 For water depths greater than 300 feet, 12-slot platform costs were used.

Table A3 presents the particular platform fabrication 

and installation costs that were used in this study. 

Estimates of platform operating costs (also used in this 

study) are presented in table A4.

The cost of drilling exploratory and development 

wells offshore was estimated with data supplied by 

industry sources. Components of drilling and wellcompletion costs were classified as either a time-sensiField 

size 

classes

7 _______

8 ______

-LV/

11

12 ______ 

13 _____

1*i

16

17 _____ 

18 

1Q

90

"For water dep

Number of 

wells

2 

3 

3 

5 

8 

13 

23 

40 

68 

117 

201 

343 

599 

1,022

Platform 

size 

(slots)

121 , 4 

12l , 4 

121 , 4 

121 , 6 

121 , 9 

18 

24 

24 

24 

24 

42 

40 

42 

36

Processing equipment 

capacity

Liquids 

(bbVd)

1,500 

1,500 

2,500 

2,500 

2,500 

5,000 

10,000 

10,000 

10,000 

10,000 

20,000 

20,000 

20,000 

20,000

ths greater than 300 feet, 12-slot

Associated gas 

(106 ftVd)

10 

10 

15 

15

25 

60 

60 

60 

60 

120 

120 

120 

120

Number of platforms 

and equipment package

1 

1 

1 

1 

1 

1 

1

2 

3 

5 

5 

9 

15 

30

platform costs were used.

tive cost or a cost fixed for a given drilling depth. Costs 

for all wildcat wells and dry development wells did not

TABLE A3. Estimates of platform fabrication and installation costs 

(size vs. water depth) for the Gulf of Mexico (in millions of dollars, 

costs as of 1981)

Platform 

size

4-slot 

6-slot 

9-slot 

12-slot 

18-slot 

24-slot 

36-slot 

4.9 «lnt

Water depths (feet)

40 150 317 525

3.645 4.313 NA NA 

3.893 4.900 NA NA 

4.536 5.778 NA NA 

5.179 6.657 11.763 24.009 

6.464 8.414 14.330 27.978 

7.749 10.171 16.897 31.947 

10.320 13.686 22.032 39.884 

11.177 14.858 23.743 42.530 

11.606 15.443 24.599 43.853

'NA = not applicable.

17
18 FUTURE SUPPLY OF OIL AND GAS FROM THE GULF OF MEXICO

TABLE A4. Estimates of platform operating costs (size vs. water 

depth) in the Gulf of Mexico (in millions of dollars; costs as of 1981)

_. _ Water depths (feet) Platform

size 40 150 317 525

4-slot 2.292 2.301 NA NA 

6-slot 2.340 2.352 NA NA

9-slot 2.411 2.430 NA NA

12-Qlnt 9 4ft9 9^07 9 fiO3 9 ftl 7

18-slot 2.624 2.662 2.806 3.127

94 csl/vf O 1RR O Q1 7 Q DDQ Q A Q7

36-slot 3.050 3.127 3.414 4.057 

40-slot 3.145 3.231 3.549 4.264

42-slot 3.193 3.282 3.617 4.367

include completion costs. The charges in table A5 also 

should have added to them the costs of the contract 

drilling rigs. Daily rates for various kinds of drilling 

rigs are presented in table A6. 

Field development time profiles are described in 

table A7. While these scenarios may not be followed by 

all operators, they were considered reasonable in light 

of industry and market conditions in 1981. It was 

assumed that approximately 90 percent of the development wells for fields larger than class- 13 oil and 

class- 14 gas would be drilled by using platform drilling 

rigs and that the rest of the development wells would

>NA = not applicable. be drilled by mobil rigs. 

TABLE A5. Drilling costs and completion costs for the Gulf of Mexico

[Daily rates and fixed charges exclusive of drilling rig costs for drilling well at 11,500 feet. Costs in 1981 dollars]

Drilling costs

Time sensitive costs Costs per day

MuH 3 9 c>fl

Wat6r 100

Dispatch 400

Rrtafo Q OCfi

Truck 100

fl^TTi^nl" r»tVMJi7 QP\fi

Rentals: 

Mud cleaner 200 

Shock sub 200 

Stabilizer 450

Othpr * Qfin

Total $15,000

Fixed cost items Costs per day

Mud logging $155,000 

Drive pipe 30 ,000

Surfacing casing, conductor, 

intermediate casing 375,000

Total $700,000

Well completion costs

Time sensitive costs Costs per day

TTiiolc $ 1 650

Boats 2 000

Water 100

rti cnn trVi 400

Total $4,150

Fixed cost items Costs per day

Production facilities (including packers) $100,000 

Perforating 30,000

PrnHiir>tinn rasincr 300 000

WollVioarl _ AK. 000

Total $625,000

TABLE A6. Daily rates for various types of drilling rigs according 

to water depth (costs as of 1981)

Rated water depth, 

in feet Type of rig Daily rate

40 .Tnrlr nn $25 000

150 Jack-up $35,000

3171 Jack-up $40,000 

3171 Semisubmersible $58,000 

525 Semisubmersible $58,000 

Platform rigs: 

All modular2 $16,000

All Ipnnfrncr3 $14000

'At 317 feet of water depth, 40 percent of wells were assumed to be drilled by jack-up rigs, 

and 60 percent of wells were drilled by Semisubmersible rigs.

'Set-up costs included 7 days of barge time at $455,000 and 14 days of rig time at $224,000. 

3Set-up costs include 24 days of rig time at $210,000.
APPENDIX A 

TABLE A7. Development strategies: Drilling and production schedules

19

I. Classes 5-9: Smaller than class 10 for both oil and gas; it is assumed that the development takes place within 1 year and, for accounting 

purposes, drilling and production are almost instantaneous. Some of early project costs are adjusted to correct for this assumption.

II. Classes 10 and 11 (oil) and classes 10,11,12 (gas): All drilling and platform expenditures occur during year 1, and production begins in 

year 2 (class 12 gas same as above).

III. Classes 12, 13, and 14 (oil) and classes 13, 14, 15, and 16 (gas): 

Expenditures

% cost item 

Drilling 

Platform 

Processing equipment

Revenue stream

% of total wells coming into production

Year

1

50

50

50

0

2

50

50

50

50

3

50

IV. Classes 15 and 16 (oil); and classes 17, 18, and 19 (gas):

Expenditures: 

% cost item

Drilling

Platform

Processing equipment

Revenue stream

% of total wells coming into production

V. Class 17 (oil) and class 20 (gas):

Expenditures 

% cost item

Drilling

Platform

Processing equipment

Revenue stream

% of total wells coming into production

VI. Classes 18, 19, and 20 (oil):

Expenditures 

% cost item

Drilling

Platform

Processing equipment

Revenue stream

% of total wells coming into production

Year

1

40

40

40

0

2

35

35

35

30

3

25

25

25

45

4

25

Year

1

35

35

35

0

2

35

35

35

20

3

20

20

20

30

4

10

10

10

40

5

10

Year

1

20

20

20

0

2

30

30

30

15

3

30

30

30

25

4

15

15

15

25

5

5

5

5

25

6

10

'Exploratory wells assumed to be drilled since December 31,1976. The stopping rule for exploratory wells 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.

'At the margin, the sum of the marginal finding cost and the marginal production cost is equal to the output 

price (column 1).
APPENDIX B. OIL AND NONASSOCIATED GAS 

WELL PRODUCTION SCHEDULES

Oil and nonassociated gas well production schedules 

were developed by the Dallas Field Office of the U.S. 

Department of Energy for another study. The following 

is a description of the equations used in the generation 

of the production schedules (John Wood, U.S. Department of Energy, written commun., 1979).

Oil well schedules. Wells that represent field size 

classes of larger than 10 are assumed to produce at a 

constant rate for a period of time. Wells representing 

size classes of fields smaller than class 11 are assumed 

to decline immediately according to a hyperbolic function. The following variables are defined:

t = current time period,

q0 = initial well production rate,

Np(t) = cumulative oil production to time t in

barrels, 

Gp(t) = cumulative associated gas production in

thousands of cubic feet, 

Nu = expected ultimate per well oil recovery in

barrels,

D = exponential decline rate, 

td = deliverability life in years, 

qa = nominal 1978 offshore abandonment rate of

9,125 barrels per year or 25 barrels per

day, 

g = gas-to-oil ratio in thousands of cubic feet

per barrel,

ap(t) = annual oil production, 

ag(f) = annual associated gas production.

For fields in size classes 7 through 20:

Nu+qa

"° fc+Cl/D) 

Ift<td, then Np(f)=t(q0l Otherwise

D

Annual oil production is ap(t)=Np(t)-Np(t-l), and annual gas production is ag(t)=g ap(t).

Values of parameters associated with each size class 

field are presented in Table Bl.

Nonassociated gas production schedules. Gas deliverability was computed on a well basis by number of 

wells per field using the computer program developed 

by J. N. Hicks (Dallas Field Office, Department of 

Energy, 1976). Initial gas rates were based on 25 percent of initial open flow production, except in class 20 

where 24 percent was used. The predictive equation for 

generating future nonassociated gas production prior 

to the production decline is Gp(t)=tdqg. With the onset 

of decline, the predictive equation is

where Gp(f) is cumulative gas production to time t in 

million cubic feet, td is the period of constant production, qc is the initial constant gas production rate in 

millions of cubic feet per year, qg is the initial gas production rate in millions of cubic feet per year for the 

decline curve, a is the initial loss ratio, and b is the 

first derivative (with respect to time) of the loss ratio (b 

is dimensionless). Values for the parameters associated 

with each size class field are presented in Table B2.

TABLE Bl. Oil production schedule constants for Texas and 

Louisiana offshore oil fields by size class

[Nu is expected ultimate per well oil recovery in barrels; D is the exponential decline rate; td 

is deliverability life in years]

Size 

class

7

g

g ___________

10 ___________

11 ___________

12

13 

14 ___________

15 ___________

16 

17

lg ___________

19 ___________

20 _______

N

111,000

1 rjo AAA

270,000

387,000

466,000

545,000

637,000

744,000

870,000

1,020,000

1 1 on nnn

1,390,000

1,620,000

1,900,000

D

0.340

0.310

0.286

0.266

0.251

A OOQ

0.227

0.217

0.209

0.202

0.195

0.190

0.185

0.180

td

0

0

0

0

0.5

1.0

1.5

2.0

2.5

3.0

q c

4.0

4.5

5.0

Gas/oil 

ratio 

(bbl/mcfl

1 q

1 R

1.8

1.7

1.7

1.7

1.6

1.6

1.6

1.5

1.5

1.5

1.4

1.4

20
FUTURE SUPPLY OF OIL AND GAS FROM THE GULF OF MEXICO 

TABLE B2. Nonassociated gas production equation parameters

[trf is the period of constant production, in years; qc is the initial constant gas production 

rate, in millions of cubic feet per year; <?~ is the initial gas production rate, in millions of 

cubic feet per year, for the decline curve; a is the initial loss ratio; 6 is the first derivative 

of the loss ratio]

21

Size 

class

7

g

9

10

11

12 ___________

13 ___________

14 ___________

15 ___________

lg ___________

17 ___________

lg ___________

19 ___________

20

*d

0.43

f\ CO

0 Q

i 07

1.71

2.25

2.86

3.52

4.17

4.76

5.25

5.57

5.70

6.04

1c

coo A etc

1 1 70 qc

1 O£C 1

1551.25

1 7^,9 ft

1956.4

2168.1

2383.45

2606.1

2839.7

3076.95

3321.5

3569.7

3686.5

ig

CQQ An

1 1Q9. Q

1QQO C

000*7 Q£

1QCA 7C

1790.69

2118.77

2441.6

2487.96

2937.58

3129.78

3353.54

3593.25

3710.69

a

0.748033

A rr A OAOO

0

7/1 ftAOO

0

74QAOO

1 9°.7ft°.

1.83560

2.61138

2.62474

4.62321

3.90549

4.67399

5.34045

6.02773

6.27156

6

0

1 OAQC

0 1 OAQC

0

1 OAQC

0

1 OAQC

0

1 ee£*£*

-0.15641

-0.20523

-0.0485

-0.21428

-0.05787

-0.08371

-0.10133

-0.11818

-0.23789

6U.S. GOVERNMENT PRINTING OFFICE: 1983-381-419/115